PIPELINE MANUAL
CHEVRON RESEARCH AND TECHNOLOGY COMPANY RICHMOND, CA
November 1994
Manual sponsor:
For information or help regarding this manual, contact T. (Tim) Sheckler (510) 242-2298
Printing History Pipeline Manual First Edition First Revision Second Revision Third Revision Fourth Revision
November 1989 January 1990 January 1991 May 1993 November 1994
Restricted Material Technical Memorandum This material is transmitted subject to the Export Control Laws of the United States Department of Commerce for technical data. Furthermore, you hereby assure us that the material transmitted herewith shall not be exported or re-exported by you in violation of these export controls.
The information in this Manual has been jointly developed by Chevron Corporation and its Operating Companies. The Manual has been written to assist Chevron personnel in their work; as such, it may be interpreted and used as seen fit by operating management. Copyright 1988, 1990, 1991, 1993, 1994 CHEVRON CORPORATION. All rights reserved. This document contains proprietary information for use by Chevron Corporation, its subsidiaries, and affiliates. All other uses require written permission.
November 1994
Chevron Corporation
List of Current Pages Pipeline Manual The following list shows publication or revision dates for the contents of this manual. To verify that your manual contains current material, check the sections in question with the list below. If your copy is not current, contact the Technical Standards Team, Chevron Research and Technology Company, Richmond, CA (510) 242-7241.
Section Front Matter Table of Contents References Section 50 Section 100 Section 200 Section 300 Section 400 Section 500 Section 600 Section 700 Section 800 Section 900 Section 1000 Section 2000
Date November 1994 November 1994 November 1994 November 1994 November 1988 November 1988 November 1994 November 1994 November 1988 November 1988 November 1994 November 1988 November 1994 May 1993 November 1994
Company Specifications PPL-MS-1050-H PPL-MS-1564-D PPL-MS-1632-E PPL-MS-1800-G PPL-MS-4041-B PPL-MS-4737-A PPL-MS-4807
May 1993 January 1990 November 1988 November 1990 May 1993 November 1994 January 1990
Data Sheets PPL-DS-4737 PPL-DS-1050
Chevron Corporation
November 1994 May 1993
November 1994
Section PPL-DS-4041 PPL-DS-4807 All other Data Sheets
Date May 1993 January 1990 November 1988
Data Sheet Guides PPL-DG-1050 PPL-DG-4041 PPL-DG-4807
November 1994 November 1994 January 1990
All other Data Sheet Guides
November 1988
Standard Drawings and Forms
All specifications, drawings, and forms are marked with thier latest revision dates.
GE-L99880
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Appendix A Appendix B Appendix C Appendix D Appendix E Appendix F Appendix G Appendix H Appendix I
November 1988 November 1988 November 1988 November 1988 November 1988 November 1988 November 1988 January 1990 November 1994
1 PC Disk Disk(s) Information Sheet
November 1994 November 1994
Maintaining This Manual Pipeline Manual If you have moved or you want to change the distribution of this manual, use the form below. Once you have completed the information, fold, staple, and send by company mail. You can also FAX your change to (510) 242-2157. ❑ Change addressee as shown below. ❑ Replace manual owner with name below. ❑ Remove the name shown below. Previous Owner:
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Send this completed form to: Document Control, Room 50-4328 Chevron Research and Technology Company 100 Chevron Way (P.O. Box 1627) Richmond, CA 94802
CRTC Consultants Card The Chevron Research and Technology Company (CRTC) is a full-service, in-house engineering organization. CRTC periodically publishes a Consultants Card listing primary contacts in the CRTC specialty divisions. To order a Consultants Card, contact Ken Wasilchin of the CRTC Technical Standards Team at (510) 242-7241, or email him at “KWAS.”
Chevron Corporation
November 1994
Reader Response Form Pipeline Manual We are very interested in comments and suggestions for improving this manual and keeping it up to date. Please use this form to suggest changes; notify us of errors or inaccuracies; provide information that reflects changing technology; or submit material (drawings, specifications, procedures, etc.) that should be considered for inclusion. Feel free to include photocopies of page(s) you have comments about. All suggestions will be reviewed as part of the update cycle for the next revision of this manual. Send your comments to:
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Document Control, Room 50-4328 Chevron Research and Technology Company 100 Chevron Way (P.O.Box 1627) Richmond, CA 94802 Comments
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Chevron Corporation
November 1994
Pipeline Manual Sponsor: G. B. Kohut / (510) 242-3245 / E-mail:
[email protected] This document contains extensive hyperlinks to figures and cross-referenced sections. The pointer will change to a pointing finger when positioned over text which contains a link.
List of Current Pages 50
Using This Manual
50-1
100
General Information
100-1
200
Route Selection
200-1
300
Pipe and Coatings
300-1
400
Design
400-1
500
SCADA Systems
500-1
600
Construction
600-1
700
Inspection and Testing
700-1
800
Operations and Maintenance
800-1
900
Offshore
900-1
1000
Guidelines for Low Pressure Buried Fiberglass Pipe
1000-1
Appendices Appendix A Appendix B Appendix C Appendix D Appendix E Appendix F Appendix G Appendix H Appendix I
Conversion Tables Directional Drilling Offshore Pipelines Operating Plan Guidelines Field Inspection Guidelines Development of Depth of Burial Diagrams Subsea Valves Guidelines for Weight-Coating on Submerged Pipelines Calculation of Bending Stress in Buried Pressurized Pipeline Due to External Loads
References
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50
Using This Manual Abstract This section tells you how this manual is organized. A Quick-Reference Guide (Figure 50-1) is provided to highlight key areas of the manual. A cross-reference chart (Figure 50-2) relates the manual to others in the set.
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50 Using This Manual
Pipeline Manual
Scope and Application The Pipeline Manual, written for convenient reference by Company personnel engaged in technical work on pipelines, is directed to technical personnel regardless of experience. This manual should never substitute for sound engineering judgment. This manual contains guidelines and specifications for use by Company personnel. The material may be used as is, or modified for local organizational or geographic preferences, priorities, or experiences. The intent is to provide practical, useful information based on Company experience. Therefore, forms have been included in the front of the manual for your convenience in suggesting changes. Your input and experience are important for improving subsequent printings and keeping this manual up-to-date.
Organization The Pipeline Manual is part of a set of manuals produced by Chevron Research & Technology Company in cooperation with all Operating Companies in the Corporation. Several of these manuals contain information directly related to pipelines. • • • • • •
Piping Insulation and Refractories Fluid Flow Instrumentation and Control Coatings Corrosion Prevention Welding
All the manuals are interrelated; therefore, a list of cross references (at the end of this section.) has been developed to assist you in finding related subject matter. The index also aids in locating information in other manuals. Each manual is organized using different-colored tabs to assist users in finding the appropriate information quickly:
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•
White tabs are for table of contents, introduction, appendices, PC disks, index and general purpose topics.
•
Blue tabs denote Engineering Guidelines.
•
Gray tabs denote Specifications, Data Sheets, Data Sheet Guides, and related industry standards (API, ANSI).
•
A Red tab marks a place for you to keep documents developed by your organization.
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50 Using This Manual
Part I - Engineering Guidelines This part of the manual contains: (1) material selection guidelines; (2) design principles and Corporation suggested practices; (3) construction techniques; (4) inspection criteria; (5) operational information.
Part II - Specifications This part of the manual contains: (1) general instructions for using specifications; (2) model specifications, data sheets, and data sheet instructions that can be copied or modified to local preferences; and, (3) industry standards (API, ANSI). Change Bars, vertical black lines, have been used in the margins of the master specifications to indicate where information has been added, changed, or deleted in reference to the last edition of the manual.
Other Company Manuals The text sometimes refers to documents in other Company manuals. These documents carry the prefix of that manual. The prefixes are defined here: Prefix CIV CMP COM CPM DRI ELC EXH FFM FPM HTR ICM IRM MAC NCM PIM PMP PPL PVM TAM UTL WEM
Chevron Corporation
Company Manual Civil and Structural Compressor Coatings Corrosion Prevention Driver Electrical Exchangers and Cooling Towers Fluid Flow Fire Protection Manual Fired Heaters and Waste Heat Recovery Instrumentation and Control Insulation and Refractory General Machinery Noise Control Piping Pump Pipeline Pressure Vessel Tank Utilities Welding
50-3
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50 Using This Manual
Fig. 50-1
Pipeline Manual
Quick Reference Guide
Task
Pipeline Manual Sections
Learn background information •
Hydraulics
400
•
Design
200, 300, 400, 500, 600, 900
•
Offshore
900
Specifying and purchasing •
Line pipe
300, 2000
•
Induction bends
300, 2000
•
Cement-lined pipe
300, 2000
Troubleshooting •
Hot-tapping
800
•
Hydrates
800
Developing a Purchase Specification
Model Specifications, Specification disk
Filling Out a Data Sheet
Data Sheet Guides
Selecting the Best •
Line pipe
310, 400
•
Pipeline route
200
•
SCADA system
500
•
Coating
340, 350, 440
Selecting appropriate inspection and testing for pipelines
700
Selecting appropriate inspection and testing for line pipe
300, 700, Data Sheet Guides
Locating information related to pipelines (components, coatings, welding, insulation)
See Cross-Reference List
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Fig. 50-2
50 Using This Manual
Manuals Cross Reference Chart (1 of 2) PPL
Abandonment
X
Anchors
X
PIM
FFM
COM
CPM
X
X
WEM
IRM
ICM
X
Coatings External
X
Insulation
X
Internal
X
Selection Chart
X
Weight
X
X
Components API 5L Line Pipe
X
ASTM A106 Pipe
X
Instruments
X
Insulation
X
Valves and Fittings Computer Programs
X
X
X
X
Construction Cathodic Protection
X
Coating
X
X
X
Inspection
X
X
X
Offshore Methods
X
X
X
Testing
X
X
X
Welding
X
X
X
X X
Design ANSI/ASME B31.3
X
ANSI/ASME B31.4 ANSI/ASME B31.8
X
Hot Oil
X
X
Metering Pipeline
X X
Plant Piping SCADA
X X
Expansion
X
X
Hot Tapping
X
X
Chevron Corporation
X
50-5
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Fig. 50-2
Pipeline Manual
Manuals Cross Reference Chart (2 of 2) PPL
PIM
Hydraulic Calculations
X
X
Inspection and Testing
X
FFM
COM
CPM
WEM
IRM
ICM
Installation Crossings
X
Pipeline
X
Plant Piping Pipe Cleaning
X X
X
Plant Piping
X
Pulsation Control (Surge)
X
Row Cleanup
X
Specifications C.S. Piping Fabrication
X
Cement-Lined Pipe
X
External FBE Coating Induction Bonding
X X
Internal Coating Tubular
X
Insulation Line Pipe
X X
Pressure Testing of Plant Piping
X
Radiography
X
Sour Line Pipe
X
Startup
X
Surveying
X
Troubleshooting
X
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100 General Information Abstract The Pipeline Manual is a guide for the basic design and construction of pipeline systems. It focuses on design fundamentals, guidelines for practical installations, and specification and purchase of materials and services. It is applicable to small gathering pipelines, large transmission pipeline systems and offshore pipelines. Its guidelines encompass the experience of the Corporation’s Operating Companies. The manual’s broad applicability makes it useful to both engineers and operating personnel. The Pipeline Manual is concerned only with pipelines. It does not provide design information for pump stations, compressor stations or tank terminals, even though these facilities may be covered by the pipeline design codes. The manual includes certain topics related to operations and maintenance, but not a comprehensive description of these functions. The Pipeline Manual organizes in one place much of the Company’s information on pipelines, presented in guideline form. It includes Company specifications which are easily used by any Operating Company. Industry standards are also included. For some subjects it advises reference to the more complete discussions in other ETD manuals.
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Page
110
Contents
100-2
120
Code Compliance
100-2
130
Legal Requirements
100-3
140
Engineering Judgment
100-4
150
Mandatory and Recommended Practice
100-4
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110 Contents The Pipeline Manual is organized into two parts:
Part I - Engineering Guidelines •
Section 100 provides a road map for the entire manual, and background information on engineering style.
•
Section 200 describes how to select a pipeline route.
•
Section 300 describes the selection of the physical parts of a pipeline: the pipe, components and coating.
•
Section 400 explains pipeline design and the Company’s preferred methods.
•
Section 500 tells how to monitor your pipeline system by using SCADA systems.
•
Section 600 discusses pipeline construction activities and contracting.
•
Section 700 tells you how to ensure a good product through careful inspection and testing.
•
Section 800 explains some operations and maintenance considerations that help produce practical designs.
•
Section 900 covers the subject of offshore pipeline design and construction, discussing the differences and recapitulating the similarities between onshore and offshore pipelines.
Part II - Specifications •
Section 2000 introduces the Specifications part of the manual and tells you how to use the documents contained there.
•
The Company Specifications section contains model format specifications with comments and their corresponding data sheets.
•
The Standard Forms and Drawings section contains forms and drawings that pertain to the pipeline guidelines in this manual.
•
The Industry Codes and Practices section provides the industry specifications and practices that the Guidelines and Company Specifications reference.
•
The Appendices provide references, conversion tables, sample specifications, sample guidelines, and background design calculations.
120 Code Compliance The various pipeline codes (such as ANSI/ASME Codes B31.4 and B31.8 in the United States) contain practices necessary for safe pipeline systems, but are not intended to be complete specifications for all phases of design. The Company recognizes this fact, and the guidelines and specifications in this manual provide the
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supplemental requirements normally needed to obtain economical systems for basic fluid services. A few requirements—where experience has shown them to be better choices—are more stringent than code minimums. Engineers responsible for design and construction of pipelines are expected to be familiar with and to comply with the appropriate codes even though some of their provisions may not be specifically included in this manual.
130 Legal Requirements In general, pipelines which conform with ANSI/ASME Codes B31.4 and B31.8 will meet the legal requirements in the USA for gas and liquid pipelines and facilities such as pump stations and compressor stations. See Section 400 for elaboration. In the United States, the Occupational Safety and Health Act (OSHA) is mandatory. Other countries have similar legislation. For general petroleum industry piping, the major effect of OSHA is on construction safety and to forbid the use of regular cast iron for flammable or combustible liquids having a flash temperature below 200°F or a temperature within 30°F of their flash temperature. Steel, ductile cast iron or malleable cast iron are required. The details of OSHA regulations are still changing, and the most recent revision should be reviewed where the economic effect of this requirement is considerable. Pipeline activities in Canada are governed by the CAN3-Z183 and CAN/CSA-Z184 pipeline codes, and the CAN3-Z245 line pipe code. Some states and localities in the United States have adopted some sections of ANSI/ASME Code B31; however, it is not a legal requirement in most states. OSHA regulations strongly encourage use of Code B31 by stating that compliance with Code B31 and specific OSHA rules is prime facie evidence of compliance with OSHA basic requirements. The United States Code of Federal Regulations, Title 49, Part 192 and Part 195 (49 CFR 192 and 195) cover interstate and continental shelf oil piping and essentially all gas transportation piping. They define the minimum design requirements for oil and gas pipelines. Pipelines regulated by 49 CFR 192 and 195 are the responsibility of the Department of Transportation (DOT). 49 CFR 192 does not incorporate Code B31.8 by reference, while 49 CFR 195 does incorporate Code B31.4 by reference. However, Codes B31.4 and B31.8 contain supplemental design information and their use is recommended. In case of conflict, the applicable part of 49 CFR will govern. The United States Code of Federal Regulations, Title 30 Part 250 (30 CFR 250) covers oil, gas, and sulfur operators in the continental shelf. Pipelines regulated by 30 CFR 250 are the responsibility of the Department of the Interior (DOI). 30 CFR 250 covers flowlines, platforms, separation facilities, pumps, and compressors upstream of the first flange on the sales pipeline, which is usually a DOT responsibility pipeline. See Section 900 for explanation. Engineers responsible for design and construction of pipelines in the United States are expected to determine which codes are legally required and if there are any other federal, state, or local regulations governing such construction. The Company
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requires compliance with the most stringent practice. For installations outside the United States and Canada, the engineer responsible for piping design and construction should determine if there are national and local regulations pertaining to piping design. The ANSI/ASME codes remain good guidelines where no other regulations exist.
140 Engineering Judgment The use of these Guidelines does not eliminate the need for sound engineering judgment. A few examples of special cases that are not covered by these guidelines and that should be given special consideration are: •
Extraordinary service conditions such as earthquake, high wind, other unusual dynamic loadings, or unusual superimposed dead loads
•
Cold climates that may require special materials to avoid brittle fractures
•
High H2S concentrations that may place restrictions on valve trim and weld hardness
•
Consider upgrading of Class 150 flanges to Class 300 flanges where frequent blinding is required
It is necessary that the user of this manual realize that its use does not release him from his responsibility to use sound judgment in the selection of materials, fittings, valves, and other piping items to meet safety and economic considerations. No attempt has been made to provide for all the in-between or gray areas. Some examples of areas where variations could apply: •
Use of lighter wall pipe for low pressure systems
•
Use of higher yield strength materials when economics dictate
•
Variation in corrosion allowance or selection of material for handling of corrosive/erosive material
150 Mandatory and Recommended Practice For the most part, this manual covers RECOMMENDED practice. However, certain codes govern some activities and require that the design and materials conform to a specific standard. These codes are therefore mandatory. MANDATORY in this context means that the engineer and/or operating personnel selecting equipment must conform to the selections as required by the governing code in order to meet minimum safety standards and government requirements. The following definitions also apply throughout this manual: SHALL and IS REQUIRED mean mandatory per code and/or Company requirements.
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SHOULD means advisory guidelines that are to be adhered to where no overriding objections are apparent. An advisory guideline represents a design which is applicable in most cases and represents the experience and expertise of the Company. PREFERRED and RECOMMENDED mean guide-lines which are generally and successfully used within the Company, but there are other choices and methods which are acceptable. MAY means acceptable or permitted options. The above definitions are the same as those used in the Company’s Safety-inDesigns Manual.
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200 Route Selection Abstract This section focuses on the route selection decisions and activities that occur at the beginning of a pipeline project and influence the character of the entire project. Issues covered include preliminary route selection, project planning, regulatory and jurisdictional research, surface considerations, environmental and technical surveys, and final alignment and surveying. Careful and complete project planning minimizes project cost and duration. This section was developed with a large crosscountry pipeline in mind, but most of the concepts can also be applied to smaller jobs and offshore pipelines.
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Contents
Page
210
Preliminary Route Selection
200-3
211
Hydraulic Profiles and Pump Station Locations
212
Input on Right-of-Way and Permitting Procedures
220
Project Planning
200-4
230
Jurisdiction, Permitting, and Rights-of-Way
200-6
231
Governmental Jurisdictions
232
Land Jurisdictions
233
Permitting
234
Private Right-of-Way Acquisition
240
Surface Considerations
241
Surface Conditions
242
Environmental Surveys
243
Technical Surveys
250
Alignment, Surveying, and Mapping
251
Published Maps and Aerial Photography
252
Surveying and Mapping Services
253
Aerial Photography and Photogrammetry
254
Field Surveying and Mapping
200-1
200-9
200-11
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255
Route Alignment Sheets and Design Drawings
256
Special Survey Systems
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210 Preliminary Route Selection Preliminary route selection involves applying common-sense engineering to the problem of identifying reasonable deviations from a straight line between points A and B. These deviations are dictated by the need for an economic route and by the requirements of permitting agencies. Suitable maps are required to select a route and to determine the length of the pipeline; these should show contour lines, rivers, roads, railroads, towns, existing pipelines, and other topographic features. For long cross-country pipelines a World Aeronautical Chart is very useful. These are readily available for most parts of the world. For lines in the United States, U.S. Geological Survey maps of an appropriate scale give more detail, and are especially useful for shorter lines and critical areas. Aerial photographs, if available, also show certain topographic details. Common-sense reasons to deviate from the straight line include the following: •
To avoid significant natural obstacles such as mountains, rock, swamps, unnecessary river crossings, etc., and to select favorable locations for crossing mountain ranges, rivers, etc. However, extensive deviation to avoid difficult terrain should be evaluated to determine whether the lower construction cost per mile offsets the added length of line and the probable higher pumping costs
•
To avoid developed areas such as towns, industrial areas, residential areas, intensive cultivation, etc., where right-of-way, construction, and construction damage costs will be high
•
To minimize control points in hydraulic profiles. See the discussion of hydraulic profiles in Sections 420 and 430 of this manual. Additional pumping power may be needed to overcome hydrostatic heads to clear control point elevations, particularly where the control point is near the end of the line or the inlet to a pump station
•
To improve access for pipeline construction material and equipment—as well as for operations and maintenance—by using existing roads, including unimproved roads adequate for pipe-hauling trucks
•
To avoid government-restricted or environmentally sensitive areas and to reduce right-of-way and construction damage costs, if the information on these areas is available when a preliminary route is initially being studied. This information should be developed concurrently and factored into the route selection process as soon as it is available (see Section 210). Depending on the nature and complexity of these considerations, either a single preliminary route will be the obvious selection, and steps to develop a final alignment can proceed, or one or more alternative routes will warrant evaluation. Route selection may be influenced by right-of-way and permitting conditions as well as economic comparison.
211 Hydraulic Profiles and Pump Station Locations Once an initial route has been identified, the ground profile should be plotted on cross-section paper, and a preliminary hydraulic profile should be developed using
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the method discussed in Section 420. This should also be done for any alternative routes under consideration. The hydraulic profile indicates approximate locations for intermediate pump stations for both initial and future design line throughput capacity. Pump station location may slightly influence final pipeline alignment, because of land availability, station access, electric power access, etc.
212 Input on Right-of-Way and Permitting Procedures Gathering of information on right-of-way and permitting procedures should proceed concurrently with route selection, preliminary engineering for line sizing, and cost estimates. This input is vital in developing the preliminary route that will be the basis for detailed engineering, acquisition of rights of way and permits, environmental and technical surveys, and final route alignment surveying. Besides those of the Company operating organization that the pipeline facility will serve, Company resources at this stage normally should include: • • • •
Engineering Land Governmental affairs Environmental affairs
These groups usually can offer pertinent background information on route selection and procedures involved in obtaining rights of way and permits, and can develop plans to identify the appropriate authorities involved in granting rights of way and permits. For a cross-country or offshore pipeline, early development of a schedule for permit applications and approvals, environmental and technical surveys to support these applications, right-of-way acquisition (including condemnations, etc.) is essential.
220 Project Planning Basic planning and coordination for all phases of the project should be initiated early in the project, so that project progress is not stalled by such road blocks as extended permit application procedures, changes in design basis, (such as line throughput forecast or fluid properties), prolonged permitting processes, right-ofway acquisition difficulties, pipe delivery delays, contracting surprises, and problems in staffing and equipping field forces. Project planning for a major pipeline should cover the following: •
Pre-appropriation request phase – – –
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Conceptual design and cost estimates, based on a reliable line throughput forecast and best available information on fluid properties Rheological testing, if needed to establish or confirm fluid properties Definition of procedures and arrangements for permit applications, environmental and technical surveys, and environmental impact studies, and
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– •
Project development of the approved project – – – – – – – – –
•
initiation of these surveys and studies as appropriate to meet permitting schedules Preparation of an Appropriation Request and economic analysis, and a Contracting Plan
Designs Acquisition of permits and rights of way, including finalizing environmental impact reports Procurement of construction materials Arrangements for temporary field facilities Further environmental and technical surveys Field alignment and property surveys Preparation of contract specifications and bidding papers Contract awards Project controls and reports
Construction and project completion: – – – – – – – –
Contract administration, field engineering and inspection, materials control Field contracting Field purchasing, if appropriate Project controls and reports Completion tests, dewatering, and turnover to the operating organization Construction damage claim settlements Documentation and reports to permitting authorities Record drawings for completed facilities
For offshore projects key elements of front-end engineering and detailed design development are indicated in Section 930, Figures 900-1 and 900-2. Many of these elements apply to onshore projects. Planning must also include staffing requirements for all phases of the project, development of personnel policies, arrangements for extended work weeks and travel and field expenses, arrangements for borrowed personnel, etc. See the guidelines on the field supervision organization in Section 670 of this manual, and on the typical field inspection organization in Section 790. Field support facilities must be carefully and realistically defined, so that offices, vehicles, and the communication system are ready and operational when needed. Mobility of field personnel and reliable communications are extremely important on a pipeline project. Field personnel are spread out geographically; they must be able to travel the route and to communicate with other field people and the construction office base at all times. Vehicles and the communications system must suit the terrain, and acquiring them often involves long lead times. With few exceptions four-wheel drive vehicles and two-way radios are necessary along the route, and key construction office personnel should have radio-equipped vehicles.
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A Project Contracting Plan is required by Corporation Policy 500 for large projects, and should be prepared for all projects to summarize intended contracts and timing. Dependent on contract scope and circumstances, contracts may cover: •
Front-end engineering, providing conceptual design, cost estimates, and preparation of specifications for detailed design, procurement and construction
•
Surveying and mapping, and environmental and technical surveys as needed for route selection, permitting, and design development
•
Specialist assistance for right-of-way and permit acquisition
•
Technical research and testing, as may be needed
•
Design and procurement, if not done in-house
•
Construction of the facilities, usually separately for the pipeline and for stations and terminals
•
Construction support services, including radiographic inspection, nondestructive testing, and hydrostatic test witnessing
•
Supplemental personnel
•
Temporary facilities and utilities
Contracting guidelines are included in the Construction and Services Contract Manual. The Contracts staff of the Engineering Technology Department can be consulted regarding types of contracts, contract forms, compensation items, and contractor performance. Also, see the discussion on construction and construction service contracts in Section 680 of the manual.
230 Jurisdiction, Permitting, and Rights-of-Way 231 Governmental Jurisdictions United States interstate and intrastate hazardous liquid and gas pipelines are federally regulated except in the case of intrastate pipelines where a state has adopted standards that are the same as or more stringent than the federal standards. Chevron Pipe Line Company’s Guide to Pipeline Safety Regulations provides the information needed to determine jurisdiction for pipelines. Chevron Pipe Line Company in San Francisco should be consulted for guidance on current federal and state regulations. The applicable federal regulations are contained in Code of Federal Regulations Title 49, Part 195 (49 CFR 195), for liquid lines and 49 CFR 191 and 192 for gas lines. Canada has comparable federal and provincial regulations, although the provinces have more central control over intraprovincial activities. Regulatory jurisdictions are further discussed in Sections 410 and 910 of this manual.
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232 Land Jurisdictions Except for production flow and gathering lines lying entirely within Company property, a cross-country pipeline traverses either privately owned lands or agencyadministered lands under municipal, county, state or federal government jurisdiction. County records offices are the best source of ownership information and addresses for owners and agencies. In general, permits or agreements for construction and operation of a pipeline system are granted by government agencies or owners of existing crossed facilities, such as highways, roads, railroads, canals, pipelines, and power and telephone lines. Rights-of-way, on the other hand, are needed to enter privately-owned lands for construction and maintenance of a pipeline.
233 Permitting Permitting procedure and timing must be determined for each governmental agency and owner of an existing crossed facility. These will vary from agency to agency, and not infrequently from time to time for the same agency. This information must be developed as soon as possible so that priorities can be given to permitting procedures that take the most time, or where sequential permit approvals are dependent on prior approval by other agencies. Permitting authorities should be contacted at an early stage regarding anticipated permit conditions and requirements affecting construction, so that these can be incorporated into construction specifications before inviting bids. In the U.S., preparation, review and approval of an Environmental Impact Report (EIR) is now required for nearly all cross-county pipelines. Under guidelines of the National Environmental Policy Act (NEPA), the EIR process can add over a year to the project schedule. Project timing and funding must allow for this. A number of governmental agencies are likely to be involved in the EIR process, in addition to the one(s) with jurisdiction over the land which the line traverses. One agency is assigned as the lead agency, and has the responsibility for coordinating the others and for conducting the public hearing and response process. The EIR requires significant front end engineering to thoroughly cover the proposed construction, since, once approved, permit conditions and mitigation measures cannot be changed. Preparation of the EIR, along with required surveys and the review, takes time. Scheduling should make realistic allowances for this process, and every effort should be made to keep the process on schedule. Environmental and technical surveys are discussed in Section 240. Requirements for supplemental documentation, such as a construction operating plan, copy of the construction specification, etc., should be determined for each permitting authority. All permits should be obtained before starting construction, since unforseen delay in granting a permit after construction starts will interrupt work and lead to high standby charges. In some cases permitting authorities will issue a letter giving approval to proceed pending formal execution of the permit.
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A Company land department is normally assigned responsibility for permit applications by the pipeline operating organization, coordinating with governmental affairs, environmental affairs and engineering organizations. Close coordination between these groups is essential, both for exchange of information and to assure that responsibilities for action by the various groups are clearly defined.
234 Private Right-of-Way Acquisition A typical right-of-way document is in a form prepared by the Company, by which a private land owner gives the Company, for a consideration, the right to construct and maintain one or several pipelines within a specified width across the property, with reasonable access over the property to the lines. In some right-of-way agreements for undeveloped lands the location of the right-of-way may be defined by the center-line of the first pipeline laid, but usual practice is to legally describe the route on the property. Usually the width of the right-of-way is less than the working strip needed for construction of the line, but the negotiated right of access allows the Company to use the additional width needed for construction. A right-of-way agreement is negotiated with each property owner. Payments for rights-of-way are, preferably, uniform for all owners. However, adjustments are usually necessary, depending on differing land values and difficulties in negotiating with particular owners. If a landowner adamantly refuses to grant a right-of-way, common carrier pipeline companies may use the right of eminent domain to obtain the right-of-way by taking legal action. The conditions for and duration of this legal process vary from state to state. In many cases additional special conditions for the particular property are incorporated in the right-of-way agreement. Where these special conditions affect construction, they should be summarized in a sequential list according to their occurrence along the route. This information should be distributed to Company field personnel and contractor supervisory personnel so that construction meets the special conditions, for instance, extra depth of cover, protection of water aquifers and springs, protection of vegetation, specified seed mixtures for revegetation of rangeland. Payment for damages to the property resulting from construction and maintenance of a pipeline is separate from payment for the right-of-way, although in some cases costs for damages can be agreed in advance of construction, and damage payment is made at the same time as payment for the right-of-way. Construction damages include damages both within the specified width defined in the right-of-way agreement and on the construction working strip outside the right-of-way width, and any other damage to the property as a consequence of pipeline construction activities. Where damages result from unnecessary and avoidable acts by the contractor, a method to allocate such costs to the contractor or by which the contractor settles directly with the landowner or tenant, should be provided for in the construction specifications. Right-of-way acquisition, as for permit acquisition, is normally the responsibility of a Company land department, which often directs contract right-of-way agents. Close coordination with field engineers handling detailed routing and alignment surveying is essential. Land Department representatives are also responsible for
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damage claim settlements. Here again close coordination with field construction engineers is important when the nature and extent of damages and the responsible parties are in dispute.
240 Surface Considerations After establishing a preliminary route as described in Section 210, preliminary alignment photography and/or surveying is done, and environmental and technical surveys are initiated, as appropriate. Priorities must be given to the portions of this phase that are on the critical path for permitting and design.
241 Surface Conditions Information is developed from the preliminary alignment photography and/or surveying on: •
Natural features and agricultural lands. Rivers, streams, water courses, swamps, canals, rocky terrain, irrigated cultivation, dry-land cultivation, range land, forests, etc.
•
Surface improvements. Existing highways, roads, railroads, pipelines, cables, power and telephone lines, etc.
•
Buildings. Existing buildings and structures. For gas pipelines, density of buildings along the route is a critical element in design; see Section 430.
Highway, railroad, and irrigation canal authorities; owners of pipelines, power lines, and telephone cables; and local authorities should be queried regarding future developments of their systems or of residential and industrial areas that might affect pipeline routing or design. Where the preliminary pipeline route roughly parallels existing pipelines, governmental authorities and private landowners are likely to require that the proposed line be located in a corridor with the existing pipeline(s). In such cases it is preferable for construction and maintenance access and safety that the new line be on the opposite side of the corridor from the existing line(s), or, failing this, that ample spacing be provided so that excavation and construction equipment will not jeopardize the existing line(s). Preliminary site inspection at major river and stream crossings should be made to establish tentative crossing locations, for which technical surveys will be made.
242 Environmental Surveys Federal and state regulations provide for protection of significant cultural features and threatened and endangered wildlife, and require surveys of potentially sensitive areas along the route to identify the existence of such areas. If any are found, the relevant authority determines the extent of further investigation and the effect on line routing, conditions for construction, or required mitigation measures. Contracts for these surveys are subject to overruns, because the scope cannot be defined at the
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outset. In essence, the purpose of environmental surveys is both to determine what is there and to establish what must be done to mitigate or investigate further. Typical environmental surveys cover: • • • • • •
Archeological and historical features Fish Birds Other fauna Plants Paleontological features (fossils)
Information developed by these surveys can lead to: •
Adjusting the pipeline route alignment to avoid sensitive areas
•
Completing archeological, historical, and paleontological studies at identified sites before construction—if construction can then be allowed through the sites
•
Scheduling construction activities in areas to avoid critical periods for fish and wildlife, such as breeding, nesting, spawning seasons
Environmental surveys are performed by environmental engineering contractors or independent specialists, often associated with staffs of university departments. These professional service contracts are usually performed on an all-in reimbursable basis for labor and equipment rental rates, with per diem allowances for field expenses. Comparative proposals should be obtained wherever feasible. Environmental Affairs, Governmental Affairs, Engineering Technology Department, local Company offices and the permitting authority may be consulted regarding contractors or specialists recognized and accepted by authorities for expertise in the various categories of environmental surveys. In some areas, government agencies have conducted surveys and predesignated significant cultural resources. Maps of these features are generally available from the agencies involved. This information may save retaining an environmental contractor. In many cases archeological, historical and paleontological field work is done after construction excavation in potential sites in search of any significant evidence in the trench or spoil that warrants further investigation. If such evidence is found, construction work in the area must stop, and either be deferred until investigation and studies are complete, or proceed on a relocated route which skirts the site. Judgment should be used in controlling the extent of environmental surveys. Sufficient work must be done to expeditiously meet permitting conditions, but reasonable limits should be set on investigation beyond the required scope that the specialist field team may want to do at Company expense.
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243 Technical Surveys Depending on terrain and physical conditions along the route, technical studies of some kind will usually be needed for the permitting procedure or for design. Typically, these are as follows: •
Geophysical surveys in areas of soil instability or earthquake activity. These identify areas of concern that warrant further investigation to develop recommended measures to protect the pipeline, or to adjust the route alignment to avoid or reduce the hazard
•
Geotechnical and hydrological surveys at river and stream crossings to develop data on soil properties, predicted scouring and bank variation, and seasonal and historical variations in flow
•
Geotechnical surveys at highway, road and railroad crossings if needed to determine soil properties and water table data for bored crossings, both cased and uncased
•
Geophysical and meteorological surveys for heated lines to determine ground and air temperatures, and soil conductivity properties, or for water slurry lines to determine ground temperatures and frost depths
•
Meteorological surveys to determine weather conditions during the scheduled construction period
•
Geotechnical, hydrological and meteorological surveys may be needed to develop spill contingency plans for oil lines
Technical surveys may involve only a literature search, or a combination of literature search, field investigation, and lab testing, as determined by the circumstances. Professional service contracts with reputable engineering and technical contractors should be used for technical surveys. The Civil and Structural Division of the Engineering Technology Department can be consulted for recommended contractors for these surveys.
250 Alignment, Surveying, and Mapping Initial routing of the pipeline and the preliminary route selection, possibly with alternatives, are based on existing published maps and aerial photography, as discussed in Section 210. Field surveying is usually needed in conjunction with environmental and technical surveys—to mark the preliminary route, to survey proposed crossings, to record locations of soil borings, soil samples, archeological sites, etc. Aerial photography may also be done at this time. When a firm route alignment has been developed, field surveying is done to tie the alignment to land survey monuments and to obtain data for alignment maps and crossing profiles, right-of-way maps, and property maps for station and appurtenance sites. The alignment may be flagged on certain properties to support right-ofway acquisition. At the time of construction the alignment is staked ahead of the
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construction crews, any minor alignment relocations are surveyed, and record data for the completed facility are obtained.
251 Published Maps and Aerial Photography Maps suitable for route selection include the following: •
World Aeronautical Charts. These show significant topographic features; scale is 1:1,000,000 (1 inch = 16 miles). They may be obtained from aircraft charter and service firms, or from Department of Commerce, National Oceanographic and Atmospheric Administration, Rockville, Maryland, 20852.
•
U.S. Geological Survey maps. These show more detailed topographic features and ground cover. Scales are: 1:250,000 (1 inch = 4 miles); 1:125,000 (1 inch = 2 miles); 1:62,500 (1 inch = 1 mile); 1:50,000 (1 inch = 0.8 mile). Maps may be obtained from Operating Company map and drafting records groups, local map supply stores, or the U.S. Geological Survey, Denver, Colorado, or Reston, Virginia. For some areas USGS also has information on geology, flood plain areas, hydrological data, land use and orthophoto maps (with aerial photo background).
•
Canadian Geological Survey maps are similar to USGS maps.
Aerial photographs may be available from government sources to supplement maps for preliminary route selection. A scale of approximately 1:36,000 (1 inch = 0.6 mile) is good for route selection. With about 60% overlap of photos, stereo viewing will show exaggerated ground relief and is useful in laying out the route in rough terrain. Enlargements are useful in selecting station and appurtenance sites. Sources for aerial photography include the following: • • • • •
U.S. Geological Survey U.S. Bureau of Land Management U.S. Bureau of Reclamation N.A.S.A. Commercial aerial photography services
Operating Companies periodically fly their own aerial photography surveys, especially for new exploration areas. Contact your map and drafting records group. Similar topographic maps and aerial photos are usually available from local government sources in other countries.
252 Surveying and Mapping Services Careful selection of a surveying and mapping services company for the project is important, since work must be done accurately, field crews must be available when needed, and maps must be prepared quickly after the field data is in hand. The expected scope of services required for the project should be clearly presented to several reputable land surveying companies and discussed with them to develop information on their capabilities and commitment to meet the expected needs. From
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these prequalification meetings a short-list should be invited to submit proposals. For a long cross-country line it may be advisable to contract sections of the route to different surveying companies. In this case, make arrangements for similar presentation of data by each contractor. The surveying company should be equipped with electronic distance measuring instruments and computerized theodolites, and be able to produce maps within 24 hours, when necessary. Mapping for permit, right-of-way, and land acquisition should be done by the land surveying contractor. Alignment sheets and crossing detail drawings, both for construction and for record, are usually prepared by the project engineering organization using survey data from the surveying company, since these drawings incorporate more information than just the definition of the route. The contract schedule of payments for surveying and mapping services should be complete and precise in covering all items of cost anticipated for the work. Compensation is normally on an hourly or daily reimbursement basis for field crews and office personnel, with added items for special equipment, field expenses, printing and reproduction, etc. Aerial photography and photogrammetric mapping and engineering are often advantageous and economical. The land surveying company may have this capability, or, more likely, will subcontract this phase of work. Compensation for such work should also be defined in the contract schedule of payments at the time of award. On large projects or projects in remote areas sophisticated inertial or satellite surveying systems may be applicable. These may be provided within the surveying and mapping services contract or may be contracted for separately, in which case close coordination is required with the conventional field surveying crews.
253 Aerial Photography and Photogrammetry After a preliminary route is selected for a cross-country pipeline and the project is approved, it may be economical and expeditious to arrange for aerial photography along the route. Aerial photographs may be uncontrolled—by flying at a certain elevation above the ground to give an approximate scale—or controlled by using known surveyed ground reference points and photogrammetric methods to produce accurately scaled photographs. Uncontrolled aerial photography is considerably less expensive than controlled, and may be satisfactory for wilderness or remote areas where accurate right-of-way mapping is not critical. However, in the United States and other developed countries controlled aerial photography and photogrammetric mapping is usually made economical by the saving in costs and time for field survey crews and office engineering and drafting, and will provide the background for final alignment sheets. Photogrammetric methods can also produce elevation data and contour maps. Aerial mosaic strips, marked to show the pipeline with a simplified route alignment map, are useful in describing the route to bidders for construction of the line.
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Usually, aerial photography is done early in the design phase of the project, but there may be situations in wilderness and remote areas in which the cost of controlled aerial photogrammetry done after construction, with the cleared working strip and markers over the pipeline visible, will be offset by reduced field survey costs.
254 Field Surveying and Mapping Control surveys are done on the ground, based on existing government monuments or other accepted monuments with established location coordinates and elevations. Control surveys are usually made to a high order of accuracy (second order or better). They provide the basic network for all other surveying and mapping during the design, right-of-way, and property acquisition and construction phases of the project. The cost of setting up the survey control network is usually significant. Control points should be well documented, and semipermanent monuments installed. This is particularly critical if there should be a change in surveying company between initial surveying and construction surveying. The route centerline alignment is tied to government monuments, property corners, and boundaries and to the monuments established by the control survey. The route is defined by the points of intersection (PI’s) of the straight lines identifying the route, the horizontal lengths, or tangents, between PI’s, and the bearings, or deflections, of the tangents. Preferably, the initial and final points of the line should be stated in Lambert grid coordinates, or another standard grid system adopted by the governmental survey authority for the area. Typically, permit and right-of-way maps show ties to controlling property corners, and the dimensions and areas of right-of-way parcels. Specific requirements for monumenting the right-of-way and preparing right-of-way maps and documents vary from place to place. The Manual of Instructions for the Survey of the Public Lands of the U.S., issued by the U.S. Bureau of Land Management, governs procedures for land surveying. Field surveying must also be done at the design phase for: • • • •
Ground reference points for controlled aerial photography Route alignment sheets Crossing detail drawings Site topographic maps
The alignment is staked at the time of construction. Offset stakes are set from the pipe centerline, usually at 200-foot intervals, and marking stakes are set with horizontal stationings. These stakes define the pipeline for construction—locating the pipe centerline and locations for changes in pipe wall thickness, grade or coating, appurtenances, extra depth of cover, etc. This staking continues during the construction period; if it is done too far in advance of the construction crews, stakes may well be lost before the trench can be excavated.
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Construction staking may be done either by the Company’s surveying contractor or by the pipeline construction contractor. If done by the construction contractor, the Company field engineer should ensure that clearly marked base survey stakes are in place (by which the construction contractor will set his offset stakes) and that the construction contractor’s survey crew is competent. Field surveying may also be needed during the construction period to lay out and stake minor realignments during the course of construction. Field surveying should be done when installing river and stream crossings so that the location and depth of the line, and river bottom and bank profiles are accurately recorded. When the pipeline is in the ground and all work is essentially complete, field surveying is done for record purposes. Slope distances along the line are measured, corresponding to the actual length of pipe. From these, slope stationings for PI’s, pipe and coating changes, crossings, appurtenances, fence lines, pipeline markers, etc., can be derived and shown on the final record alignment sheets.
255 Route Alignment Sheets and Design Drawings These drawings are prepared by the project engineering organization for construction and as a record of the completed pipeline facility. Because the line is generally buried, and lies on property not owned by the Company, accurate records of the line as constructed, or, subsequently, as modified, are particularly important. As prepared for construction, route alignment sheets define the route, with horizontal stationings (the cumulative distance from a starting point of the line, such as the scraper trap mainline block valve at the initial pump station). The alignment sheets typically also show:
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•
Right-of-way width, and position of the new pipeline(s) within the right-of-way
•
Ground elevation profile
•
Pipe minimum cover
•
Pipe size, wall thickness, grade, manufacturer
•
Pipe coating
•
Appurtenance locations, including cathodic protection rectifier stations, anodes, and test stations, with references to detail drawings
•
River and stream crossings, with references to detail drawings
•
Highway, road and railroad crossings, with references to detail drawings
•
Foreign and Company pipeline crossings, with references to detail drawings
•
Underground cable and telephone lines
•
Overhead power and telephone lines
•
Land monuments, section lines, and property boundaries
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•
Property ownership, and permit and right-of-way reference numbers
•
Types of vegetation or cultivation
Crossing detail drawings show plan and profile views for each crossed facility (river, stream, highway, road, railroad) and the pipeline. For cased crossings the casing, size, wall thickness and length are shown, and vents (if any), and the quantity and description of insulating spacer supports and casing end seals are listed. For crossings of pipelines and cables a typical drawing is usually prepared for all such crossings. The record alignment sheets incorporate information on the completed pipeline, and show slope stationings for PI’s and all pipeline features. Horizontal stationings originally shown for the route and ties to monuments and properties should remain. Horizontal stationings and slope stationings should be clearly differentiated; for example, show all slope stationings within parentheses. Chevron Pipe Line Company and the Civil and Structural Division of the Engineering Technology Department may be consulted for recommended format for alignment sheets and crossing detail drawings. See Figures 200-1 and 200-2.
256 Special Survey Systems For surveys in undeveloped and remote areas, and where survey base monuments may be distant, special inertial or satellite survey systems should be considered. State-of-the-art equipment is continually improving, and available systems should be evaluated at the time of the project. These systems give latitude and longitude (or coordinates in a base system), and elevations, and can be effectively used to establish a network of project reference monuments along the route as a basis for conventional field surveying on the ground.
Example Alignment Sheet: Notes (Notes to Figure 200-1) A. Ownership
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1.
Line list number or parcel number identifies property or rancho boundaries crossed by pipeline and right-of-way.
2.
Pipeline schematic and identification.
3.
Right-of-way boundaries on either side of pipeline. Show width of R/W from centerline of pipeline.
4.
Oval containing line list/parcel number identifies property entered by pipeline and/or easement. Numbers are consecutive along pipeline route.
5.
Property lines are not to scale, but represent property limits only. Property plats determine if entire right-of-way or just a portion lies inside property.
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6.
If plat determines that property contains only easement (not pipeline), draw property line within right-of-way.
7.
Property corner "ties" identify property limits more clearly (use a 1/16-in. circle).
8.
"X" after line list/parcel number denotes a road crossing, "R" a railroad crossing. Show centerline and name of road or railroad. If crossing lies between two properties use lower property number.
9.
Line out "stationing &" if not used.
10. Horizontal pipeline footage through a property. This footage is on property plat. Place footage number in line with line list/parcel number. Survey ties to property lines, section corners, etc., are horizontal distances. 11. Place property line stationing (if shown) vertically on left side of property lines. B. Aerial 12. Show scale used. 13. Indicate information concerning "start" of an alignment, e.g., continuation drawing numbers, coordinate system reference, start of survey stationing and/or matching stationing from a previous alignment sheet. 14. North arrow. 15. Plot pipeline line to scale with points of intersection (PI) symbols (1/16-in. circles) indicating bearing changes. Plot valve symbols and bearings along pipeline. 16. List of PI’s and stationing. 17. Milepost marker with stationing to left of extension line. Extension lines extend to, but not through, pipeline line. 18. Line list/parcel number with leader to 1/6-in. dot at property location. Property corner ties help identify plat. Show only property crossed by pipeline or within right-of-way. 19. Identify county and state on each alignment sheet. 20. Identify any parallel pipeline(s). 21. Indicate road/railroad crossings with an oval, symbol and number, and leader to road/railroad centerline. To avoid confusion, set leader at an angle to the centerline. 22. Place crossing symbols as near point of crossing as possible. Make all symbols same size as in legend. 23. Show property, rancho and grant names and boundaries. Reference only properties entered by pipeline. Show township and section lines with stationing.
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C. Material Section 24. Pipeline line (same scale as aerial map). 25. Use extension and dimension lines and a box to identify pipe size, wall thickness, grade, pipe ends, pipe manufacturing process and coating type. 26. Give beginning and ending stationing for concrete coatings, weights and casings as found in field notebook. 27. Use and station cathodic protection symbols per legend and field notebook. 28. Place wall thickness (WT) changes next to extension line. 29. Show valves and refer to separate detail drawings if required. 30. Line up all matchlines. Indicate stationing and continuation sheets or start of survey information. D. Class Location Section 43. For gas pipelines, show class location boundaries. E. Alignment Section 31. Show pipeline as a straight line with PI and valve symbols spaced to scale of aerial strip. 32. Indicate crossings as found in field notebook. Place crossing symbols perpendicular to pipeline at about the same location as in aerial strip with spacing as much to scale as possible. 33. Place stationing and brief description of crossings below symbol in text portion. Stationing relates to inventory (slope) distances, not horizontal distances. 34. Indicate tie dimensions and reference in text when they appear in field notebook. 35. Line up all matchlines with each other. Indicate stationing and continuation sheets or start of survey information. F. Profile 36. Record beginning station and end station. 37. Give elevation for centerline of pipeline. Use a consistent vertical scale on all alignment sheets, large enough to show elevation changes of concern to designer. In hilly terrain, break-points may be used. 38. Profile data is inadequate for calculating overbends and sagbends. Milepost markers are set at or near calculated miles, but should not interfere with land use.
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G. Legend 44. Symbols used on alignment sheet. 45. Revision block. 46. Scale of aerial and alignment strips. 47. Date of plat. 48. Drawing title. 49. Drawing number.
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Fig. 200-1
200 Route Selection
Example Alignment Sheet
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Fig. 200-2
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Alignment Sheet
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300 Pipe and Coatings Abstract This section provides the engineer with guidance on selection of line pipe materials, requirements for bending in the field and in the shop, and selection and application of coatings and linings for corrosion protection. Guidelines and specifications are included. Specifications for line pipe materials, methods of bending, and internal and external coatings are also included.
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Contents
Page
310
Line Pipe Selection
300-3
311
Line Pipe Manufacturing
312
Selection of Grade and Wall Thickness
313
Fracture Toughness Requirements (Impact Testing)
314
Corrosion
315
Specifications and Selection for Specific Services
316
Pipe Purchasing
320
Field Bending
321
Code Requirements
322
Chevron Requirements
330
Shop Bending
331
Induction Bending
332
Hot Bending
340
External Pipeline Coatings
300-28
350
Internal Coatings and Linings
300-30
351
Epoxy Coatings
352
Plastic Linings
353
Cement Linings
360
Piping Components for Pipelines
361
General
300-22
300-24
300-1
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362
Through-Conduit Valves
363
Closures and Appurtenances for Scraper Traps
364
Casing Insulators and Seals
365
Special Repair Fittings
366
Branch Connections
367
Wall Thickness Transition Pieces
370
Special Installations
371
Insulation on Buried Lines
372
Heat Tracing for Buried and Aboveground Lines
373
Nonmetallic and Corrosion Resistant Pipe
380
References
300-43
300-45
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310 Line Pipe Selection Line Pipe Specifications The commonly used industry specifications for line pipe are API 5L and Canadian Standard CAN3-Z245.1. In 1994, ISO (International Standards Organization) adopted line pipe standards. These are ISO 3183-1, Technical Delivery Conditions for Steel Line Pipes for Combustible Fluids — Part 1: Pipes of quality level A; and ISO 3183-2, Technical Delivery Conditions for Steel Line Pipes for Combustible Fluids — Part 2: Enhanced quality level B. ISO 3183-1 is essentially based on the Fortieth edition of API 5L, November 1992. ISO 3183-2 has tighter chemical composition requirements, specific heat treatments and mandatory toughness requirements. It is similar to the Chevron specifications. For both onshore and offshore pipelines the Company generally uses line pipe purchased with Model Specification PPL-MS-1050, Line Pipe for General Service. For sour service, PPL-MS-4041, Sour Service Line Pipe is recommended. Specifications PPL-MS-1050 and PPL-MS-4041 (for sour service) are actually a list of requirements that supplement API specification 5L. These additional requirements are necessary to enable the user or project engineer to obtain state of the technology line pipe with assured weldability, NDE requirements and sour service performance.
311 Line Pipe Manufacturing Pipe Making Processes Line pipe is manufactured by several different processes. Chevron commonly uses seamless (SMLS), electric weld (ERW or HFI), and submerged arc welded (SAW) pipe. There is also helical or spiral welded submerged arc welded pipe, however its use has not been common in Chevron’s operations. Each process has its inherent advantages, disadvantages and suitability for different sizes of pipe. Refer to Figure 300-1.
Seamless Pipe Manufacturing of seamless (SMLS) pipe begins with a solid round billet that is heated to about 2200°F and pierced to make a hollow cylinder. The cylinder passes through several hot (1800-2200°F) rolling steps to make a pipe with the desired size and wall thickness. Seamless pipe may be supplied as-rolled, or it may be heat treated after rolling to improve its properties. Either normalizing or quenching and tempering heat treatments may be used. Straightening if required is done either hot or cold depending upon the mill practice. Seamless pipe has greater variation in wall thickness that welded pipe. Also the length variation in a particular lot or mill run is greater than welded pipe. The engineer is advised to clearly specify the acceptable length variations on the purchase order.
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Fig. 300-1
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Typical Availability and Usage for Types of Pipe Seamless
EW (ERW or HFI)
SAW
Spiral Weld
Minimum Diameter(1)
2-3/8 in. or less
2-3/8 in. or less
16 in. to 20 in.
10 in.
Maximum Diameter(1)
16 in. (typical) to 26 in.
24 in. to 26 in.
64 in. to 84 in.
80 in. to 100+ in.
Maximum Wall Thickness (1) (2)
0.750 in. to 2.000 in.
0.312 in. to 0.750 in.
0.625 in. to 1.500 in.
0.500 in. to 1.500 in.
Grades
B thru X-80
B thru X-70
B thru X-80
B thru X-70
Highly weldable X grades may be heat treated by quenching and tempering
X-52 and higher grades are made from controlled rolled skelp or quenched and tempered
X-52 and higher grades are made from controlled rolled plate
X-52 and higher grades are made from controlled rolled skelp
Acceptable Services
All services onshore and offshore
All services onshore; some offshore services. See Figure 300-2
All services onshore and offshore
USA experience limited to less critical services. Used as equivalent to SAW in Europe, Canada, etc.
Relative Cost
More expensive than EW. Cost premium may be significant for larger sizes (>10 inch)
Usually less expensive than seamless in sizes <10 inches. Almost always less expensive than seamless in sizes >10 inches. Large overlap in size range with seamless
In the small range of size overlap, usually less expensive than seamless but more than ERW
May be less expensive than long seam SAW
(1) The range represents the capacity variations for different manufacturers. (2) Above 1.25 in. refer to ANSI/ASME B31.4 and B31.8 for stress relief requirements.
Electric Welded Pipe (ERW or HFI) Electric welded pipe is manufactured from a long, flat coiled strip called skelp that has been rolled to the desired wall thickness of the finished pipe. The strip has a width equal to the circumference of the pipe. In the pipe mill the skelp is fed through a series of rolls which form it into a cylinder. The edges are welded together using electric resistance (ERW) or induction (HFI) heating and pressure from the rolls to make a longitudinal seam. No filler metal is added to the weld, and after the “flash” from the weld is trimmed off it is difficult to visually locate the weld on the OD. At the ID the flash trimming operation creates a small depression which makes the weld line distinguishable in many cases. The narrow heat affected zone along the seam is heat treated (seam normalized) after welding using localized induction heating coils. EW pipe is usually not given an additional heat treatment
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and its mechanical properties are determined by the original properties of the skelp. Forming, final sizing, and straightening are all done cold. ERW pipe has a better surface finish and can be more uniform in length than seamless. The advantage of better surface quality is that for FBE coated pipe there are fewer problems with holidays in the coating. Note The term ERW is used in this manual to refer to two processes for manufacturing electric welded (EW) pipe, and includes electric resistance welded (ERW) and high frequency induction welded (HFI). The latter is the newer process. The basic difference between the two processes is: the ERW process is conductive where the heating of the vee formed by bringing the edges of the skelp together is produced by flowing a high frequency current between the edges of the skelp prior to pressing the edges together to form the weld; whereas in the HFI process, the heat is generated by an induction coil placed around the formed skelp cylinder. HFI is claimed to have the advantage of producing a higher heat flux across the weld during the manufacturing and therefore is claimed to be more suitable for thicker walls. Chevron has not made a quality distinction between the two processes. ERW Weld Quality. Over 25 years ago, ERW pipe gained a reputation as poor quality pipe. Most of the performance problems were associated with frequent field leaks during field hydrotesting and operations caused by manufacturing defects in the weld. Advances in skelp material quality, manufacturing processes, particularly high frequency resistance and high frequency induction welding, and more accurate and reliable NDE equipment especially ultrasonic testing have virtually eliminated these problems. ERW pipe made today in a modern mill can be manufactured to be equal in performance to seamless. Recommendations for specifying and ordering ERW pipe are found in Section 316 and Figure 300-2.
Submerged Arc Welded Pipe Submerged Arc Welded (SAW) longitudinal seam pipe is manufactured by forming a plate into a cylinder, then making a longitudinal seam using the submerged arc welding process with filler metal. The most common forming process is called UOE, which stands for the three main forming steps: bending the plate into a U, pressing into an O, and then (after welding the seam) expanding the pipe to final size. All of the forming is done cold, including the expansion step. In addition to final sizing, cold expansion also improves roundness, redistributes the residual stresses from forming, and acts as a severe proof test of the weld. Forming processes other than UOE, such as pyramid rolling and press breaking, may also be used to make SAW pipe. Spiral Weld (Helical Weld) Submerged Arc Welded Pipe is manufactured from skelp which is twisted in a helix. The spiral seam is made with the submerged arc welding process. Mechanical properties are determined by the original plate properties. The finished pipe and weld seams are not heat treated. Spiral weld pipe is not usually cold expanded. Spiral welded pipe is not included in PPL-MS-1050 or PPL-MS-4041 because Chevron has very limited experience with the process. API 5L spiral welded pipe is not manufactured in the U.S. There is, however, extensive use in Canada and
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Fig. 300-2
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Specification Decision Tree for Mill Runs of ERW (1 of 2)
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Fig. 300-2
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Specification Decision Tree for Mill Runs of ERW (2 of 2)
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Europe. Spiral weld pipe should be considered for large diameter lines ( greater than 36 inches) in sweet service where it may be more economical than longitudinal seam SAW. It can be purchased to a modified version of PPL-MS-1050. A detailed review of the supplier is mandatory.
Other Processes Corrosion resistant alloy (CRA) line pipe is essentially line pipe made from chromium (13 Cr) and duplex stainless steel, nickel-chromium stainless steels (316) or nickel alloys (Incoloy 825). It is covered in API Specification 5LC. CRA line pipe is seeing increased applications as an alternative to chemical inhibition for corrosion control. It may be cost effective for high temperature streams >350°F (176C) where inhibition is not feasible or in deep offshore applications whenever the total cost of ownership is considered. This product is about 3 to 10 times the cost of conventional carbon steel depending upon alloy grade and size. Consult a materials engineer for assistance in selecting the appropriate alloy and specifications for the environment. Clad or Bimetallic pipe is a new technology for flowlines and gathering lines. This line pipe product consists of a conventional steel line pipe backing to contain the pressure and a “liner” of corrosion resistant alloy. This combination of materials provides a high strength, cost competitive (with solid CRA) pipe up to grade X-65 in sizes over about 6 NPS. The lining material is selected on the basis of the environment in the pipe. The lining may either be metallurgically bonded or hydraulically fitted into the steel pipe. For diameters of NPS 16 and larger this product is made from clad plate. API specification 5LD contains the basic requirements for the purchasing and inspection of clad pipe. In sizes over about 12 NPS it is the preferred way to employ CRA. Justification for selection is usually based on the total cost of ownership of the installation including operating expenses for corrosion control and monitoring. The CRTC Materials and Equipment Engineering Unit can assist in developing the proper ordering specification. Coiled tubing refers to a continuously manufactured length (1000s of feet in length) of electric welded tubing spooled on to a reel. Sizes range from about 3/4 to 5 inches. This product differs from reeled line pipe which is conventional API line pipe of 40 to 60 foot lengths which have been welded together and rolled onto a spool. Because coiled tubing is manufactured as a long length, thousands of feet, it does not conform to all of the API 5L line pipe requirements, especially the weld testing frequency and the prove up of NDE weld line indications. Coiled tubing was developed and used for downhole workovers and is recently (early 90’s) being considered for flowlines. Before coiled tubing is used for pressure flow line applications specialists in design, materials and quality assurance in CPTC and CRTC should be consulted. Furnace butt-welded pipe is similar to ERW pipe, except that the weld is made by heating the edges of the plate in a furnace and then pressing them together. This process does not produce good quality welds, and API 5L only permits it for grade A25. The Company does not use grade A25 for pipelines.
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Lap welded pipe is no longer made. However, there are still significant quantities of this pipe in the ground.
312 Selection of Grade and Wall Thickness Pipe Grades (Strength) Line pipe grades are differentiated by the specified minimum yield strength (SMYS) of the steel. API 5L line pipe is available in strength grades, ranging from Grade B (35 ksi SMYS) to X80 (80 ksi SMYS). The primary advantage of higher strength grades of pipe is reduced wall thickness for comparable design pressure levels. Thinner walls mean fewer tons of steel over the length of the line. Since pipe cost is directly related to tonnage, significant cost savings occur even when the higher strength steel costs more per ton (usually about 20% extra). Cost savings also result from the reduced time required for field welding of the thinner wall pipe. However, before selecting the high strength pipe the designer should investigate the fitting (bends, flanges, etc.) strength requirements and availability. Induction bending of the pipe is a method for producing fittings of the required strength and wall thickness. However if these fittings are being considered, front end planning is required. Note As indicated in Section 310, ISO 3183 is comparable to API 5L. However, the strength levels are metric and therefore the names of the grades are different. The table below contains the English/ Metric conversion for the API grades. API GR.B X-42 X-46 X-52 X-56 X-60 X-65 X-70
ISP l245 l290 L320 L360 L390 L415 L450 L485
Grade Limitations Sweet Service. The Company has used line pipe up to grade X-65, but X-70 is used by other operators. Grade X-80 should be considered where appropriate although manufacturing experience with X-80 is currently very limited. The higher strength grades become attractive in offshore laying operations where laying stresses and not the operating pressure or hoop stresses may be governing the design. Experimental higher strength grades up to grade X-100 are available on special order, but they have not yet been widely used. Sour Service. Chevron has used seamless pipe in grades X-52 and lower in sour service without special requirements beyond API. However, the grade B seamless being supplied today may contain additions of vanadium or columbium for strengthening if the carbon content is being kept low for weldability. These elements should be controlled in the range shown in the Chevron specifications and the welding
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procedures should be tested to assure that heat affected zones are not above 22 HRC. For seamless grades higher than X-52 the requirements of PPL-MS-4041 should apply. For welded SAW or ERW pipe the requirements of PPL-MS-4041 should apply to all grades. For ERW see the decision tree in Figure 300-2. One difference driving different requirements between seamless and welded pipe in H2S service is related to the manufacturing process. H2S environments result in charging the pipeline steel with hydrogen which collects at inclusions within the steel. In seamless pipe the inclusions are cigar shaped and are not deleterious, however in welded pipe which is made from plate or strip the inclusions are pancake like. In this case hydrogen blistering or stepwise (HIC) cracking can occur. The requirements of PPL-MS-4041 minimize the presence of the inclusions and require testing of the steel for cracking sensitivity in H2S environments.
Weldability The weldability of modern pipeline steel is typically determined by the chemical composition of the pipe and not by the yield strength. API chemistry limits are broad and if the steel is at the maximum limits of the API specified compositions, weldability will be compromised. However, this is usually not the case for modern steels. Manufacturers are controlling chemistry limits more tightly than required by API and much of the line pipe being produced today has very good weldability. Many of the X-grades of pipe (with carbon equivalents {CE}of 0.25-0.35%) are as weldable as Grade B. The chemical composition and carbon equivalent requirements of PPL-MS-1050 and PPL-MS-4041 will ensure adequate weldability. Note Carbon equivalent,CE, is determined by an equation of specific elements (expressed as weight percent). If the value is less than 0.42% for general service or 0.38% for sour service the material is considered weldable. This equation only applies to carbon and low alloy steels. CE= C+ Mn/6 +(Cr+Mo+V)/5 +(Ni+Cu)/15 Multiple Stenciling of Grade B. In order to hold down inventories manufacturers are stenciling pipe with multiple grade designations. It is commonplace to obtain pipe marked with all of the following designations: ASTM A-53 Gr B, ASTM A106 B, API 5L Gr B and API 5L-X42. This pipe will meet the minimum requirements of each of the specifications. The chemical composition of this material may not be plain carbon steel but may have alloying elements of vanadium (V), titanium (Ti) or niobium (Nb). These elements may have an effect on hardening the heat affected zone of the pipe when they are present at levels of about 0.02%. The designer is cautioned about the acceptance of Grade B pipe for sour service applications without a review of the mill test reports for the carbon equivalent and these elements. See the previous section on sour service. Pipe exhibiting multiple stencils with X-42 in the stencil will also have higher yield and tensile strength than grade B steels produced in the past. The mill test reports may actually show properties for this grade B that conform to grade X-52 or higher. These steels are acceptable for use as grade B, but the user should be aware that field bending may be more difficult than the traditional grade B steel which has a
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lower yield strength. Also the user should be cautious on accepting these grades for H2S service.
Wall Thickness Pipe diameter and wall thickness requirements are dictated by the fluid flow and design pressure calculations. The calculation for required wall thickness is covered in Section 440. For offshore pipelines, laying stresses and buckling considerations can affect the selected wall thickness and the pipe strength. Refer to Section 930.
Wall Thickness Limitations Several factors limit the use of the higher strength grades of pipe to reduce the wall thickness. Very thin wall pipe can be difficult to handle without denting and difficult to align properly for welding. Section 440 contains the minimum recommended wall thickness for pipelines of various diameters. The maximum wall thickness is restricted by pipe availability (mill capability) as the strength increases. Stress relief of welds is required when the pipe wall thickness is over 1-1/2 inches for ANSI/ASME Code B31.4 and 1-1/4 inches for ANSI/ASME Code B31.8. Stress relieving the field girth welds is costly so higher strength steels should be considered to reduce the wall thickness and avoid heat treatment. Since stress relieving of the low carbon thermo-mechanically rolled steels (those containing vanadium, niobium or titanium) may result in lowering the tensile properties below the minimum allowable, the welding procedure qualification test specimens should be post weld heat treated as well.
Length Variations Length variation must also be addressed when specifying pipe. Length variation is especially a critical factor when laying pipe off of a barge. Welding, inspection and weld coating stations are all set at specific locations along the length of the barge. If pipe has large variation in lengths it will take longer to lay the pipe because the ends will not coincide with the work stations. Short lengths also give problems in loading and unloading pipe onto trucks and barges. The data sheet guide to the pipeline specifications in section 5.2 g gives guidance on length tolerances.
313 Fracture Toughness Requirements (Impact Testing) Pipeline code requirements for fracture toughness of line pipe steels are addressed in ANSI B31.4 for liquid lines and ANSI B31.8 for gas lines. Pipeline Safety Regulations 49 CFR Part 195 (Liquids) and 49 CFR Part 192 (gas) incorporate the ANSI Codes by reference. The intent of both codes is to prevent any type of crack or leak in the pipeline (such as a fatigue crack, or mechanical damage from a backhoe) from initiating a major fracture in the line. This section provides some additional background on fracture toughness, and explains the reasoning behind the recommended fracture toughness testing requirements summarized in Figure 300-3. For
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additional help in specifying adequate fracture toughness, consult CRTC Materials and Equipment Engineering. Fig. 300-3
Fracture Toughness Requirements for Pipelines
Fluid Liquid other than LPG
LPG
Line Size (OD) and Strength Grade All sizes and grades
All sizes and grades
Gas or MultiPhase
CO2
Maximum Allowable Operating Pressure All pressures
All pressures
General Service
Critical Service(1)
No tests recommended
Absorbed Energy average:20 ft-lbs minimum:15 ft-lbs Test Temperature:
20 ft-lbs 15 ft-lbs
Abosrbed Energy average: minimum: Test Temperature:
15 ft-lbs 10 ft-lbs
Absorbed Energy average: minimum: Test Temperature:
20 ft-lbs 15 ft-lbs
Abosrbed Energy average: minimum: Test Temperature:
20 ft-lbs 15 ft-lbs
No tests recommended if lowest auto-refrigeration temperature is above 32°F
4-inch maximum Grade B or X-42 and maximum hoop stress does not exceed 72% of SMYS
3705 psi maximum (ANSI Class 1500)
No tests recommended
14-inch maximum Grade X-52 or lower and maximum hoop stress does not exceed 72% of SMYS
1480 psi maximum (ANSI Class 600)
Absorbed Energy average: minimum: Test Temperature:32°F
14-inch maximum Higher strength grade or maximum hoop stress greater than 72% of SMYS
All pressures
Shear Area: Absorbed Energy: Test Temperature:
(3)
16-inch and larger All Grades
All pressures
Shear Area: Absorbed Area: Test Temperature:
(3)
Any size
Super-critical pressures
20 ft-lbs 15 ft-lbs 32°F
(4)
32°F
(4)
32°F
Consult CRTC Materials and Equipment Engineering Unit
(2)
(2)
(2)
(2)
Shear Area: Absorbed Energy: Test Temperature:
(4)
Shear Area: Absorbed Energy: Test Temperature:
(3)
(4) (2)
(4) (2)
Consult CRTC Materials and Equipment Engineering Unit
(1) Critical service should include the following: All offshore lines, and onshore lines in populated areas Large diameter, high pressure gas lines (particularly lines greater than 14 inch or 1480 psi) Gas or liquid lines where the lowest expected operating temperature is below 32°F LPG lines where the lowest auto-refrigeration temperature is below 32°F (2) Test temperature should be 32°F or the lowest expected operating temperature, whichever is lower. For buried lines, the lowest expected operating temperature is seldom below 20°F. For LPG lines, use 32°F or lower. Test temperature should be based on the lowest auto-refrigeration temperature, but may be higher in some cases. Consult CRTC Materials and Equipment Engineering for specific recommendations. (3) Shear Area: 50% minimum average of all heats, 35% minimum average for each individual heat (4) Absorbed energy: calculate requirements according to the equations given in ANSI B31.8 Section 841. The specified minimum average energy should the the highest value calculated or 20 ft-lbs, whichever is greater. If all calculated values are below 10 ft-lbs, see discussion in Section 313. Also note that the equations are based on methane; see discussion regarding the effect of gas mixtures.
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Ductile to Brittle Transition At low temperature, steel can fracture in a brittle manner like glass or ceramic. The fracture surface has a crystalline appearance, and the amount of energy absorbed is low. As the temperature increases, the steel undergoes a transition from brittle fracture behavior to ductile tearing (also called shear), with a significant increase in the amount of energy required for fracture. This ductile to brittle transition can be characterized using the Charpy impact test, as illustrated in Figure 300-4. The transition temperature can be defined as the temperature where either the absorbed energy for a full-size Charpy specimen exceeds 15 ft-lbs, or the appearance of the fracture surface of the specimen is at least 50% shear. Brittle fracture can be prevented by insuring that the minimum operating temperature of the pipeline is well above this transition temperature. Fig. 300-4
Schematic Drawing Showing Ductile to Brittle Transition Behavior in the Charpy Impact Test
Liquid Lines (ANSI B31.4) For liquid lines, we are primarily concerned about preventing brittle fracture. Since most pipeline steels have adequate toughness to prevent brittle fracture at temperatures above freezing, fracture toughness testing for liquid lines operating above 32°F is generally not required. For liquid lines in critical service, such as a large diameter offshore crude oil line, fracture toughness testing is recommended as an extra guarantee that the steel will be operating above its transition temperature. For these lines, Charpy impact testing should be required according to API 5L SR5, and a minimum average energy of 20 ft-lbs should be specified. The standard test temperature is 32°F, which is acceptable for all lines which operate above this temperature. For liquid lines which operate at temperatures below 32°F, Charpy impact testing should always be required. Specify a minimum average energy of at least 20 ft-lbs at the lowest expected operating temperature of the line. This will insure that the
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transition temperature of the steel is below the minimum operating temperature, and the steel will have adequate resistance to brittle fracture. Note that for buried lines, the lowest expected operating temperature is seldom below 20°F due to warming from the earth.
LPG Lines LPG lines are a special case, because auto-refrigeration can cause very cold temperatures in the area of a leak as the line depressurizes. Brittle fracture of the line could occur if the temperature falls below the transition temperature of the steel while the line is still under substantial pressure. Although the ANSI B31.4 Code does not require special treatment of LPG lines, we recommend fracture toughness testing if the lowest auto-refrigeration temperature which could occur is below 32°F. This temperature must be calculated based on the specific composition of the LPG. Mixtures containing large amounts of propane or butane will have lower autorefrigeration temperatures than those with mostly C5+ hydrocarbons. If the autorefrigeration temperature is above 32°F it is not necessary to specify Charpy impact tests. If it is below 32°F, specify a minimum average energy of 15 ft-lbs at 32°F or lower. Since it would be unlikely that the line would ever actually reach the lowest auto-refrigeration temperature while under substantial pressure, it is not always necessary to specify fracture toughness testing at that temperature. Consult CRTC Materials and Equipment Engineering for recommended testing temperatures for specific lines.
Gas and Multi-Phase Lines (ANSI B31.8) For gas lines, the Code requirements for fracture toughness are more stringent than for liquid lines. The reason for the increased requirements is that in addition to brittle fracture concerns, the stored energy of the compressed gas in a large diameter or high pressure gas line can be great enough to propagate a ductile fracture. If a crack is initiated by an external force (backhoe, earthquake, etc.) the gas in the pipeline will start to decompress and release this stored energy. Whether or not the crack will propagate depends on the speed of the decompression wave inside the pipe relative to the fracture velocity in the steel, as shown in Figures 300-5 and 300-6. If the crack velocity exceeds the speed of the decompression wave, the pipe will “unzip” over a long distance. One way to prevent ductile fracture propagation is to slow down the crack. Since the crack velocity in the steel is related to the steel’s fracture toughness, specifying a high enough minimum Charpy impact energy will accomplish this. Another method is to install crack arrestors, which are discussed in Section 448. The fracture toughness requirements in the Code are mandatory for all lines 16 inch NPS and larger which are designed to operate with a hoop stress over 40% of the specified minimum yield strength (SMYS) of the pipe, and for lines smaller than 16 inch NPS which are designed to operate with a hoop stress over 72% of SMYS (the Code permits maximum design stresses up to 80% of SMYS for some lines). Two acceptance criteria must be met: •
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The average shear area for the Charpy impact specimens must be at least 35% for each individual heat, and the average of all heats must be at least 50%, at
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Fig. 300-5
Ductile Fracture in Gas Pipelines
Fig. 300-6
Example of Ductile Fracture Analysis for Export Gas Line
the lowest expected operating temperature of the line or 32°F, whichever is lower. •
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The average absorbed energy for the Charpy impact specimens from all heats must meet or exceed the energy value calculated using one of several equations developed from pipeline research programs to predict the energy required for ductile fracture arrest. These equations and an example calculation are given in Figure 300-7.
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Fig. 300-7
Example of Ductile Fracture Arrest Calculations
1. Gas Pipeline:
24" outside diameter 1480 psi maximum allowable working pressure
2. Select Pipe Grade and Wall Thickness: API 5L X-60 wall thickness:
(SMYS = 60,000 psi) 0.438" required for hoop stress ≤ 72% of SMYS
hoop stress =
PD ------- = 40,548 psi (68% of SMYS) 2t
3. Calculate Ductile Fracture Arrest Energy using equations from ANSI B31.8 Section 841.11 a. Battelle Columbus Laboratories (BCL) (AGA) CVN = 0.0108σ2R1/3t1/3 = 31 ft-lbs b. American Iron and Steel Institute (AISI) CVN = 0.0345σ3/2R1/2 = 31 ft-lbs c. British Gas Council (BGC) CVN = 0.0315σR/t1/2 = 23 ft-lbs d. British Steel Corporation (BSC) CVN = 0.00119σ2R = 23 ft-lbs where: CVN = full-size Charpy V-notch absorbed energy, ft-lb σ = hoop stress, ksi
R = pipe radius, in. t = wall thickness, in. Company practice has generally been to specify Charpy impact testing for all gas pipelines, with a minimum energy requirement of 20 ft-lbs at 32°F or the lowest expected operating temperature of the line, whichever is lower. This level of fracture toughness is adequate to prevent brittle fracture, and will also exceed the ductile fracture arrest energy required for many small to medium diameter lines with typical operating pressures. This practice is included in the requirements in Figure 300-3, in addition to the Code requirements. For lines up to 4 inch OD (3.5 inch NPS) which operate above 32°F and are designed using API 5L Grade B or Grade X-42 pipe, fracture toughness testing is not required unless the hoop stress exceeds 72% of SMYS, or the maximum allowable operating pressure exceeds ANSI Class 1500 limits (3705 psi at up to 100°F). These lines do not have a significant risk of brittle fracture, and the calculated energy requirement for ductile fracture arrest is low (less than 10 ft-lbs). For critical service, which includes all lines with operating temperatures below 32°F, fracture toughness testing should be specified with a minimum energy requirement of 20 ftlbs at 32°F or the lowest expected operating temperature (whichever is lower) according to past Company practice. Note that API 5L SR5 does not cover testing of pipe 4 inch OD and smaller because it specifies transverse specimens which cannot be taken from small pipe without flattening. All of the requirements of API
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5L SR5 should be followed, except that the specimen orientation should be changed to longitudinal. For lines up to 14 inch OD which are designed using API 5L Grade X-52 or lower strength pipe with maximum allowable operating pressures up to ANSI Class 600 limits (1480 psi at up to 100°F), a minimum energy requirement of 20 ft-lbs at 32°F or the lowest expected operating temperature (whichever is lower) will be adequate to prevent both brittle and ductile fracture. Specifying this requirement is recommended in accordance with past Company practice, even though it is not mandatory according to the Code. However, if the hoop stress exceeds 72% of SMYS, then the Code requirements for shear area become mandatory and the ductile fracture arrest energy requirement may exceed 20 ft-lbs. Also, if higher strength pipe is used to reduce wall thickness requirements or the maximum allowable operating pressure exceeds 1480 psi, the ductile fracture arrest energy requirements may exceed 20 ft-lbs. For lines up to 14 inch OD which fall outside the specific limits given above, and for all lines 16 inch OD and larger, the minimum energy and shear area requirements must be determined in accordance with the Code. There are four equations given for calculating the minimum energy required for ductile fracture arrest (refer to Figure 300-7). Since all four equations generally give results which are easily achievable with modern line pipe steels, we recommend using whichever equation gives the highest value for the particular line in question. The specified energy requirement should not be less than 20 ft-lbs, even if the calculated values are lower. If the calculated values are below 10 ft-lbs, consult CRTC Materials and Equipment Engineering regarding whether or not fracture toughness testing should be waived (unless it is mandatory per the Code). Note that, as stated in the Code, the equations for calculating the minimum energy for ductile fracture arrest are based on pipelines transporting essentially pure methane. Gas mixtures containing substantial amounts of heavier gasses such as propane and butane will have different decompression behavior, and may require higher Charpy energy to insure ductile fracture arrest. An arbitrary safety factor of 1.5 has sometimes been applied to the calculated energy requirements to account for this “rich gas” effect. CRTC Materials and Equipment Engineering can perform an analysis of the decompression behavior of a gas mixture using a mainframe computer program called EQUIPHASE to accurately determine the required Charpy energy. Company specifications require testing of the weld and heat affected zone of seam welded pipe (ERW or SAW) in addition to the base metal whenever fracture toughness tests are specified. The Code requirements for ductile fracture arrest energy are not mandatory for the weld seam, based on the assumption that the weld seam in each joint will be rotated with respect to the next joint. Therefore, a fracture would destroy at most one joint of pipe before it arrests in the next joint. However, it has been Company practice to apply the same requirements to the weld and heat affected zone as for the base metal, and this has generally been achieved without much difficulty. Contact CRTC Materials and Equipment Engineering regarding relaxation of this requirement if necessary.
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Use of drop-weight tear testing (DWTT) in accordance with API 5L Supplementary Requirement SR6 should also be considered for high pressure gas lines 20 inches in diameter or larger and Grade X-52 or higher. The Code permits this test as an alternative to specifying a minimum shear area for the Charpy impact specimens. However, Charpy impact testing is still required to verify that the ductile fracture arrest criteria are met.
CO2 Lines CO2 lines which operate at super-critical pressures (where the CO2 is a dense phase more like a liquid than a gas) are also a special case. Extremely high pressures combined with auto-refrigeration concerns can result in fracture toughness requirements which are significantly greater than for typical natural gas pipelines. Crack arrestors have been used for CO2 pipelines, as discussed in Section 448. Consult CRTC and CPTC specialists for advice on design of high pressure CO2 pipelines.
314 Corrosion Internal Corrosion Carbon steel pipelines are typically designed with a zero corrosion allowance. Adding a corrosion allowance should be an economic decision. Corrosion in pipelines usually takes the form of pitting for which a corrosion allowance offers little benefit. Corrosion can usually be controlled more economically with either inhibitors or corrosion resistant linings. In the special instances where corrosion allowances are desired the following rules of thumb may be used: •
The corrosion allowance depends on the product or medium in the line.
•
As small as possible corrosion allowance is usually selected because it will add to the weight and cost of the line.
•
For refined products the rule is zero to 1/32 inch (0.8mm).
•
For crude lines with significant water the typical allowance is 1/16 to 1/8 inch (1.60 to 3.20 mm).
•
In gas lines that contain water, and CO2 or H2S an allowance of 1/8 inch is reasonable.
•
In special cases a higher allowance may be warranted.
•
Pipelines carrying gas meeting transmission pipeline specifications should not require a corrosion allowance.
In systems where corrosion cannot be controlled or carbon steel is inadequate, several options can be considered: •
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Internally lined pipe (e.g., cement-lined, plastic lined, or epoxy coated) is used in water services. See Section 350 for more information.
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•
Nonmetallic pipe (e.g., fiber reinforced plastic (FRP) or plastic) is sometimes used for water or chemicals. See Section 370 of this manual and Section 1100 of the Piping Manual for more information.
•
Corrosion-resistant alloys (chromium and duplex stainless steels, and nickel alloys) are available as line pipe as indicated in Section 311. There are also weldable low chromium alloy steel grades (0.5% to 2% Cr) with enhanced CO2 corrosion resistance available from some of the Japanese manufacturers.
•
Clad or bi-metallic pipe with a conventional steel backing and an alloy liner is available. API specification 5LD applies to these materials. These materials are very costly but very effective in mitigating corrosion. Long lead times are necessary for procurement. See Section 311.
External Corrosion Codes B31.4 and B31.8 require external corrosion control of buried and underwater pipelines by a combination of external coating (see Section 250 of the Coatings Manual and Sections 340 and 444 of this manual) and cathodic protection (see Section 460 of this manual and Section 500 of the Corrosion Prevention Manual). It is not necessary to provide a corrosion allowance for pitting.
315 Specifications and Selection for Specific Services General Services (PPl-MS-1050) For most services with temperatures above 32°F, including crude oil and products lines, small diameter and low pressure gas lines, and water injection systems, the basic requirements of PPL-MS-1050 are adequate. PPL-MS-1050 also contains supplemental requirements which can be specified for critical services (e.g., offshore pipelines and lines in populated areas). The supplemental requirements can be specified in Data Sheet PPL-DS-1050, which should be part of the bid request and the purchase order. Hard copies of both the data sheet and specification and a PC disk copy of the latter are contained in this manual.
Sour Service (PPL-MS-4041) Specification PPL-MS-4041 covers all services which contain H2S, including sour gas, sour crude oil, and water injection systems which are contaminated with H2S. All of the basic requirements of PPL-MS-1050 are included in PPL-MS-4041, as well as some additions. PPL-MS-4041 also has supplemental requirements, which can be specified on the Data Sheet PPL-DS-4041. Hard copies of PPL-DG-4041 and PPL-MS-4041, and a PC disk copy of the latter are contained in this manual.
ERW Pipe Selection Decision Tree Figure 300-2 presents an ERW pipe selection decision tree which is intended to assist the engineer in the selection of the specification level, supplementary requirements and the mill class / source for ERW pipe. While ERW has been widely used in Chevron for onshore sweet lines its use offshore and for sour lines has been almost nil (except for Canada) . Cost savings can be realized with ERW especially
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in sizes greater than about 10 NPS. All of the requirements and notes shown in the tree must be adhered to since performance is dependent upon all of the requirements being met. The first decision to be made in using the tree is to determine if the environment will be corrosive. Commodity grade ERW pipe can undergo grooving corrosion of the weld seam in low pH waters, salt water, and wet gas containing CO2. Grooving corrosion is controlled by using a pipe chemistry with low sulfur (<0.005%), calcium inclusion shape control, and normalizing heat treatment of the weld seam. These requirements are in the Chevron specifications. The decision tree contains two branches. The branch on the left is for non sour service and the one on the right is for sour service. The left branch references PPLMS-1050 whereas the right branch references PPL-MS-4041. The numbers in the ellipses refer to the supplementary requirements in these specifications. The CSR numbers refer to the list of supplementary requirements. The notes are special instructions or procedures. The mill class refers to the approved list (also see Figure 300-4) in AQUAII which is maintained by the Quality Assurance team in CRTC. Mill surveillance requirements are also recommended based on mill class.
ERW Pipe for offshore pipelines. Chevron did not use ERW pipe offshore until the early 1990’s. One of the resistors was the concern about weld seam quality. With the improvements in skelp quality, seam heat treatment and NDE there has been significant industry usage of ERW for offshore pipelines throughout the world. The decision tree in Figure 300-2 has been developed as a tool to assist the project engineer in selecting the proper specification requirements and class of mill to use ERW pipe offshore with confidence. ERW should be considered for offshore service where there is an economic incentive to do so. This is usually in sizes of 12 inches and greater.
316 Pipe Purchasing Approved Mills CRTC Materials and Equipment Engineering Unit Quality Assurance maintains a list of acceptable pipe mills. The list specifies the manufacturer, plant location, type of manufacture (ERW, seamless, etc.), grades, and sizes. In the case of ERW or electric welded pipe, the manufacturers are classified according to their manufacturing and inspection capabilities. This list should be consulted to establish the acceptable bidders’ list. Mill surveys or audits may be done to qualify additional mills when necessary. ERW Pipe Mills. Not all electric weld mills have kept up with the most current technologies and therefore there is a variation on pipe quality from various mills. CRTC Materials and Equipment Engineering has developed a process where ERW mills are not only approved as in the past but are also classified for specific services according to the mill’s capabilities or attributes. The attributes fall into one of four categories: materials, manufacturing, inspection, and experience. Using a process that uses weighted questions, a score is established for each ERW mill and a class
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assigned. Mills capable of manufacturing the highest quality of pipe are assigned a class A. The classes are tied to specific applications based on severity of service. Mill order quantities. For pipeline projects and major producing field projects (such as gathering systems), the quantity of pipe required is usually large enough to justify mill order purchase. PPL-MS-1050 and PPL-MS-4041 should be used to supplement the requirements of API 5L and to assure that chemical composition, mechanical properties and NDE are adequate. This will minimize weldability and field bending problems during laying of the lines. For recommendations on inspections to be performed see Section 700. Based on experience, ERW pipe will be generally less in cost compared to seamless in sizes above about 10 to 12 NPS. However the engineer, when going out for pipe cost quotations should consider the total cost of ownership including shipping, coating, delivery time, etc. all of which could easily effect the economics of which product is more cost effective. ERW mill order purchases. In order to properly specify and purchase ERW, consult the decision tree in Figure 300-2. This tree is intended to assist the facilities engineer with selection of the proper Chevron specifications, supplementary requirements that will provide the appropriate quality level of pipe and to give guidance on the selection of the mill class. It is recommended that this chart be used whenever ERW pipe is being purchased. If the pipe is coming out of stock, request the mill test reports. Pipe orders from distributor stock. For small projects, pipe is purchased “off- theshelf” from distributor stock. Purchasing pipe manufactured to API 5L, or other similar industry standards typically has been the only option for small jobs. API 5L pipe not meeting the additional requirements of PPL-MS-1050 General Service, or PPL-MS-4041, Sour Service, is adequate for some services, but has had several serious shortcomings. Some of these are: •
Broad chemical composition limits which can decrease weldability
•
Mill hydrotest pressures as low as 60% of the specified minimum yield strength (SMYS) which is usually lower than the field hydrotest
•
Minimum NDE inspection requirements that may not be adequate for critical services
In recent years, many manufacturers are gradually upgrading their standard product to where it will meet many of the Chevron specification requirements. If the engineer requires out of distributor stock (for ERW see next paragraph) it is recommended that they request the mill test reports, and check these against the chemical composition, NDE, and hydrotest requirements of the Chevron PPL-EG specifications. This pipe may be acceptable if it meets these requirements. If assistance is required consult a quality assurance or metallurgy specialist in the Materials and Equipment Engineering Unit at CRTC.
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ERW Pipe Orders from Stock For smaller quantities of pipe ordered directly from distributor stock, the use of the Chevron specifications to place the order is not feasible. The engineer and purchasing units are encouraged to refer to the decision tree in Figure 300-2 to select the appropriate class mill. Knowing the mill who produced the pipe, consulting the new mill approved list, and the experience information in AQUA II available from QA will aid in assessing the suitability of the stock pipe. The engineer should request the mill test reports which will give the chemical composition and the mechanical properties. The type of final NDE can be determined from the mill source. While the pipe will not be made to the Chevron specifications, the engineers will be able to assess whether it is from a high enough class of mill and meets the important specification requirements for the service. Engineers in the Materials Unit will be able to help with this selection.
320 Field Bending Field bending involves cold bending the pipe to the required radius or bend angle. Field bending is needed so the pipe will conform to the curvature of the ditch. For up to approximately NPS 12 the bending can be done with a suitable bending shoe attached to the frame of the side boom. For sizes larger than NPS 12, a field bending machine is recommended. Most domestic field bending machines are manufactured by CRC-Evans, Houston, Tx (713) 460-2900. Their many sizes range from 4- to 60-inch diameter. For large-diameter high-strength pipe, a bending qualification test is recommended to confirm that the proposed bending machine size has adequate capacity to bend the pipe. Bend quality depends on the skill of the machine operator.
321 Code Requirements Both Code B31.4 Section 406.2 and B31.8 Section 841.231 limit the prequalified minimum bending radius to a multiple of the pipe diameter. The minimum prequalified bending radius varies with the pipe diameter. For example, pipe sizes up to and including NPS 12 have a prequalified minimum bend radius of 18D (18 times the pipe diameter). NPS 20 and larger have a prequalified minimum bend radius of 30D. Both Code B31.4 and Code B31.8 will allow a smaller bending radius, providing prototype testing is done. For cold bends, Code B31.4 (liquids) limits the absolute minimum pipe bend radius to 18D. Both Codes B31.4 and B31.8 allow bends with a smaller radius providing a prototype bend conforms to the following: (1) wall thickness is within tolerance for the original pipe, (2) pipe diameter is not reduced by more than 2.5%, (3) the pipe will pass a specified gauging pig, and (4) the bend is free from buckling, cracks, and mechanical damage. ANSI/ASME Code B31.3 Section 332 contains different requirements, but generally allows smaller radius bends.
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322 Chevron Requirements Corrosion Coating Damage Company pipeline fabrication specifications often limit the bending radius to larger than would be allowed by the Code. The intent is to limit pipe coating damage. Excessive bending angles can cause the coating to crack or to spall. The bending limits are different for the various common pipeline coatings. Pritec (extruded polyethylene with a butyl rubber mastic) and Mapec (extruded polyethylene with a thermal setting mastic) are bendable without special precautions. However, these coatings wrinkle very easily, i.e., disbond, and they can hide buckles and mechanical damage in the bend. Fusion-bonded epoxy (FBE) (up to 20 mils DFT) can typically be bent to 1.5 degrees per diameter bend length (38D bend radius) without difficulty. For example, a 40-foot length of 24-inch pipe with two 6-foot tangents has 28 feet of bendable length. This represents 14 pipe diameters, so this joint could be bent up to 21 degrees. Tighter bends are possible, and the limit will depend on the temperature, FBE supplier, and coating thickness. The bendablity of coal tar enamel depends on the ambient temperature and the coating grade. High-temperature grades have poor bending properties at ambient temperature and may require heating to avoid cracking. Field-applied over-the-ditch (OTD) tapes require special attention for bends of more than 0.5 degrees per diameter foot (115D). The OTD machine operator must increase the tape overlap before entering a bend. Otherwise the tape will gap on the outside radius of the bend. Field bending specifications require that the bending apparatus be adequately padded to minimize damage to the pipe coating. Misalignment of the bending shoes can also cause coating damage. Field bends should be holiday-tested (“jeeped”) to confirm that the coating has not been damaged by bending.
Wall Thickness Seamless pipe can have significant variations in wall thickness. The thickness can be determined by ultrasonic measurements (see Section 710). Field bending specifications for seamless pipe require that the thinnest wall be positioned on the inside radius during bending, because the wall on the outside of the bend will be thinned during the bending process. This minimizes the chance that the outside of the bend will have wall thicknesses below the minimum tolerance for the original pipe. Welded pipe does not have significant wall thickness variations.
Welded Pipe Seam For welded pipe, the weld seam should be located on the neutral axis of the bend. This is considered good practice, and is required by CFR Part 192 and Part 195 unless certain precautions are taken. When the bend is in the bending machine, the neutral axis would be located in the 3 or 9 o’clock position for a bend made in the
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vertical plane. This is a workmanship requirement and, providing all of the other Code and specification requirements are met, should not be the sole reason for rejection of a bend.
Sizing Plate Each field bend must be able to pass a sizing plate of a size specified in the bending specification. This can be used to confirm the Code requirement that “pipe diameter should not be reduced by more than 2.5% of the nominal pipe diameter.” Sizing plates that confirm that an inspection pig will be able to pass through the line are typically not necessary for field bends. Field bends are typically 18D and above, and the problem with inspection pig passage usually does not begin until bends are 12D and below.
Mechanical property degradation Significant degradation of the pipe material impact toughness is not expected unless the cold forming strain exceeds 5% (equivalent to less than a 10D bend radius). This degradation is caused by strain aging, which leads to increased yield strength and decreased toughness.
Bending Formulas 57.3° × bend length Bend radius = ----------------------------------------------bend angle
(1)
where: Bend radius and bend length are measured in pipe diameters Bend angle is in degrees D = nominal pipe diameter, ft
(2)
D × 100% Cold forming strain = ------------------------------------2 × bend radius
330 Shop Bending 331 Induction Bending Induction bending for pipe is widely used.
Capabilities and Advantages Large induction bending machines can bend pipe from 3 to 66 inches in diameter with wall thicknesses up to 4 inches and bend angles up to 180 degrees (90 degrees
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for pipe diameters greater than 34 inches). Small bending machines (e.g., Cojaflex PB Special) can bend 2- to 12-inch diameter pipe. The bend radius can be as low as 1.5 times the pipe diameter (3D bends are routine) for small diameter pipe. Figure 300-8 gives some basic induction bending terminology. Fig. 300-8
Basic Induction Bending Terminology
Induction bending overcomes most of the deficiencies of furnace hot bending and has several additional advantages: •
High dimensional accuracy.
•
Various bend angles and multiple plane bends.
•
Off-the-shelf seamless and ERW pipe may be induction bent to avoid small quantities of special order pipe. The weld metal in SAW pipe can be a problem.
Description of the Induction Bending Process The induction bending process uses a medium frequency induction coil to heat the pipe (to 1500-2000°F for carbon and low alloy steels, and 1900-2100°F for stainless steel), while a hydraulic ram pushes the pipe around a radius (see Figure 300-9). A water or air quench ring is placed closely behind the induction coil, so that the width of the heated zone is typically only twice the pipe wall thickness. Restricting the heating and bending to this small zone helps maintain dimensions and avoid wrinkling. As a result, most of the residual stresses are compressive. A water quench provides the best dimensional properties and is preferred, except for ASME P4 and P5 materials. ASME P4 and P5 materials are easily hardened, and they can crack as a result of water quenching.
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Fig. 300-9
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Induction Bending Machine
Note The induction bending temperature cycle can significantly affect the mechanical properties (strength and/or impact toughness) of the pipe as detailed below.
Metallurgical Effects of Induction Bending The thermal cycle associated with induction bending can significantly affect the yield and tensile strength (of all steels), impact properties (of carbon and low alloy steels), and corrosion resistance of austenitic stainless steels. The effects of induction bending vary with the chemical composition and the prior heat treatment of the pipe to be bent.
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•
Carbon steel pipe (e.g., ASTM A106 & A53, API 5L Gr B, X-42, etc.) is strengthened primarily by carbon and manganese. It will often strengthen significantly during the induction bending thermal cycle. For example, API 5L Gr B pipe has met X-70 strength requirements following induction bending. To reduce the excessive strength and hardness in the as-bent condition, these grades require tempering following induction bending.
•
High strength steel pipe (e.g., X-56 and above) is strengthened by chemistry (carbon and manganese), thermal mechanical working, and microalloying. Grades of pipe that gain a significant amount of their strength by microalloying and thermal mechanical working often do not retain their original strength after induction bending. Hence, these steels may have problems meeting specified minimum strength requirements following induction bending. Bends should also be tempered following induction bending, which may further reduce their strength. They must be tempered for sour service.
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•
Low alloy steel pipe (e.g., ASME P4 & P5) will be strengthened significantly by induction bending and is normally cooled by air quenching rather than water quenching during induction bending. The air quench will minimize the hardness and the risk of cracking. These grades require tempering following induction bending.
•
Austenitic stainless steel pipe (e.g., Type 316), which receives some of its strength from cold work, will have its strength reduced by the induction bending thermal cycle. In addition, the beginning and end of the bend will have reduced corrosion resistance similar to that experienced in weld heat affected zones. If corrosion resistance or resistance to stress corrosion cracking is required, only low carbon or stabilized grades (e.g., 304L, 316L, 317L, 321, or 347) of stainless steel should be induction bent.
In summary, all induction bent pipe (except austenitic stainless steels—Type 3XX) should be tempered following bending to reduce the strength and hardness and to improve the impact toughness of the pipe. Tempering should be waived only on certain nonsour-service, high-strength grades when tempering would be detrimental to the final strength and/or impact toughness—and then only after prototype bends are made and shown to meet the service requirements.
Selection of Materials for Induction Bending Successful induction bends have been made in Carbon, Low Alloy, And Line Pipe Steels with carbon equivalents (CE) from the high 0.20%’s through the 0.50%’s. However, carbon equivalents in the mid- to high-0.30%’s represent the optimum chemistry for both bendablity and weldability. Carbon equivalents are defined by the equation: CE = C + Mn/6 + (Cr + Mo + V)/5 + (Cu + Ni)/15 (Eq. 300-1)
A potential weld toughness problem exists when SAW pipe, particularly pipe for low temperature service, is induction bent. SAW wire and flux combinations developed to give good impact toughness in the as-welded condition may undergo a dramatic decrease in toughness after being exposed to a stress-relieving (tempering) or quenching and tempering cycle similar to that encountered during induction bending. Welding consumables are available which will respond more favorably to heat treatment, but they will typically not be the pipe mill’s standard consumable. Model Specification PPL-MS-4737 requires testing of the weld for SAW pipe and weld impact testing when the original pipe is impact tested. If corrosion resistance or resistance to stress corrosion cracking is required, only low carbon or stabilized grades (e.g., 304L, 316L, 317L, 321, or 347) of Austenitic stainless steel should be used as bent. The corrosion resistance would not normally be a factor for service temperatures above 850°F or below 32°F.
Model Specification PPL-MS-4737 Model Specification PPL-MS-4737, Induction Bending, presents requirements for induction bending carbon and low allow steel pipe (ASME P1, and P3 through P5
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pipe, CAN3-Z245.1 line pipe, and API SPEC 5L line pipe). Submerged arc welded, seamless, or electric resistance welded (ERW) pipe may all be bent according to this specification. Austenitic stainless steels (e.g., Type 3XX) may also be bent by induction bending. They have been excluded from the model specification for simplicity. A hard copy and PC disk copy of PPL-MS-4737 are contained in this volume.
332 Hot Bending Prior to the widespread use of induction bending for pipe (approximately 1980), pipe bends were made by hot bending. Two methods were used: •
Hot slab bending. Pack with sand, furnace-heat, and bend while hot
•
Hamburger or clam shell method. Hot-form half-shells in dies and then weld the long seams
These methods were labor intensive, had limited dimensional accuracy, required expensive dies for each size and bend radius, and presented the problem of how to maintain the bending temperature on large pieces. Bending could not continue after the pipe temperature cooled below 1600°F, necessitating repeated return trips to the furnace. Hot bends also require limited quantities of special high-strength line pipe with specific chemical and physical properties, creating a procurement problem. Hot bends are no longer recommended for use in any service.
340 External Pipeline Coatings This section provides a brief overview of the recommended types of corrosion protection coatings for buried pipelines. More complete information on external pipeline coatings can be found in the Coatings Manual and in Section 950 of this manual. The Coatings Manual’s Quick Reference Guide provides a selection guide for external pipeline coatings. It lists the types of coatings (fusion bonded epoxy, extruded plastic, coal tar enamel, tape wraps, etc.) and their recommended services. The guide also includes temperature limits, hydrocarbon resistance, weld joint protection and repair. Figure 300-10 gives the advantages and disadvantages of using these coatings. Fusion bonded epoxy (FBE) is, in general, the best coating for buried lines. Extruded plastics (Pritec and Mapec are preferred because of their high quality adhesive and plastic) are recommended when supply or economics rule out FBE. Tape wraps and coal tar enamel, while needed for certain applications, are not recommended for new pipeline construction. When selecting a coating, installation costs must be balanced with the reliability expected. Using a tape wrap instead of FBE may save money in the short-term, but will increase the chances of long-term losses due to increased maintenance and possible early corrosion failure of the line. Other concerns are shipping costs, appli-
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Fig. 300-10 External Coating Alternatives (1 of 2) Coating
Advantages
Disadvantages
Line Coatings Fusion Bonded Epoxy
20+ years experience Low current required for C. protection Good resistance to C. disbondment -40° to 200°F temperature range Available in all pipe sizes Excellent hydrocarbon resistance Not susceptible to cathodic shielding Excellent adhesion to steel Continuous coating
Near white metal surface prep required High application temperatures Thinnest coating Difficult to apply holiday free Difficult to apply consistently Difficult to apply to bends
Liquid Epoxies (Thermosets)
200°F+ temperature resistance Can be spray or hand applied in field Good chemical resistance Can be applied to odd shapes Can be incorporated with a tape Can be applied while pipe in service
Long cure time (minutes to 24 hours) May need near white blast surface Limited service history Expensive
Extruded Plastic, Butyl adhesive (Pritec brand)
Low current required for C. protection Minimum holidays on application -40° to 180°F temperature range Self-healing adhesive Wide range of sizes Excellent adhesion to steel Continuous coating
High initial cost for small dia. pipe Susceptible to C. shielding Do not use on spiral welded pipe Hard to handle when warm Susceptible to damage from thermal expansion and contraction Cannot be used on bends Limited hydrocarbon resistance
Extruded Plastic, Liquid adhesive(X-Tru-Coat-type)
24+ years experience Minimum holidays on application Low current required for C. protection -40° to 100°F temperature range
Minimum adhesion to steel Do not use above ground Limited storage life Tears in jacket can go length of pipe Adhesive flows at low temperatures Poor hydrocarbon resistance Susceptible to C. shielding Hard to handle when hot
Tape Wraps (services < 140°F)
25+ years experience Easy to apply Can be used for bends Can be used to coat all sizes of pipes Can be applied to pipe while in service
Susceptible to cathodic shielding Poor coating-to-coating bond at overlap Susceptible to soil stresses Temperature limited Non-continuous coating Poor service history
Coal Tar Enamel
60+ years experience Minimum holidays on application Low current required for C. protection Good resistance to C. disbondment Good subsea experience with weight coating Available for all sizes of pipe
Carcinogenic fumes when applied Poor UV resistance Cracking problem below 32°F Soft when hot (100°F) Poor hydrocarbon resistance
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Fig. 300-10 External Coating Alternatives (2 of 2) Coating
Advantages
Disadvantages
Field Joint Coatings Fusion Bonded Epoxy
Best protection Cost near to that of shrink sleeves Same material as on the line See above, Line Coatings
Near white metal surface prep required Requires special equipment to apply Use on FBE lines only See above
Liquid Epoxies
See above, Line Coatings
See above
Shrink Sleeves
Easy to apply by inexperienced personnel -30° to 230°F temperature range Extensive service history Minimum surface prep required (SSPC SP-3) Readily available
High temperature sleeves need heat application Poor hydrocarbon resistance
Tape Wraps
Not recommended, see above
Not recommended, see above
cation site, chemical resistance, maximum service temperature, soil conditions, accessibility to the line, and storage and handling. Tape wraps are no longer recommended for new pipelines because their low cost and the ease of over-the-ditch application are offset by a poor service history and high failure rate. However, tapes are useful for repairing mechanically damaged coatings, protecting large radius bends and tie-ins, and performing over-the-ditch coating refurbishment when other coatings are not flexible enough or cannot be field-applied. Increasingly, liquid epoxies are being used to refurbish old coatings and for odd geometries. These two-part liquids have chemical and temperature resistance properties that are similar to FBE, and can be applied in the field. However, they do require a sand-blast cleaned pipe surface and are relatively expensive. No matter which coating is selected, surface preparation is critical. Poor or improper surface preparation will cause any coating to fail prematurely.
350 Internal Coatings and Linings This section briefly summarizes information from the Coatings Manual. For further information refer to the Coatings Manual. Pipe is internally coated or lined to prevent corrosion, to increase flow rates by reducing friction losses, to preserve product purity, or to prolong the life of an existing line. In this section the term “coatings” refers to the relatively thin painttype coatings, while “linings” refers to the thicker cement or plastic, “field applied” means application of a coating or lining to an existing pipeline. Figure 300-11 gives alternatives for internal coatings and linings.
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Fig. 300-11 Internal Coating/Lining Alternatives for Pipelines Material
Recommended Services
Advantages
Limitations
Approximate Cost(1)
Cement Lining
Produced water Salt water Almost always for new lines
Thick, usually very reliable against water corrosion
Joints are potentially a weak link, not good in many chemicals Min. Pipe diameter: 2-3 inches Temp. approx. 250°F Pressure approx. 5000 psig. Velocity approx. 10 fps
Shop = $1.60/ft.
Plastic Liner (shop applied)
Process chemicals
Excellent corrosion resistance to a variety of services
Typically comes in 20-foot flanged lengths Flange joints can leak Pipe diameter 1-16 inches Temp. approx. 200°F (PPL) to approx. 500°F (Teflon)
Including pipe and flanges = $80/ft (PPL) to $300/ft (Teflon).
Plastic Liner (Field applied) (HDPE)
Produced water Salt water New existing lines
Very reliable Very few joints Can salvage existing lines
Pipe diameter 3-16 inches (but larger sizes can be done) Temp. ±200°F
$9.20/ft.
Coatings (Shop applied)
Produced water Salt water Flow friction reduction
Fair to good corrosion resistance
Joints are potentially a weak link Relatively thin film (may give shorter, less reliable life)
Coatings (Field applied)
Produced water Salt water Flow friction reduction New or existing lines
Fair to good corrosion resistance
Good chance of field foulups Spotty history of quality control Relatively thin film (may give shorter, less reliable life)
(1) Except as noted, costs are for lining an 8-inch pipe at the shop location. Pipe costs extra. Costs are for rough comparative purposes only.
351 Epoxy Coatings Shop applied, internal epoxy coating is generally available as a heat cured powder or as a baked-on liquid. The powder is a thermosetting resin for application by the fusion-bonded process, with or without primer. The baked-on liquid can be epoxy, epoxy-phenolic, or possibly a modified urethane with primer. Field-applied coatings are limited to the liquid epoxies since a furnace cure is not possible. The application method makes an experienced foreman crucial to achieving a good result.
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352 Plastic Linings Linings are installed for new construction or can be installed through existing pipelines to salvage a corroded line that would otherwise have to be replaced. High density polyethylene (HDPE) liners are used to line pipelines in the 3- to 16inch size range. Installation is by wire-line pulling of sections up to 3000 feet long into previously laid steel pipeline. Joints are made with buried flanges. The cost per lineal foot is fairly high compared to cement lining (see Section 353) but may be the only option. For instance, a HDPE liner was pulled through the expansion loops and river crossing sag bends in an otherwise cement-lined pipeline because cementlined pipe could not have been bent. A HDPE lining was used in the 4NPS flow lines for the Norphlet project to reduce the need for inhibition. The liner failed during startup of the system. The consequences of the failure are that significantly larger quantities of chemical inhibitor are necessary to control the corrosion than would be required with a bare steel flow line. While this is a negative experience it is believed that there is considerable potential for cost savings with the use of these liners. It is stressed that front end engineering and testing to qualify a procedure for making the HDPE joints in long pipelines is very definitely required for a successful application. HDPE liners can effectively salvage existing corroded pipelines, even bridging small leaks. For large (18 inch and above) the Company’s own thin-walled HDPE (Spirolite) can be used to line pipelines that operate below about 100 psig.
353 Cement Linings Cement-lined pipe has been used in the United States for nearly 100 years. Cementlined steel pipe combines the physical qualities of steel with the protective qualities of cement mortar. The lining creates a smooth, dense finish that protects the pipe from tuberculation (the formation of scale or other nodules on the inner surface of the pipe) and provides a relatively high flow coefficient. In addition to acting as a physical barrier between the steel pipe and any potentially corrosive fluid, the cement lining also creates an alkaline environment near the steel wall that helps inhibit corrosion [1]. Chevron has successfully used cement-lined pipe for many years in both producing and refining applications. Cement-lined pipe is most often used to protect carbon steel pipe from corrosion in water/brine environments. Typical applications include water injection systems in oil fields and fire water systems in large plants.
Applicable Specifications General. There are several specifications you may use for cement lining steel pipe: •
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API RP 10E, Recommended Practice for Application of Cement Lining to Tubular Goods, Handling, Installation and Joining.
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•
PPL-MS-1632, Materials and Fabrication of Cement-Lined Piping and Tubular Goods. PPL-MS-1632 modifies API RP 10E, which is intended for oil production related uses.
•
AWWA STD C602-83, Cement-Mortar Lining of Water Pipelines in Place.
•
AWWA STD C205-85, Cement-Mortar Protective Lining and Coating for Steel Water Pipe—4 In. and Larger Shop—Applied.
•
ANSI Standard A21.4, Cement-Mortar Lining for Cast Iron and Ductile Iron Pipe and Fittings for Water.
API RP 10E and Company Specification PPL-MS-1632 (used in conjunction) are the recommended specifications for cement-lining of pipe for produced water, reinjection water, brine, and salt water service in the oil field. For some piping intended for fresh or brackish service the AWWA Standards are often good enough. Many small applicators use the AWWA standards and are not familiar with API RP 10E. Refineries and chemical plants have successfully lined pipe to the AWWA Standards for fresh and seawater service. How to Specify. API RP 10E is the recommended specification for cement lining both new and used pipe. Specification PPL-MS-1632 should be used in conjunction with API RP 10E for cement-lining new pipe. In-place (in-situ) cement lining is sometimes done on existing pipe to extend the life of internally corroded pipe, as well as for lining new pipe on site. PPL-MS-1632 should still be used along with the API specification even though it does not directly address in-place lining. PPLMS-1632 still gives guidance on cement selection, gasket selection, etc. API RP 10E is preferred primarily because it covers sulfate- resistant cements with low tricalcium aluminate (C3A) and is a more stringent specification and more appropriate for oil producing or refining services. Company specification PPL-MS1632 is based directly on API RP 10E and modifies it by adding or deleting requirements from several paragraphs. Many cement lining vendors are not familiar with the API practice and commonly use the AWWA standards. In several instances the AWWA standards have been used in lieu of the API standard. The Richmond Deepwater Outfall Project is one example. Generally, if the water being piped is fresh or mildly brackish and the piping system is not deemed critical, specifications other than the API RP 10E are adequate. Examples of noncritical systems are potable water, domestic drainage, and sewage systems. The AWWA Standards have been used in the past with requirements added for steel pipe, curing, joining, etc. Contact the CRTC Materials and Equipment Engineering Unit for assistance with the specific requirements for your project.
Steel Pipe Requirements Company Specification PPL-MS-1050 supplements API SPEC 5L. See Section 310. Thickness and straightness are two very important requirements for steel pipe to be cement-lined. Thickness is more important than the grade. If the pipe is thin-wall, it
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is more apt to be dented, formed out-of-round, or to become bent. Section 2 in API RP 10E and PPL-MS-1632 cover pipe thickness requirements. Pipe should be straight to within 1/8 inch per 10 feet of length. This is not covered in API RP 10E but is used by several cement lining applicators. Spiral-welded pipe is not used for cement-lined pipe that conforms to API RP 10E because the cement cannot be applied by the rapid spin method. The raised weld profile causes the pipe to vibrate severely, and bounce or wobble during application, when spinning speeds can reach 700 rpm. This prevents the application of a good, dense lining and may damage equipment. However, spiral welded pipe has been successfully lined using other lining methods. These methods utilize a heavy slurry sand cement and involve slower spinning speeds and hand trowelling. This type of cement-lined pipe is covered in the AWWA specifications and is appropriate for low corrosive and noncritical systems, as mentioned earlier. Richmond Refinery made successful use of spiral-welded cement-lined pipe for the deep water effluent outfall line.
Types of Cement Linings Cements. The Company specifies Portland cement conforming to ASTM C-150 Type I, Type II, Type III, or Type V depending on the sulfate levels of the water that the pipe will transport. Sulfate ions attack cement linings by reacting with the cement and forming gypsum, which occupies about 18% greater volume than the original cement. The gypsum in turn reacts with C 3A to form a complex hydrate crystal which expands to over 200% of the volume of the original constituents[2]. This causes the lining to spall and crack, and eventually to fail. Types III and V cement are specified for high concentrations of sulfate (above 5000 ppm and 1500 ppm, respectively). Limits are placed on the content of C3A in the cement. Cements with low amounts of C3A are resistant to sulfate attack. Type II cement may be used for moderately sour water with sulfate levels below 1500 ppm. Type I cement may be used for fresh water with sulfate levels below 200 ppm. Fresh and potable water generally have less than 40 ppm of sulfates and seawater has around 2650 ppm. These levels vary; the engineer should obtain an analysis of the water the pipe will transport. Experience. Two types of lining mixtures have dominated cement-lined pipe technology over the last 25 years: pozzolanic cements, containing 60% cement and 40% pozzolans; and sand cements containing 60% sand, 35% cement, and 5% pozzolans[2]. Pozzolans are fine particles of silica and alumina that react with lime to form calcium silicate and aluminates. Experience has shown that pozzolan cements are more sulfate resistant, and sand cements are more acid-resistant [2]. CUSA Producing, Northern Region has used 60% cement/40% pozzolan linings successfully for many years in injection systems high in sulfates conditions. This type of cement has a lower permeability than sand cements and therefore provides more resistance to water diffusing through the pipe and corroding the steel [3].
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Cement Lining Application Chemical Attack. As with almost any type of coating or lining, proper application is one of the most important variables in the overall success and longevity of the coating or lining. For cement linings, proper mix proportion is equally important. Shop-Applied. Straight sections of pipe are lined with a machine that spins the pipe joint and centrifugally applies cement linings to the interior of steel pipe. The entire pipe section is lined to a uniform thickness without interruption. Once the desired thickness is obtained, the rotation speed is increased to produce a dense cement with a smooth surface and a minimum of shrinkage. Elbows, bends, and other shapes must be lined using mechanical placement, pneumatic placement, or hand application techniques. The cement is often reinforced in these cases with a wire fabric reinforcement. The thickness may be varied to make a smooth transition with adjoining sections of pipe but is otherwise the same as centrifugally spun straight sections [4]. Several things can go wrong during the lining process and must be watched for: •
Excessive acceleration up to spinning speed leads to poor spreading of cement and results in lining eccentricity.
•
Too high a spinning speed and too long a spin duration result in particle size segregation in the lining.
•
Applicators must vary rotating speed for different pipe diameters to ensure proper centrifugal forces, which determine liner density.
•
Holddowns, or rollers, should be spaced about one per every 7 feet of pipe. This helps reduce vibration and eccentricity.
Field-Applied or In-Place. Field application is done in three basic steps. First, a mechanical scraper with wire brushes is run through the line enough times to remove heavy scale and deposits. Then, a rubber pig is run through the line to remove sand, debris and water. Finally, the cement coating is applied. Application is by a moving head that centrifugally shoots the mortar onto the steel pipe. A conical trowel almost immediately smoothes out the cement to a uniform thickness. The pipe ends are then sealed to prevent moisture loss [5]. Curing. Specification PPL-MS-1632 requires all shop-applied cement linings be steam-cured. Steam curing accelerates the chemical (cement hydrolysis) curing process and brings the cement to full strength much quicker than an atmospheric cure will. Steam curing does not alter the lining’s chemical resistance properties. Most, if not all, field applicators of cement linings are unable to steam cure. In these cases, the atmospheric curing requirements in API RP 10E, Section 3.4b, should be strictly enforced. Quality Control Procedures. The Company should inspect the contractor’s plant during application to ensure proper lining procedures are being used. The Company should also inspect the finished product and review the applicator’s certification documents to ensure that the cement used for lining meets the required specifica-
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tions. Certification and testing are covered in Sections 4 and 6, respectively, in API RP 10E. Cement Lining Applicators. Listed below are several cement lining applicators. The list is not complete, nor is it an “approved bidders” list. Armor Cote, TX
915/332-0558
Permian Enterprises, TX
915/683-1084
Ameron, CA
213/268-4111
Spiniello Construction Co., CA
213/835-2111
Heitkamp, CT
203/274-5468
Burke Industries, CA
408/297-3500
Progressive Fabricators, MO
314/385-5477
Thompson Pipe and Steel, CO
303/289-4080
U.S. Pipe and Foundry, AL
205/254-7000
American Cast Iron Pipe Co., AL
205/325-7701
Bitco, CA
415/233-7373
Shaw Pipe Protection, Alberta
Joining Cement-Lined Pipe Gaskets. Gaskets are needed to protect the inner surface of steel pipe joints once the pipe is put into service. Gaskets for butt-welded joints must be heat-resistant to withstand the heat of welding. Asbestos has been used for many years and has been largely successful [3]. We believe that asbestos gaskets may still be used in compliance with environmental and health regulations because the gaskets are installed in the outdoors and never exposed once the joint is welded. However, the engineer must check the current regulations concerning the use of asbestos gaskets. The governing regulations are listed on page three of API RP 10E. If the operating company or the governing regulations prohibit the use of asbestos gaskets, API RP 10E lists an alternative to asbestos. This is a new product with limited field experience. We believe that the flexible graphite sheet will work well, but it costs considerably more than asbestos. Chevron Canada Resources has successfully used an Inconel wire-mesh-impregnated gasket for welded joints. These gaskets are available through Alberta Gaskets in Alberta. The CRTC Materials and Equipment Engineering Unit can provide assistance with selecting nonasbestos gasket materials. Joints. The Company has used butt-weld, sleeve, and slip-on flange joints. Buttweld joints are preferred because they are stronger and stiffer than sleeve joints. Slip-on flange joints are hardly ever used because welding heat damages the cement lining. Screwed-on flanges are possible but not recommended. See Figure 300-12 for illustration of a butt-weld cement-lined pipe joint.
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Fig. 300-12 Butt-weld Cement-Lined Pipe Joint
Welding procedures for cement-lined steel pipe have traditionally been standard pipeline procedures, with incomplete penetration on the root pass to avoid damage to the cement and gasket. Electrodes have generally been of the EXX10 type. Some recent experience in Canada has suggested that these electrodes, which leave more hydrogen in the weld, may combine with the stress riser of the incomplete penetration weld to produce root cracks. A welding procedure using EXX18 low hydrogen electrodes and an inconel wirereinforced composition gasket has been developed by Chevron Canada Resources. The procedure allows more weld penetration (90+%) and thus a stronger weld. The procedure is downhill for NPS 2 pipe and uphill for NPS 3 and larger. The uphill procedure appears slower but will save on repair time. Contact the Design and Construction Group in Calgary for further information. Branch Connections. Branch connections are preferably made with cement-lined tees. Branches may be made with bosses or weld-o-lets that have been fabricated into a pipe spool and cement-lined in the shop. Good advance planning and design will allow ordering shop lined branch components with connections and fittings attached. If field cutting must be done use a hole saw. A hole saw is a cylindrical saw attached to a drill. A cement-lined weld-o-let should be welded on and the internal lining repaired with a repair compound such as X-Pando. Field torch-cutting for branches should be avoided as this damages the cement lining. Repatching these damaged areas is difficult, especially for small connections and fittings. Ordering extra tees, fittings, and flanges will prevent delays in field work and result in better lining integrity.
Typical Problems with Cement Linings Chemical Attack. Cement linings can be corroded by many different chemicals [2]. Examples are: • •
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Strong acids with pH below 5.0 Carbonic acids
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• •
Sulfates (as described earlier) Magnesium chlorides
The pipe’s spinning during cement application and subsequent hardfinishing results in the lining being slightly thicker at the ends. If the gasket seal fails corrosion may start at the joint. However, the lining may not begin to spall or break until steel corrosion has progressed several inches away from the joint because of the slightly thicker lining near the joint. Erosion. High fluid velocities, especially at tees and elbows, can also cause cement lining deterioration. Water and solids impingement can cause erosion and also continually replenishes corrosives to the lining. Unfortunately, the linings at elbows and tees are not centrifugally spun and therefore are not as dense and strong as linings in straight sections. Fluid velocities should be limited to roughly 10 fps (3 m/s) in order to avoid erosion damage (from the equation V = 100/ρ, where ρ = density of the fluid in lb/ft3).
Transportation and Handling of Cement-lined Pipe Cement-lined pipe should be transported and handled with care so as not to crack or damage the lining. API RP 10E covers the proper procedures for loading/unloading, transportation, and installation handling for cement-lined pipe. Refer to API Recommended Practices RP 5L1, 5L5 and 5L6 for information on general handling of pipe.
360 Piping Components for Pipelines 361 General This section describes piping items with specific application to pipeline service that are commonly used in pipeline systems: • • • •
Through-conduit valves Closures and appurtenances for scraper traps Casing insulators and seals Special repair fittings
Other items commonly used but also found in plant piping systems are also described: • •
Branch connections Wall-thickness transition pieces
For other piping components where use is the same as for plant piping systems see Sections 200 and 300 of the Piping Manual.
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362 Through-Conduit Valves Because cross-country and offshore pipelines are nearly always designed for scraper runs through the length of the line, line valves must allow for smooth passage of scrapers and any objects or debris that may be pushed ahead of the scrapers. Thus, valves must be full-opening to match the internal diameter of the line pipe, and not have any pockets or irregularities that would catch or trap scrapers or debris passing through the valves. Line valve types include steel gate valves, ball valves, and check valves. API Specification 6D, Pipeline Valves, End Closures, Connectors and Swivels, applies to these valves and is included by reference in Codes B31.4 and B31.8 for liquid and gas pipelines. Valves may be welded into the line or flanged. Unless there is a particular purpose for a flanged connection, welded connections are generally preferred for their cost savings and to minimize potential flange leakage in service. Depending on size and service considerations, valves are either operated manually (lever/wrench, handwheel, or geared) or powered (electrical, hydraulic, or pneumatic). Service and size, as well as economics, will influence comparative evaluation between gate valves and ball valves. Gate valves do well in all services; ball valves should be restricted to clean products and gas. Gate valves are bulkier and require larger and more expensive actuators (operators); ball valves are compact, easier to operate, and better suited for hydraulic and pneumatic operators at remote locations. Design features to be considered in valve selection are as follows: •
Gate valves: gate seating, bonnet type, body pressure relief and drain, lubrication
•
Ball valves: ball seating, body access, lubrication
•
Check valves: seating, closure dampening
Typical through-conduit valves are manufactured by the following: •
Gate valves: WKM, Houston TX; Grove, Oakland, CA; Walworth-FIP, Houston, TX; Daniels M&J, Houston, TX; USI Axelson
•
Ball valves: WKM, Houston, TX; Cameron, Houston, TX; Borsig, Germany
•
Check valves: Wheatley, Tulsa, OK; Streamflo, Edmonton, Alberta
Design and selection of subsea pipeline valves is discussed in Section 950. Valve type and manufacturer standardization is highly desirable, allowing operating and maintenance personnel to acquire greater familiarity with the valves and minimizing spare parts stock. It should be recognized that selection of standardized valves within an operating organization or for a project may vary depending on service and size.
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363 Closures and Appurtenances for Scraper Traps Closures The closure at the end of a scraper trap barrel provides easy, quick opening of the barrel for insertion and removal of scrapers. Closures should comply with Section 406.6.1 of Code B31.4 and API Specification 6D, Pipeline Valves, End Closures, Connectors, and Swivels. A closure is hinged or equipped with a davit so that it swings clear of the barrel opening. A locking mechanism seals the opening, and should be equipped with a pressure warning device to alert the operator to completely relieve pressure in the barrel. Typical closures are made by Huber-Yale, Borger, TX; see Figure 300-13. Fig. 300-13 Huber-Yale Figure 500 Closure
Scraper Passage Detectors A scraper trap manifold usually includes mechanical devices to indicate passage of outgoing and incoming scrapers. These have a mechanical “flag” for a visual signal or can be fitted with a switch for electrical indication. Typical devices are made by T. D. Williamson, Inc., Tulsa, OK, and F. H. Maloney Company, Houston, TX.
364 Casing Insulators and Seals Casing insulators are durable, electrically nonconducting supports, banded around the line pipe at spaced intervals, to keep the line pipe from contacting the casing in a cased highway or railroad crossing. To prevent slippage on the line pipe, an insulator should clamp securely around the pipe without damaging the coating and should readily slide along the casing. Casing seals close the annular space between the line pipe and the casing. Casing seals are of two types:
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Flexible, nonconducting, water-tight sleeves with end diameters that match the casing and the line pipe and stainless steel bands that clamp the end seals around the line pipe and the casing Expandable synthetic rubber rings that fit between the line pipe and the casing (Link-Seal) Typical insulator assemblies and flexible seals are made by Pipeline Seals and Insulator Inc., Houston, TX; and F. H. Maloney Co., Houston, TX. Link-Seal brand ring seals are made by Thunderline Corp., Wayne, MI.
365 Special Repair Fittings The special repair fittings manufactured by The Pipe Line Development Company (Plidco), Cleveland, OH, have application in facilitating repairs and modifications to line pipe in situations where hot work (torch cutting, welding) cannot be done safely because of inflammable liquids or vapors in the line or in the working area. These special repair fittings include the following: •
Plidco “Weld + Ends” Coupling. This is a collar coupling that slips over the line pipe, and clamps and seals around the outer periphery of the pipe to make a leakproof joint so that operation of the line can be resumed. With flow resumed and conditions safe for welding, the coupling can be fully sealwelded to the line, making a permanent installation. See Figures 300-14 and 300-15.
Fig. 300-14 Plidco “Weld + Ends” Coupling
Chevron Corporation
•
Plidco “Split + Sleeve.” This is a longitudinally split sleeve that bolts around the line pipe to make a seal. It also can be sealwelded to the line after flow is resumed.
•
Plidco “+ Flange.” A flanged fitting that slips over the line pipe and clamps and seals around the pipe. It also can be subsequently sealwelded to the line.
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Fig. 300-15 Plidco “Weld + Ends” Cross-section
•
Plidco “Smith + Clamp.” This fitting plugs pinhole leaks while the line is under pressure. It should be considered as a temporary short-term measure until permanent sleeve repairs or pipe replacement can be made.
•
Plidco “Hot Tapping + Saddle.” This is a split sleeve with flanged branch connection for hot taps where surrounding conditions do not permit welding, including underwater tie-ins. If conditions subsequently permit, it can be sealwelded.
•
Custom/Special: Plidco will also custom design and fabricate special repair fittings for almost any application.
366 Branch Connections Section 404.3 of Code B31.4 and Sections 831.4, 831.5 and 831.6 of Code B31.8 cover detailed requirements for design of branch connections. Dependent on size and pressure, branch connections complying with Code requirements may be: •
Forged welding tees, per ANSI Specification B16.9, Factory-Made Wrought Steel Butt-Welding Fittings
•
Integrally-reinforced, extruded outlet headers
•
Welded branches with full-encirclement reinforcement
•
Welded branches with localized reinforcing saddles
•
Forged weld-o-lets for small-size connections (NPS 1, 1-1/2—connections under NPS 1 are not recommended) at manifolds, or larger size weld-o-lets on heavier wall pipe that is not highly stressed
Forged welding tees and integrally-reinforced extruded outlet headers are recommended. Alternatively, welded branches with full-encirclement reinforcement may be considered for large-diameter, high-strength line pipe, because high-strength
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forged fittings are often costly and unavailable. Localized reinforcement is not recommended. Main line branch tee connections that are larger than about 25% of the line diameter should be provided with bar grates so that scrapers will not get caught at the branch. See Standard Drawing GA-L99880.
367 Wall Thickness Transition Pieces At butt-welded joints when wall thicknesses of the adjoining pipe or fitting vary by more than 3/32 inch (2.4 mm), Codes B31.4 and B31.8 and CSA Standard CAN3Z183 require tapering at the transition. CSA Standard CAN/CSA-Z184 requires tapering for a 1/16-inch (1.6 mm) mismatch. The more conservative criterion of 1/16-inch mismatch is recommended for Company pipelines. Figure 4.8.6(a)-B of Code B31.4 and Figure I5 of Code B31.8 show similar details for acceptable butt-welded joint design for unequal wall thicknesses. When the thicker wall pipe or fitting is the same or higher grade as the thinner wall pipe, its inside wall may be tapered by smooth-grinding in the field. A 4:1 taper is suggested. More commonly, the thicker wall pipe or fitting is the lower grade and cannot be tapered lest it then be unsuitable for the design maximum operating pressure. In this case a transition piece is required. Alternatively, for large diameter pipe, internal backwelding to form the taper is permissible. The material grade of the transition piece must match the higher grade of the thinner wall pipe. A 4:1 machined taper is suggested. The Codes allow a taper between 30 degrees maximum and 14 degrees minimum. Both ends are bevelled for butt-welding to the adjoining pipe. The transition piece should be long enough so it can be readily handled and fit up with welding clamps. A length of 12 inches minimum or 1.5 x pipe diameter is suggested for sizes up through NPS 24, and 1 x pipe diameter for larger sizes, although the Codes allow a length of 0.5 x pipe diameter. The pipe size, grade, and wall thickness of each end should be clearly stencilled on each transition piece, so it can be readily identified for installation at the correct pipe wall change location. Obtaining stock material of sufficient wall thickness in high-strength grades is often difficult. Transition pieces should be designed and purchase orders placed as early in the project as practical.
370 Special Installations This section gives brief references to Company pipeline systems that incorporate special features, such as: • •
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Insulation on buried lines Heat tracing for buried and aboveground lines
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•
Nonmetallic and internal-corrosion-resistant pipe
The Materials and Equipment Engineering Unit of CRTC can be contacted for background on the design features of these and current systems. For similar and other special installations reference should also be made to articles and technical literature available from Company library resources and technical publications.
371 Insulation on Buried Lines Company projects using insulation or buried lines include the following: •
Bluebell Pipeline in eastern Utah, Chevron Pipe Line Company, 1973
•
Feluy Heavy Fuel Oil Line in Belgium, Chevron Oil Belgium, 1971
•
Rio Bravo-Estero Pipeline in Central California, Chevron Pipe Line Company, 1981
•
Flow lines and gathering lines, Chevron Canada Resources, Calgary, Alberta
372 Heat Tracing for Buried and Aboveground Lines Company projects using heat tracing on buried and aboveground lines include the following: •
4-inch hot water tracer with buried 8-inch heavy fuel oil line in Hawaii, CUSA, 1960
•
Skin-electric-current-traced (SECT) 6-inch sulfur line in Wyoming, CUSA, 1983
•
SECT-heated 24-inch crude oil line in Sumatra, Caltex Pacific Indonesia, 198082
373 Nonmetallic and Corrosion Resistant Pipe •
Examples of fiber-reinforced plastic (FRP) pipe for produced water and water injection lines, by various producing organizations, include the following: – –
•
CUSA, Southern Crane County, California; Rangely, Colorado Chevron Canada Resources, Calgary, Alberta
90-10 Cu-Ni offshore seawater intake pipe at Gaviota, CA, CUSA Western Region
Bimetallic (duplex) co-extruded pipe should be considered for highly corrosive service. This pipe has a layer of stainless steel or nickel alloy on the inner surface of the carbon steel pipe, joined by a metallurgical integral-welded bond. Although the Company has no pipeline experience, others in the industry (Sohio, Alaska; Shell, UK North Sea) have installed pipelines for untreated hot oil-gas-water
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systems with high CO2 content and for wet sour gas service with high CO 2 content. The Company has installed duplex piping for: • •
North Rankin “A” Platform (Sandvik 2205 SS) for various services Hidalgo Platform for brine blowdown from vapor compression watermaker
The cost of this special-order pipe may be less than solid alloy material. Mills that have produced duplex pipe are: • • • •
Japan Steel Works, Japan Sumitomo Metals, Japan Sandvik, Sweden Tubacex, Spain
API Specification 5LC, Corrosion-Resistant Line Pipe, is suggested for use in ordering pipe, with additional specifications for the particular service conditions provided by the Materials and Equipment Engineering Unit of CRTC.
380 References
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1.
American Water Works Association (AWWA). AWWA Standard for CementMortar Protective Lining and Coating for Steel Water Pipe -4 In. and Larger— Shop Applied. AWWA C205-85.
2.
Fruck, Giovanetto, Purdy. Engineering Aspects of Cement Lined Pipelines for Use in Water Systems. 1976.
3.
Murphy, C.A. Cement-lined Pipe Failure; Water Injection System, Virden Canada. June 30, 1982 (Mat Lab File 70.20).
4.
Mishael, S.J. Richmond HPSW Mortar Linings. October 11, 1983 (Mat Lab File 70.20).
5.
Price, J.E. Guidelines for Selection of Line Pipe and Use of Specifications EG1050-E and EG 4041. August 10, 1987 (Mat Lab File 67.20).
6.
Kohut, G.B. ERW Line Pipe Guidelines. December 19, 1994 (MEEU File 67.0).
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400 Design Abstract This section discusses the many considerations involved in the engineering design of pipelines. It covers the design scope for the pipeline facility—not the associated station and terminal facility (although station and terminal piping are included in pipeline codes for transportation systems). This section relates regulatory jurisdiction to the selection of an appropriate design code. Hydraulic calculations, line sizing, stress analysis, pipe wall thickness calculations, pipe and coating selection, and ancillary considerations are discussed in relation to the various codes and the Company’s preferred practices. Pipeline crossings, appurtenances, and cathodic protection facilities are also discussed.
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Contents
Page
410
Regulations and Codes
400-3
411
Regulatory Jurisdictions
412
Codes
420
Hydraulics
421
Basic Pressure Drop Calculations
422
Special Hydraulic Conditions
423
Hydraulic Profiles
430
Line Sizing
431
Elements to Determine an Economic System
432
Preliminary Pipe Selection and Line Operating Pressure
433
Hydraulic Profiles and Pump Station Locations
434
Order-of-Magnitude Estimates for Investment Costs
435
Order-of-Magnitude Estimates for Operating Costs
436
Economic Analysis for Line Sizing
437
Improving Cost Estimates
438
Sizing of Short Lines
440
Line Design
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441
Pipe and Coating Selection
442
Pipe Stress and Wall Thickness Calculations for Liquid Pipelines per ANSI/ASME Code B31.4
443
Pipe Stress and Wall Thickness Calculations for Gas Transmission Pipelines per ANSI/ASME Code B31.8
444
Coating Selection
445
Burial—Restrained Lines and Provision for Expansion
446
Seismic Considerations
447
Crossings
448
Special Considerations
450
Pipeline Appurtenances
451
Line Valves
452
Scraper Traps
453
Electronic Inspection Pigs
454
Line Pressure Control and Relief
455
Slug Catchers
456
Vents and Drains
457
Electrical Area Classification
458
Line Markers
460
Corrosion Prevention Facilities
461
General
462
Impressed Current System for Cathodic Protection
463
Galvanic Sacrificial Anodes for Cathodic Protection
464
Insulating Flanges and Joint Assemblies
465
Cathodic Protection Test Stations and Line Bonding Connections
470
References
400-50
400-62
400-63
400-2
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410 Regulations and Codes 411 Regulatory Jurisdictions United States Regulations governing interstate hazardous liquid and gas pipeline facilities are established and enforced on a federal level. Intrastate pipeline facilities are subject to federal authority unless the state certifies that it will assume responsibility. The state must adopt the same regulations or more stringent, compatible regulations. The Chevron Pipe Line Company Guide to Pipeline Safety Regulations provides information on federal and state jurisdiction for hazardous liquid and natural gas pipelines. The Operations Section of Chevron Pipe Line Company should be contacted for a copy of this guide. Regulations for hazardous liquid pipelines are covered in Title 49, Code of Federal Regulations, Part 195 (49 CFR 195), Transportation of Hazardous Liquids by Pipeline. Section 195.2 defines a hazardous liquid as petroleum, petroleum products, or anhydrous ammonia. Section 195.1(b) excludes onshore gathering lines in rural areas and onshore production facilities and flow lines. Pending regulations are expected to include supercritical CO2 pipelines under Part 195. For gas pipelines, 49 CFR 191, covers annual reporting and incident reporting, and 49 CFR 192 deals with minimum federal safety standards for transportation of natural gas and other gas by pipeline. Section 910 of this manual gives further details on the applicability of the various regulations to offshore pipelines.
Canada In Canada, jurisdiction for pipeline design and operation is either federal or provincial. In general, interprovincial transmission pipelines and pipelines designated as involving national priorities are regulated by the National Energy Board and are certificated pipelines. The Company is not, as yet, involved in transmission pipeline operations in Canada and therefore is not usually concerned with the National Energy Board regulations. Intraprovincial transmission, interfield, and gathering system pipelines are provincially regulated. Alberta, British Columbia and Saskatchewan have well established government departments to handle pipelines. The other provinces impose varying degrees of control. Most of the Company’s Canadian operations are in Alberta, British Columbia, Manitoba and Saskatchewan. Alberta’s Pipeline Act is enforced by the Energy Resources Conservation Board. The Board issues its Pipeline Regulations and the Oil and Gas Conservation Regulations. These regulations govern pipeline design, licensing, construction, testing, and record keeping, and exercise influence over routing, measurement, and environmental issues. For information on other provinces, contact Chevron Canada Resources Limited in Calgary, Alberta.
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Other Locations Legal requirements for pipeline design and operation in other geographical locations must be determined individually. If regulations do not exist or are less restrictive than U.S. regulations, the pipeline facilities should be designed to the applicable ANSI/ASME code.
412 Codes ANSI/ASME Code B31.4 ANSI/ASME Code B31.4, Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum Gas, Anhydrous Ammonia, and Alcohols is incorporated by reference in 49 CFR 195. It is also a sound basis, although not legally required, for crosscountry water and water slurry pipelines, allowing their future conversion to oil or other hazardous liquid service. A copy of Code B31.4 may be found in this manual under Industry Codes and Practices. Code B31.4 establishes requirements for safe design, construction, inspection, testing and maintenance of pipeline systems transporting liquids such as crude oil, condensate, natural gasoline, natural gas liquids, liquified petroleum gas, liquid alcohol, liquid anhydrous ammonia, and liquid petroleum products. The Company has used this code for Gilsonite and phosphate slurry pipelines. Figure 400.1.1 in Code B31.4 (1986 Addenda) shows the range of facilities covered by the code. Among these are pump stations, tank farms, terminals, pressure reducing stations and metering stations. Code B31.4 does not apply to auxiliary station piping such as water, air, steam, lubricating oil, gas and fuel; piping at or below 15 psig, piping with metal temperatures above 250°F or below -20°F; or field production facilities and pipelines.
ANSI/ASME Code B31.8 Incorporated by reference in 49 CFR 192 for natural and other gas, ANSI/ASME Code B31.8, Gas Transmission and Distribution Piping Systems, applies to field gathering, transmission and distribution pipelines for natural gas. It covers the design, fabrication, installation, inspection, testing, and safety aspects of gas transmission and distribution system operation and maintenance. Figure I8 in Appendix I of Code B31.8 shows the range of facilities covered by the Code, including gas compressor stations, gas metering and regulation stations, and closed-pipe gas storage equipment. A copy of Code B31.8 may be found in this manual under Industry Codes and Practices. Code B31.8 does not apply to piping with metal temperatures above 450°F or below -20°F, vent piping operating at substantially atmospheric pressures, wellhead assemblies, or control valves and flow lines between wellhead and trap or separator.
Canadian Standard CAN3-Z183 Canadian Standard CAN3-Z183, Oil Pipeline Systems, is incorporated by reference into the National Energy Board Act of Canada and the pipeline regulations of all
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Canadian provinces. It covers the design, material selection, fabrication, installation, inspection, testing, operation, maintenance, and repair of onshore pipelines carrying crude oil, multiphase liquids, condensate, liquid petroleum products, natural gas liquids, liquified petroleum gas, and oilfield water. CAN3-Z183 applies to pump stations, tank farms, pressure reducing stations, and metering stations. It does not apply to auxiliary station piping such as water, air, steam, gas, fuel and lubricating oil, piping with metal temperatures above 120°C or below -45°C, production equipment or oil wells. A copy of the Standard may be obtained from Chevron Canada Resources or the Canadian Standards Association.
Canadian Standard CAN/CSA-Z184 Canadian Standard CAN/CSA-Z184, Gas Pipeline Systems, is incorporated by reference into the National Energy Board Act of Canada and the pipeline regulations of all Canadian provinces. It covers the design, fabrication, installation, inspection, testing and safety aspects of operation and maintenance of gas pipeline system, including gathering lines, transmission lines, compressor stations, metering and regulating stations, distribution lines, service lines, offshore pipelines and closed-pipe gas storage equipment. It does not apply to liquified natural gas pipelines, auxiliary station piping such as water and air, metal temperatures above 230°C or below -70°C, production equipment, or gas wells. A copy may be obtained from Chevron Canada Resources or the Canadian Standards Association.
Producing Field Flow and Gathering Lines The ANSI/ASME Codes do not clearly define the extent of producing field flow and gathering lines, and CFR regulations do not cover oil and gas gathering lines in rural areas. Therefore, the Company has not always been consistent in applying the codes when designing pipelines between producing facilities and pipeline transportation systems. Where practices have not already been established, it is suggested that designs for field liquid pipelines follow Code B31.4, and, for gas pipelines, Code B31.8. 49 CFR 192 and 195 apply within the limits of any incorporated or unincorporated city, town, village, or other designated residential or commercial area. They require compliance with ANSI/ASME B31.4 and B31.8. 49 CFR 195.2 defines a liquid gathering line as a pipeline sized NPS 8 or smaller from a production facility. 49 CFR 195.1(b)(6) excludes transportation through onshore production facilities (including flow lines). 49 CFR 192.3 defines a gas gathering line as a pipeline that transports gas from a current production facility to a transmission line. Where a line handles liquid-gas two-phase flow, the more stringent requirements of each code should be applied, and special consideration should be given to the effects of slug flow along the system.
Producing Field Facilities For on-plot production facilities such as wellhead piping, separators, traps, tank batteries and gas gathering compressors, the Company uses ANSI/ASME Code B31.3, Chemical Plant and Petroleum Refinery Piping (see the Piping Manual).
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Pipeline Stations and Terminals Design and construction of piping at pump stations, compressor stations, and terminals should comply with Code B31.4 or B31.8, as appropriate. Former Chevron practice was to design piping for these facilities to the more conservative Code B31.3. It is entirely a local decision whether to continue this practice. For descriptions of piping components, and guidelines for mechanical design, layout and construction for piping at stations and terminals, refer to the Piping Manual, which covers Code B31.3 piping for hydrocarbon services, and utility and auxiliary piping involved in station and terminal facilities. Terminal facilities within a refinery are designed to Code B31.3, unless they are confined to a separate and defined pipeline area adjacent to refinery facilities.
420 Hydraulics Pressures required to move design flows through a pipeline system are calculated from the fluid properties, pipe diameter and line length. Pertinent fluid properties for basic hydraulic calculations are viscosity and specific gravity at the temperatures and pressures of the fluid in the line. These calculations indicate a range of feasible pipe diameters and tentative spacing of pump or compressor stations along the line. Section 430 should be reviewed as a guide for initially selecting pipe diameters for a particular system. As design becomes final, hydraulic calculations are refined to determine conditions for overpressure control during line shut-off and surges. The design flow, or line throughput rate, is established by the operating organization, which should define as closely as possible the expected maximum and minimum rates, and forecast future yearly throughput requirements. This information is critical in determining the most economic line size. Once line size is determined and pipe is selected, hydraulic calculations can be made to determine flows for variables in operating conditions, future expansion of system capacity by the addition of pump or compressor stations, and line capacity if the system is converted to different service.
421 Basic Pressure Drop Calculations The Fluid Flow Manual is a primary source of pressure drop data for most oils as well as water and natural gas. Refer to the following sections of it for guidance in making pressure-drop calculations: • • • •
400 Friction Pressure Drop 800 Surge Pressure 900 Pipeline Flow 1000 Fluid Properties
General hydraulics theory and development of formulas is covered in the Fluid Flow Manual, Section 400. The Fluid Flow Manual is recommended for both
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liquid and gas transmission lines, although pipeline handbooks and general hydraulics texts may also be used.
Oil and Water Lines at Ambient Temperatures Hydraulic calculations are straightforward for pipelines with a single fluid stock and little variation in viscosity throughout the line at any given time, as is the case with many of the Company’s field and transportation pipelines. Section 422 covers other situations; Section 932 discusses subsea hydraulics. Except for certain crude oils and heavy fuel oils whose viscosity is sensitive to temperature, the annual mean ambient air temperature may be used as the average flow temperature for buried lines. If available, ground temperature data is preferred. If seasonal variations are great, calculations should be made for winter and summer temperature averages. The effect of seasonal variations must be carefully evaluated. For crude oils it is necessary to know the pour point of the oil—the temperature at which viscosity of a cooling oil abruptly increases—to determine if special measures are needed to move the oil when ambient ground temperatures approach or fall below the pour point. An oil with pour point at or above the ambient temperature requires special treatment, such as a pour point, depressant additive, dilution with lighter stock, or a heated pipeline system. If ground temperatures are close to the pour point reliable data on ground temperature is critical. A program to collect this data in the initial phase of the project is recommended. Design Throughput. The design throughput of an oil pipeline is its average annual pumping rate in barrels per calendar day (BPCD). Capacity requirements given in barrels per day (BPD) should be construed as meaning BPCD. The design flow that a system must be capable of attaining to compensate for lost capacity from shutdowns and reduced flow conditions is given in barrels per operating day (BPOD). The ratio of BPCD to BPOD is the load factor (see Equation 400-1). A well-operated pipeline handling a single stock at any one time can be expected to have a load factor of at least 0.95. This figure should be used to arrive at the design BPOD rate from a given BPCD throughput unless special circumstances dictate a lower factor. BPOD = BPCD/Load Factor = 1.05 × BPCD for the usual oil pipeline system (Eq. 400-1)
In some areas BOPD and BWPD are common notations for barrels of oil and barrels of water per day. Do not confuse these with BPOD and BPCD. Preliminary Hydraulic Calculations. To set the inside diameter of a line for preliminary hydraulic calculations for cross-country oil pipelines, a pipe wall thickness of 0.250 inch can generally be used for lines up through NPS 30, 0.375 inch from NPS 30 to NPS 42, and 0.500 inch over NPS 42. Heavier wall thicknesses should be used for offshore pipelines (see Section 930). For liquid pipelines, pressure drop data from Section 400 of the Fluid Flow Manual can be developed and plotted as in Figure 400-1. Because pressure drop data will be interrelated with ground elevations, allowable line pipe, and valve pressures and
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pump discharge heads, pressures are expressed in feet of the fluid in the line as well as pounds per square inch (psi). Formulas to convert to pressure units of pounds per square inch, or vice versa, are: Ppsi =headft × 0.4328 × specific gravity headft = (2.311 × Ppsi)/specific gravity (Eq. 400-2) Fig. 400-1
Pressure Drop and Head Loss
Gas Transmission Lines Flow calculations for gas transmission lines are covered in Section 400 of the Fluid Flow Manual. Detailed design development for a high-pressure (ANSI 600# or higher) gas transmission system includes hydraulic analysis of transient pressure and temperature conditions in the pipeline, and of two-phase flow resulting from pressuring of the line from a high-pressure source and depressuring, whether intentional or resulting from line rupture. Low temperatures caused by autorefrigeration during depressuring can significantly affect fluid properties (and influence material selection). Effects of normal flow variation that stem from the delay in system response at other locations must also be considered. Unless seasonal ambient ground temperature variations are extreme, the annual mean ambient air temperature adequately approximates the average flow temperature for long buried lines. For short lines, gas temperatures of the compressor station or wells may be considerably higher than ambient, and should be taken into account. The design annual throughput of gas lines is usually expressed in standard cubic feet per calendar day (SCFCD). Seasonal throughput for gas lines can vary signifi-
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cantly because of demand fluctuations and should be considered in setting the load factor that determines design flow rate, expressed in standard cubic feet per operating day (SCFOD).
422 Special Hydraulic Conditions Situations involving special hydraulic calculations follow, along with sources of guidance for appropriate calculation methods. Specialists in the Materials and Engineering Analysis Division of the Engineering Technology Department can provide further guidance and reference to similar systems. Situations covered in this section include multistock lines, hot oil pipelines, non-Newtonian fluids, mixed phase flow, and supercritical fluids.
Multistock Flow Calculations for crude lines handling a range of specific gravities and for product pipelines must allow for (1) the presence in the line of stocks with differing physical properties and (2) deliveries from the line at several points. The latter considerably reduces the volume of products going through to the terminal compared to throughput at the initial station. To avoid excessive mixing of products, the line flow should be within the turbulent region. At low flow rates, batching pigs can be used to minimize interface mixing. Slurry pipelines usually operate within a narrow range of flow rates—with the minimum rate adequate to keep solids in suspension and the maximum low enough to avoid excessive abrasion and erosion. A wide range of net solid throughput is achieved by frequent batching of slurry and water, or by displacing slurry with water at intervals, then shutting down and restarting. To establish maximum and minimum pressure drops, calculations should be made for slurry alone and water alone.
Hot Oil Pipelines If it has a high pour point or very high viscosity, a waxy crude oil or heavy oil must be heated before it enters the pipeline, and must not be allowed to cool below a minimum temperature before it reaches the terminal or an intermediate reheating station. Maximum oil temperature entering the line is usually limited by allowable temperature for the pipe coating (see Section 340 of this manual and the Coatings Manual. See Section 900 of the Fluid Flow Manual for calculations for friction heating and external heat transfer coefficients. Heat traced pipeline electrical heating systems attached to the pipeline, or insulation on the pipe may be warranted to maintain oil temperatures above the allowable minimum. Design guides for these systems are not covered in this manual, though some Company installations are listed in Section 370. A planned shutdown procedure for hot oil pipelines, either for maintenance or emergency shutdown, usually involves displacing the line with a lighter stock. Hydraulic calculations for a multistock situation should therefore be made for both displacing and restarting.
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Non-Newtonian Fluids Non-Newtonian fluids should be handled on a case-by-case basis. Their viscosity characteristics change significantly with flow rate and as a result of the fluid’s hydraulic and temperature “history.” Pretreatment, heating, addition of pour depressants or flow improvers, and a combination of strategies have been used successfully to facilitate pumping of these oils through pipelines. Line restart after shutdown is likely to require special investigation and study. Refer to the Materials and Engineering Analysis Division of the Engineering Technology Department for assistance on any pipeline system involving an oil or slurry having non-Newtonian properties. See also Section 1000 of the Fluid Flow Manual for a discussion of non-Newtonian fluids.
Mixed Phase Flow Field production systems often have mixed phase flow in lines handling oil, water, and gas. For two-phase flow (liquid-gas) refer to the Fluid Flow Manual, Section 400, or use the PIPEFLOW-2 computer program (see the Fluid Flow Manual, Section 1100 and Appendix E). These facilities usually have a slug-catcher at the line terminus.
Supercritical Fluids A supercritical fluid is a gas compressed to a pressure greater than the saturation pressure, at temperatures greater than the critical temperature. The critical temperature is the temperature at which the gas cannot be liquified at any pressure. Supercritical fluids behave like compressible liquids, or gases as dense as a liquid. Pipeline transport of carbon dioxide as a supercritical fluid has become more common in recent years. The viscosity of supercritical CO2 is very low, but the density varies significantly with pressure, temperature and amounts of other gases present as impurities. Moreover, changes in pressure result in temperature changes. Hydraulic calculations can be made with the PIPEFLOW-2 computer program (see the Fluid Flow Manual, Section 1100 and Appendix E) incorporating density data for pressures and temperatures along the line. Calculations for supercritical hydrocarbons can be handled in a similar manner.
423 Hydraulic Profiles When a pipeline route has been determined, elevation data and hydraulic pressure drop gradient data can be plotted in a hydraulic profile. The hydraulic profile can be used to establish line size and pump station spacing, and to show allowable pipe pressures (see Sections 433 and 434). Data on pipe grade and wall thickness, pipe coating, and locations of block valves, scraper trap manifolds, and major river crossings can conveniently be incorporated on the same plot. Hydraulic profiles plot the following data: •
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Ground elevations along the route, including at least the significant high and low points, and pump station and branch line locations
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•
The approximate terminal pressure (in feet of head) at the end of the line (or section of line) required, for example, for the fluid to pass through terminal manifolding and piping and into tankage at design flow
•
Hydraulic gradient data, in feet of pressure drop per mile at design flow rate (or maximum and minimum rates), for one or several pipe sizes
A basic plot of this data is indicated in Figure 400-2. A hydraulic control point is a high-elevation point that governs the inlet head for its section of line. Often, hydraulic control points are encountered, and the hydraulic gradient must clear the ground elevation control point. Two situations may result as indicated in Figure 400-3: (a) The hydraulic gradient is continued to the end of the line, resulting in a residual pressure at the end of the line, for which back pressure control must be provided. (b) Without back pressure control, a length of line will flow only partially full, in what is called a cascade or slack-line condition. Fig. 400-2
Hydraulic Gradients
Fig. 400-3
Hydraulic Profile: Backpressure Control
A slack line should be avoided because it results in erratic correlation of the line input and output meters, which makes leak detection by metering instrumentation impossible. For products pipelines the volume of interface mixture between successive products is uncontrollable in a slack-line, and product mixing is severe in downhill sections downstream from the control point. In rare instances slack-line operation may be considered so that back-pressure control is not required. The actual pressure in the pipeline at any point along the route equals the difference between the hydraulic gradient and the ground elevation (see Figure 400-4). With multistock flow where two or more stocks having appreciably different viscosities and specific gravities are in the same line, higher pressures may develop
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at intermediate points along the line than if there were only one stock. In Figure 400-5 the trailing stock has the lower viscosity and, therefore, a less steep hydraulic gradient than the leading stock. With pump station and terminal discharge pressures P1 and P2 fixed, the locus of pressures at the interface between the stocks is arched upwards. The pressure H in feet of stock A at a distance of x miles along the line of total length L is given by: E 1 + H 1 – ( R E 2 + H 2 ) + ( R – 1 )E x H = R ( E 2 + H 2 – E x ) + --------------------------------------------------------------------------------------x 1 + r -----------L–x (Eq. 400-3)
where:
(specific gravity stock B) R = -------------------------------------------------------------( specific gravity stock A ) ( hydraulic gradient stock A ) r = -------------------------------------------------------------------( hydraulic gradient stock B ) H2 = 2.311 P2 / (sp. gr. stock A) in feet of stock A (not stock B)
Fig. 400-4
Hydraulic Profile: Line Pressure
Fig. 400-5
Hydraulic Profile: Multistock Flow
Note that while the two hydraulic gradients vary, since the throughput will not be constant for fixed station and terminal pressures, their ratio is essentially constant. If there are injection or take off points along the line, so that flow in the main line is increased or decreased, the different hydraulic gradients need to be plotted in succession along the line for the changed flow rates.
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430 Line Sizing Although different regulations and codes are involved, the following method for sizing long cross-country pipelines for liquid hydrocarbons is also applicable to natural gas transmission lines. It also applies to other pipelines which involve special conditions. There will, however, be significant differences in the facilities and economic factors. This section is concerned with the pipeline itself and pumping facilities, not field gathering systems, storage at either end, or terminals. It helps determine the most economic system for a particular set of conditions; based on order-of-magnitude cost estimates for the installed systems and for variable operating expenses. Preliminary design and cost estimating are not two separate and independent procedures; they are closely interrelated and must progress concurrently. Unlike process plant piping, a pipeline system is extremely flexible and a given throughput can be transported between two given points over a variety of routes and through different sizes of pipes. The range of possible pipelines is almost limitless, even within the restricted scope of this guide. Consequently, the parameters, guidelines, design criteria and estimating criteria presented here are not applicable in all cases. However, they provide a starting point for a logical and realistic approach to the problem. Note Short Lines. Relatively short lines such as field flow lines and gathering lines normally do not require the line sizing procedure covered in the major part of Section 430. Refer to Section 438 below for guidelines on sizing short lines.
431 Elements to Determine an Economic System To size a pipeline, one must identify the significant elements necessary to evaluate and compare alternatives, estimate costs, and perform an economic analysis of the alternatives. Cost differentials for alternative line sizes must include the following elements: • • •
Annual throughput rates for the period selected as the analysis basis Pipeline and pumping facilities with capacity to handle the throughput rates Pumping energy to transport the stock at throughput rates
Alternative forecast throughputs often consist of a most-likely case, and less likely cases at lower and higher rates. Sensitivity analyses should be made to determine the effects of the other cases—or a composite case—given the line size selected by the most-likely case analysis. Sections 432 and 433 show how to establish the pipeline and pumping facilities for the alternative line sizes, while Section 434 covers order-of-magnitude cost estimates for the facilities. Section 435 discusses order-of-magnitude estimates for operating cost (for pumping energy). (Data presentation and calculations for multiple alternative designs and conditions can be greatly facilitated by using a computer spread sheet such as Lotus 1-2-3.)
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Section 436 discusses economic analysis for line sizing. Sensitivity analyses may be in order if the estimating basis for items such as construction costs and pumping energy costs is uncertain. In some situations, other elements may affect economic evaluation of alternatives, such as: •
Line routing
•
Heated-line facilities, heating method, initial line temperature, pipe insulation, and heating energy
Sensitivity analysis may be appropriate if alternative routes involve uncertainties in comparative construction costs or costs for permitting, right-of-way acquisition and damages, or if heated-line systems involve uncertainties in line heat losses and heating energy cost.
432 Preliminary Pipe Selection and Line Operating Pressure Approximating Line Size An initial approximation for pipe size for liquid hydrocarbon pipelines can be made using the curves in Figure 400-6. These curves were not derived by a comprehensive study, but represent judgment based on Company and others’ experience over a period of years. Estimates should be made for at least three alternative pipe sizes. Fig. 400-6
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Design Flow vs. Nominal Pipe Size
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Pipe Wall Thickness A preliminary determination of pipe wall thickness(es) is necessary since the cost of pipe is based on tonnage, a function of diameter and wall thickness. A more comprehensive discussion of pipe stress and wall thickness calculations is given in Section 440. The basic pipe hoop stress formula relating internal pressure, pipe wall thickness, pipe diameter and stress value, as given in Section 404.1.2 of Code B31.4 for liquid lines, is: Pi D t = --------2S (Eq. 400-4)
where: t = pressure design wall thickness, in. Pi = internal design gage pressure, psig D = outside diameter, in. S = allowable stress value, psi Code B31.4, Section 402.3.1, establishes the allowable stress value S; Code B31.4, Table 402.3.1(a), tabulates allowable stress values for pipe of various specifications, manufacturing methods and grades. As a preliminary design basis for line sizing, API Specification 5L Grade X60 pipe is suggested, for which S = 0.72 x 60,000 = 43,200 psi. For oil lines, which normally do not require any corrosion allowance, the nominal wall thickness tn equals the pressure design wall thickness t. The hoop stress formula then becomes: Pi D t n = ----------------86,400 tn or P i = 86,400 ⋅ ---D (Eq. 400-5)
Pipe wall thicknesses commonly manufactured are given in API SPEC 5L, Section 6, Table 6.2.
Minimum Handling Thickness Pipe wall must be thick enough to resist damage and maintain roundness during construction handling and welding. Other factors affect pipe wall thickness, but for line sizing suggested minimum thicknesses are as follows:
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Min. Wall, in.
4 – 12
0.188
14 – 24
0.219
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NPS
Min. Wall, in.
26 – 30
0.250
30 – 36
0.281
36 – 40
0.312
42 – 48
0.375
Other Pressure Level Factors Mechanical limits on pump discharge pressures and ratings for valves and flanges also influence maximum design pressure levels for the pipeline. Maximum operating pressure (MOP) ratings for carbon steel pipeline valves conforming to API Spec 6D and valves and flanges conforming to ANSI Standards B16.34 and B16.5 often determine maximum pressure for pipeline design. Although valves and flanges do not usually comprise a significant portion of the system cost, going to the next higher rating to provide for only a slight increase in line pressures would not be incrementally economic. Section 402.2.1 of Code B31.4 states that pressure ratings shall conform to ratings at 100°F in the material standards. Accordingly, MOP’s for valves and flanges are as follows: Class
Valves API 6D MOP, psi
Flanges ANSI B16.34 ANSI B16.5 MOP, psi
300
720
740
600
1440
1480
900
2160
2220
1500
3600
3705
433 Hydraulic Profiles and Pump Station Locations To plot hydraulic profiles for the feasible alternatives pump discharge pressures, allowable pressures for pipe wall thicknesses, and pressure ratings for valves and flanges must be converted to feet of fluid (headft = 2.311 x Ppsi/specific gravity). Developing reasonable hydraulic profiles may require several trials, but by using parallel rules gradients can be drawn rapidly and adjustments made to develop alternative layouts. The principal characteristics of a reasonable layout are as follows:
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•
Discharge pressures at pump stations are nearly balanced. Allow about 50 psi above the bubble point for the suction to each station
•
Hydraulic gradients pass close to control points, minimizing the pressure differential needed for back pressure control
•
Gradients for expansion steps in capacity should be drawn to demonstrate the need for future intermediate pump stations to provide increased throughput. The corresponding throughputs should be shown
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Where back pressure control will cause high pressures in the pipeline beyond the control point, perhaps necessitating heavier wall pipe, two remedies are available: •
Install one or more pressure reducing stations to dissipate the pressure and bring the gradient closer to the ground elevation
•
Reduce the pipe diameter to steepen the gradient
The second alternative may seem to be an economical solution, but is not suggested for preliminary estimates. The smaller diameter is likely to be a bottleneck in capacity expansion of the pipeline. However, it should be considered in a final design stage. A scraper trap station will be needed at the point of size change so that different size inspection pigs can be run. A power-recovery turbine should also be considered as an alternative to wasting power through a control valve. Figure 400-7 shows gradients for a reasonable line size, with station locations, for: •
An initial design throughput requiring an intermediate pump station (otherwise pump discharge head at the initial pump station would be excessive) and a pressure-reducing station to reduce line pressures upstream of the terminal.
•
Future system expansion by addition of a pump station, resulting in a new gradient and throughput rate. Pump discharge head at the intermediate pump station is higher, but now matches the initial station discharge head. Although the pressure-reducing station is not needed at the future maximum throughput, pressure-control facilities will still be needed there and at the terminal to prevent overpressuring the line at low flow rates in the lower-elevation section and in the terminal piping.
Figure 400-7 also indicates the effect on gradients of a reduced size pipe as an alternative to the pressure-reducing station. Figure 400-8 shows gradients for a design throughput for three alternative line sizes, and corresponding station facilities. Pipe allowable pressures, determined by calculations described in Section 432 and converted to head in feet of fluid, should also be shown on the hydraulic gradient diagram, as indicated on Figure 400-9. The dashed line indicating the calculated pipe allowable pressure for a particular wall thickness parallels the ground profile. In Figure 400-9, for the section of the pipeline between the initial pump station and the intermediate pump station, pipe with wall thickness “a” is needed for a distance downstream of the initial pump station, but at higher elevations, this allowable pressure rating is greater than required. Therefore, in the following section, thinner wall pipe (“b” and “c”) is satisfactory. If the line were to be blocked while pumps were running, the gradient at no flow would be horizontal, indicated as “pump shut-off.” Pipe wall thickness should be selected so that pipe allowable pressures are equal to or greater than line pressures under pump shut-off conditions. In Figure 400-9, only wall thickness “e” fails to meet this criterion. In this example, wall thickness “e” represents a considerable savings in weight and dollars compared to the wall thickness required for the shutoff condition against intermediate station pumps. In many cases, wall thicknesses of older pipelines were telescoped; that is, pipe wall thickness for successive sections of line were only adequate for line pressures at flow conditions, not for a blocked line situation. At a time when the higher
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Fig. 400-7
Hydraulic Profile: Initial and Future BPOD
Fig. 400-8
Hydraulic Profile: Alternative Line Sizes
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Hydraulic Profile: Nominal Wall Thickness
strength grades of pipe were not available, appreciable savings could be realized by telescoping. Telescoping is also done by using lower grades of pipe. However telescoping introduces the hazard of overpressuring the line under pump shutoff conditions and often limits system expansion by adding intermediate pump stations. Telescoping should generally be avoided. Pumping horsepower requirements for the various alternatives can now be calculated (Equation 400-6). For preliminary estimates a pump efficiency of 70% can be used for centrifugal pumps in pipeline service. For reciprocating pumps, use 90%.
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Q bpod ⋅ H ft ⋅ SG bhp = ---------------------------------------136,000 ⋅ PE Q gpm ⋅ P psi = ---------------------------1714 ⋅ PE (Eq. 400-6)
where: bhp = pump brake horsepower Qgpm = flow rate, gpm Qbpod = flow rate, BPOD H = pump discharge head, ft SG = specific gravity P = pump discharge pressure, psi PE = pump efficiency Other features can be indicated on the hydraulic profile, such as pipe coatings, major river crossings, line valves, scraper trap manifolds, cased crossings, and areas with special construction problems.
434 Order-of-Magnitude Estimates for Investment Costs For line sizing, order-of-magnitude investment cost estimates are necessary for the overall systems, alternative line sizes and, possibly, alternative routes. Cost estimating data are not included in this manual, but sources of cost information are suggested). Besides Company sources, cost data is periodically published in the Oil and Gas Journal and other trade magazines. Costs that are functions of pipe size, number of pump stations and installed pumping horsepower are more important than costs that are essentially independent of line size. Cost analysis may also be required for selection of route alternatives, involving costs that are functions of line length, terrain, permitting and right-of-way problems, line access, construction damages, etc. Line sizing must be known to make project cost estimates, and is therefore done in conjunction with cost estimates for feasibility studies and appropriation requests. Line sizing estimates should focus on the elements of cost that constitute the bulk of the investment cost differentials for the alternatives under consideration. Usually the pipeline itself represents 75% to 85% of the investment, and pump stations, terminals, etc., account for the balance. Consequently, a substantial error in estimating the cost of pump stations will have a minor effect on the overall estimate. The two major elements in the cost of a pipeline are the cost of the pipe and the cost of construction. The cost of the pipe can generally be determined easily and quickly; therefore, the major portion of the time available should be directed toward developing a construction cost.
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Pipe Cost The cost of the pipe generally represents 25% to 50% of the total line cost, and the use of a reliable cost will go a long way toward assuring a realistic total estimate. For mill runs purchasing can usually obtain informal quotes from steel mills, based on total tonnage required, within a week. The price can be FOB mill or FOB destination. In the former case, freight charges from mill to destination must be obtained. European and Japanese sources should be included, particularly for foreign projects. Experience has shown that market fluctuations make it risky to use pipe costs from previous jobs and escalate them by an index. In calculating the tonnage of steel required, allow for heavier wall pipe for river and highway crossings. Also allow for waste and for the difference between the horizontal length of the line and its actual slope length. Even for lines laid through mountainous terrain, an allowance of 1% to 2% is usually adequate. For short producing field lines, both allowances combined (wastage and slope length) are about 5%.
Coatings Although final coating selection involves a thorough study of alternatives and design conditions, order-of-magnitude coating costs for line sizing can usually be based on the following: •
For normal soils, preferably plant-applied fusion-bonded epoxy or extruded polyethylene
•
For hot lines, plant-applied extruded polyethylene up to 150°F, fusion bonded epoxy up to 200°F
•
For wet or corrosive soil conditions, plant-applied extruded polyethylene, or fusion-bonded epoxy
Reference should be made to Section 340 of this manual and to the Coatings Manual for full descriptions of these coatings. Purchasing can usually obtain informal quotes from coating material suppliers or plant applicators within a few days. When the coating is plant-applied the application cost as well as the material cost is included. The cost of unloading the bare pipe from the delivery cars and reloading the coated pipe onto rail cars or stringing trucks and the cost for shipping coated pipe to the job should be included. Where circumstances favor coating applied over the ditch, the labor cost of application is part of the construction contract. When estimating the material cost allowances should be included for waste (15% to 20%) and for shipping costs.
Miscellaneous Materials Block valve installations, scraper traps, cathodic protection equipment, line markers, casing pipe and other items of material may be required. It is generally accurate enough to estimate all these items together as a percentage of pipe cost. The figure should be at least 5%; for short lines or lines with an unusual number of appurtenances the figure can be as high as 10%.
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Taxes and Duties Applicable sales or use taxes must be determined and included as a part of the material cost. In addition, foreign projects generally entail added costs for import duties, permits and custom clearances. This can be a very significant item.
Pipeline Construction A realistic estimate of the construction cost requires judgment in evaluating such factors as terrain, weather, availability of labor and competent welders, access, and remoteness from living and service facilities. In preparing an order-of-magnitude estimate it is not possible to evaluate these individually, but their composite effect on costs must be appraised. The basic construction cost covers clearing and grading, stringing pipe, ditching, welding, application of coating as required for the particular coating system, lowering, backfilling, cleanup and testing. It is generally estimated on the basis of dollars per linear foot. Unit construction costs for many existing pipelines are available from various sources, such as Company project cost statements and magazines such as the Oil and Gas Journal which publish data on pipeline projects. Methods for estimating basic construction cost include the following: •
Review available data to find a similar size line crossing terrain similar to the area in question. Use judgment to make adjustments for the particular conditions
•
When time is available, consult with several pipeline contractors and obtain informal estimates. Their figures should be realistic, particularly if they have actual construction experience in the same geographical area
•
Develop a daily cost for the labor and equipment needed for a pipeline spread. An estimate is then required of the rate of construction progress over the route to determine the total length of the construction period. The daily spread cost multiplied by the days to construct represents the construction cost. The daily spread cost must include items such as contractor’s overhead and profit. On foreign jobs there may be an additional lump sum to cover mobilization
A special situation occurs if the pipeline is located in city or suburban streets. The contractor will be required to limit his daily operations to a short distance. He may not be permitted to leave any ditch open overnight. Delays are likely on account of unanticipated underground interferences. He will therefore use a city spread that is much smaller in terms of the amount of equipment and number of men than the normal pipeline spread. Construction progress will be measured in terms of 500 to 1500 feet per day as compared to 5,000 to 10,000 feet per day for open country terrain. Also, the removal and replacement of paving will be a significant cost item. Installation costs for major river crossings, line valves and scraper traps, casing, cathodic protection stations, and pipeline markers are generally estimated on a lump sum per unit basis. Cost data for these items is available from past Company jobs and the published data mentioned previously. By far the largest items are river crossings, which require special equipment and involvement with government agen-
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cies. If possible, contractors should be consulted in developing the lump sum cost for a major river crossing.
Pipeline Technical Services Pipeline technical services include the following: •
Project management
•
Design engineering and drafting
•
Services for purchasing, inspection and expediting, governmental and public relations, etc.
•
Outside specialist technical services for environmental surveys; geophysical, geotechnical, hydrographic, hydrological and meteorological surveys; radiographic inspection; etc.
•
Route and land surveys, including aerial photography
•
Field supervision and inspection, including travel and living expenses
For order-of-magnitude estimates it suffices to lump all these technical services together and estimate their total cost as a percentage of total pipeline material and construction costs. The percentage will generally be 5% to 20% depending on the size and complexity of the pipeline. Experience on past Company jobs should be used as a guide in determining the percentage to use.
Permitting, Right-of-Way and Land Acquisition Permits and rights-of-way are needed for the pipeline, and land must be acquired for stations and similar facilities. These costs are usually very difficult to estimate, and all available sources should be consulted— past projects, published data, and, above all, Company land specialists and local operating organizations. Charges and expenses for agents and personnel involved in developing land information and acquiring rights-of-way and land are included in acquisition costs. For order-ofmagnitude estimates, permitting and right-of-way acquisition costs are usually estimated in dollars per mile, and land for station and similar facilities in dollars per acre.
Construction Damages and Restoration Construction damages pertain to the present use of the land, and the extent to which construction will damage crops or developments. Although route restoration, such as revegetation, is considered as a pipeline construction cost, the extent and type of restoration is usually determined by the special conditions of the permits and rightsof-way. Costs for construction damages and restoration are usually estimated in dollars per mile for the specific sections of line affected.
Pump Stations For the preliminary estimate, four major decisions must be made regarding pump stations:
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Type of pump. Although centrifugal pumps are the usual choice, reciprocating pumps may be indicated for high viscosity stock because of the centrifugal pump’s low efficiency in this service. The Pump Manual provides criteria for choosing a pump and the Mechanical and Electrical Systems Division of the Engineering Technology Department can give advice
•
Type of driver. Electric motors are the usual choice unless electric power is unavailable or some other fuel, such as natural gas, is available at a significantly lower cost. Diesel engines can be modified to burn crude oil but this generally requires a substantial investment in equipment to filter and condition the crude oil. Turbines are used in remote areas where electric power is unavailable because they require fewer auxiliary facilities, have lower maintenance requirements, and are adaptable to remote control
•
Type of operation. Remote operation of some or all intermediate pump stations should be considered. This is common practice in the United States, where labor costs are high. It is also desirable wherever nearby housing and associated facilities are unavailable
•
Amount of standby capacity. The initial design of a line usually must consider standby capacity to assure the desired line operating factor. Standby capacity is less necessary in subsequent expansions as the consequences of the loss of a pump or even a station become less severe. The total installed horsepower is the basis for estimating investment cost
The investment cost of pump stations can be estimated by breaking the facility into components, as follows: •
Fixed cost. This covers items that are largely independent of the amount of horsepower to be installed. These are land, site development, buildings, living quarters and maintenance facilities. These can be estimated as a lump sum applicable to each station
•
Variable cost. The remaining station facilities, such as pumps and drivers, manifolding, instrumentation, and power supply are related to the size of the station. These can be estimated on the basis of dollars per installed horsepower. This figure will also vary with the type of pump and driver. Diesel stations cost more than electric stations; reciprocating pump stations cost more than centrifugal pump stations
•
Technical services. The fixed cost plus the product of variable cost times installed horsepower equals the total station cost. These unit costs must include an allowance for the technical services required to design and construct the station, generally 10% to 25% of the total station cost
Other System Facilities Pipeline system facility costs not required for line sizing include the following: •
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Supervisory control and data acquisition (SCADA) facilities and associated metering, instrumentation, and control facilities
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Communications
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Station tankage
•
Cathodic Protection
Contingency, Escalation Contingencies must be provided for, including costs which have been overlooked and factors contributing to cost that have not been realistically evaluated. The percentage allowed for contingencies depends on the time available to prepare the estimate and the confidence in the figures developed. The minimum contingency should be 10%, although 15% is normally used and a higher figure may be appropriate. If the pipeline is an unusually large project, requiring two or three years to design and construct, an allowance for future escalation should be included. If no escalation is included, this should be clearly stated in the estimate.
435 Order-of-Magnitude Estimates for Operating Costs The operating cost component most important for comparing alternatives in line sizing is the electric power or fuel required for pumping. Reduction in total pumping horsepower and, possibly, the number of stations, form the basis for justifying a larger line. The cost of electric power is based on a rate schedule for demand and energy charges. Where a schedule is not available, an equivalent must be developed, on as sound a basis as possible, in conjunction with resources of the operations organization. Where the drivers use the same gas or oil being transported in the line, the cost is based on the value of the gas or oil at the point of consumption. The objective is to develop a cost for pumping power per horsepower per year, or per kilowatt hour per year. Other operating costs, significant for comprehensive economic analysis but not for line sizing analysis, include the following: • • • • • •
Direct labor for station operation Pipeline maintenance supplies, labor, and equipment Pump station and terminal maintenance supplies, labor, and equipment Property taxes Management and administration Services, such as communications
436 Economic Analysis for Line Sizing The objective of an economic analysis for line sizing is to establish the comparative attractiveness of different line sizes. Usually the system with the smallest feasible line size requires the smallest investment. The first alternative that should be analyzed is the system with the next larger line size, which costs more to build but
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less to operate for a given throughput. Where Company-owned stock is used to fill the line initially, the value of the line fill should be added to the estimated system investment. The analysis requires calculation of the incremental cost of building the larger line and the incremental savings realized in operating it over the forecast life of the pipeline. Operating costs may vary over time for both the base and alternate cases if the throughput varies (e.g., for an oil field with increasing, then declining production rates), or if power costs change (due to energy costs, inflation, etc). If an increase in throughput requires adding pump stations or looping the line, the additional investment costs must be included at the time these facilities are required. Cost elements which are the same for both cases (the incremental cost is zero) can be ignored for this comparative analysis. An economic analysis computer program such as CASHFLO (sponsored by Corporate Planning & Analytical) can calculate a rate of return (ROR) and payout (in years) for the incremental cost of the larger line based on the annual savings in operating (pumping) costs. CASHFLO also incorporates the effects of depreciation and taxes on the annual cash flow. If the ROR on the increment meets or exceeds current standards for this type of investment, then the larger line size is “economic.” This analysis can be repeated for successive line sizes until the ROR no longer justifies the incremental investment.
437 Improving Cost Estimates This section recommends additional design and estimating work useful in upgrading order-of-magnitude estimates and making designs final. See also the design development guidelines contained in other sections of this manual.
Route and Profile The route and profile should be reviewed in detail. Detailed maps should be obtained, if available. Taking a reconnaissance trip over the route is important. The group making this trip should include someone familiar with right-of-way acquisition, and environmental permitting, a Company engineer or contractor representative familiar with construction problems, and the Company project engineer. They may suggest desirable route changes and will obtain first-hand knowledge useful in estimating permitting, right-of-way acquisition, and construction costs more realistically. During the trip information should also be gathered on pipe storage and handling areas, construction camp sites, weather, labor availability, local regulations, import requirements, availability of services and supplies, etc. Although some of these items are not important on domestic projects, they are critical cost factors on foreign projects. Finally, the route should be analyzed from the viewpoint of construction progress. What rate of pipe laying can be expected? Which sections are the most difficult? Will construction be limited to a certain time of the year? What are the river conditions that will dictate design and construction of crossings? How much preparation
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work is needed? Must access roads be constructed? Are there environmental and ecological considerations that will affect construction progress and timing?
Hydraulics The fluid characteristics and volumes used in the preliminary design should be reviewed and confirmed. The viscosity and pour point of a crude oil must be accurate; if there is any doubt, samples should be obtained and a pumpability study performed. Care should be taken to assure that the sample obtained is truly representative. The volumes to be transported, particularly the forecast of future requirements, should be reviewed and confirmed. A forecast of future throughputs is essential.
Pipe and Coating Bids should be obtained for the pipe. These may be formal or informal, but should be based on specific requirements. At the same time, such items as freight and duties must be considered in detail. A proposed selection of the type of coating must be made, and applicable costs developed. Finally, a detailed list of other material requirements should be made and priced as accurately as possible.
Pipeline Construction Improving the estimate for pipeline construction should have the highest priority. Making a reconnaissance trip is particularly important, providing the engineer with a first-hand appreciation of the various conditions that will determine the construction cost. Preferably, one or more contractors should be asked to inspect the route and submit informal figures on construction costs, but it is best if the engineer conducts the inspection trip separately with each contractor. Contractors are generally willing to provide this service because it gives them an early look at a potential project. Variations in the figures submitted by different contractors may reflect different evaluations of construction difficulties, or a difference in their interest in doing the job (or in their need for work). It is difficult but necessary to assess the effect of the overall construction market on bids. The engineer should make an independent estimate of construction costs after he has seen the terrain and talked to contractors about the equipment and labor force they would use. Construction elements such as river crossings, block valves, scraper traps, and cathodic protection facilities, should be re-estimated in light of any information that has been developed. The estimating methods and sources of cost data are the same ones discussed in Section 435. The daily spread method described there is particularly useful.
Technical Services To develop a detailed estimate for each technical service element it is first necessary to prepare a schedule and a Company manpower forecast for the design and construction phases of the project.
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The construction period is fixed by the availability of pipe and the completion date. This dictates the number of spreads required for the job, which, in turn, affects the number of Company personnel assigned to the field for supervision and inspection. Engineering and drafting. In estimating the cost of engineering and drafting for design, include the time already spent on preliminary estimates and feasibility studies. Purchasing and expediting. The percentages of material costs to be used in calculating purchasing, inspection and expediting burdens should be defined. Specialists. A schedule and contracting plan for outside specialists should be made, and the anticipated scope of work for each defined. Reference to previous projects, informal discussions with technical service contractors, and consultation with Company organizations involved in environmental affairs and technical investigations are recommended.
Pump Stations, SCADA, Communications, Etc. A piping and instrument diagram (P&ID) and plot plan should be prepared for each pump station. With these, a detailed estimate can be made in the same way as for process plants. Material and equipment is priced out and the construction cost is estimated as a percentage of each material category. Project cost statements on past projects will provide guidance on typical percentages. Technical services should be estimated as described above.
Permitting, Right-of-Way and Land Acquisition After the route reconnaissance trip, a schedule and scope for permitting, right-ofway and land acquisition should be developed, and detailed advice on costs solicited from local Company Land Department people. It is usually difficult to develop an accurate estimate until the acquisition of right-of-way is well along. Be conservative: common sense is likely to produce a figure that is too low, because landowners often do not use common sense in granting rights of way. Costs for preparation and processing of an Environmental Impact Report (EIR) should also be estimated.
438 Sizing of Short Lines As explained at the beginning of Section 430, the preceding sections apply to longdistance cross-country oil pipelines. Sizing of short lines (say, under 10 miles) such as field flow and gathering lines is normally much simpler for the following reasons:
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Route selection is straightforward.
•
The terrain usually does not have large elevation differences.
•
Throughput forecasts are probably better defined.
•
Only one stock at a time is in the line.
•
No intermediate pump stations are required.
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Cost elements are not as complex and are limited to differentials for pipe and coating, pipeline construction, pump station installed horsepower, and operating power costs. All other costs are not significantly affected by pipe size or pumping requirements.
On short lines attention must still be given to: •
Fluid properties, particularly if the temperature entering the line is higher than ambient, as from a production wellhead or gas compressor, and the fluid is cooled in the pipeline. See the Fluid Flow Manual, Section 900.
•
Hydraulic calculations and hydraulic profiles for alternative line sizes and corresponding pumping requirements. Note that pumping may not be required if adequate initial pressure is available. See the Fluid Flow Manual, Section 400.
•
Economic analysis involving pipeline and pump station costs, and operating power costs using criteria suitable for local conditions.
440 Line Design 441 Pipe and Coating Selection Section 430 establishes line size based on a preliminary choice of pipe grade and coating, and wall thickness. Further studies are needed to make final selection of pipe and coating for the length of the pipeline. Selection must meet Code B31.4 or B31.8 requirements, and will be influenced by economics and timely availability of materials. See Sections 310 and 630 regarding pipe and welding. Generally, economics will dictate use of the higher grades of line pipe, with resultant thinner wall and lower tonnage; the effect of incremental cost per ton for the higher grades is small compared to reduced tonnage of pipe. Also, consideration must be given to providing sufficient wall thickness to resist mechanical damage and structural flexing in handling during construction. If Grade X70 and higher pipe is considered (or for sour service Grade X60 and higher) consultation with the Materials and Engineering Analysis Division of the Engineering Technology Department is suggested.
442 Pipe Stress and Wall Thickness Calculations for Liquid Pipelines per ANSI/ASME Code B31.4 The following sections of Code B31.4 Chapter II (Design) are particularly important for pipeline design: •
Part 1, Conditions and Criteria – –
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Section 401, Design Conditions Section 402, Design Criteria
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•
Part 2, Pressure Design of Piping Components – –
Section 403, Criteria for Pressure Design of Piping Components Section 404, Pressure Design of Components
Allowable Pipe Stresses Section 402.3.1(a) of Code B31.4 establishes the allowable stress value S for new pipe as: S = 0.72 × E × SMYS (Eq. 400-7)
where: 0.72 = Design factor based on nominal wall thickness tn. In setting this design factor, the code committee gave due consideration to and made allowance for the underthickness tolerance and maximum allowable depth of imperfections provided for in the specifications approved by Code B31.4 E = Weld joint factor per Section 402.4.3 and Table 402.4.3 of Code B31.4. For pipe normally considered for new lines, E = 1.00 SMYS = Specified minimum yield strength, psi Although mill tests for particular runs of pipe may indicate actual minimum yield strength values higher than the Specified Minimum Yield Strength (SMYS), in no case where Code B31.4 refers to SMYS shall a higher value be used in establishing the allowable stress value; (Section 402.3.1(g) of Code B31.4). Table 402.3.1(a) of Code B31.4 tabulates allowable stress values for pipe of various specifications, manufacturing methods, and grades, based on the above, for use with piping systems within the scope of Code B31.4. Sections 402.3.1(b),(c), and (d) of Code B31.4 cover allowable stresses for used (reclaimed) pipe, pipe of unknown origin, and cold-worked pipe that has subsequently been heated to 600°F or higher. Section 402.3.1(e) limits allowable stress values in shear and bearing. Section 402.3.1(f) limits tensile and compressive stress values for pipe and other steel materials when used in structural supports and restraints. Section 402.3.2 of Code B31.4 covers allowable stress values due to sustained loads and thermal expansion for the following stresses:
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Internal pressure stresses. The calculated stresses due to internal pressure shall not exceed the applicable allowable stress value S determined by 402.3.1 (a), (c), or (d) except as permitted by other subparagraphs of 402.3.
•
External pressure stresses. Stresses due to external pressure shall be considered safe when the wall thickness of the piping components meets the requirements of 403 and 404.
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Allowable expansion stresses (as for heated oil lines). The allowable stress values for the equivalent tensile stress in 419.6.4(b) for restrained lines shall not exceed 90% SMYS of the of the pipe. The allowable stress range, SA, in 419.6.4(c) for unrestrained lines shall not exceed 72% of SMYS of the pipe.
•
Additive longitudinal stresses. The sum of the longitudinal stresses due to pressure, weight, and other sustained external loadings (see 419.6.4(c)) shall not exceed 75% of the allowable stress value specified for SA under “allowable expansion stresses.”
•
Additive circumferential stresses. The sum of the circumferential stresses from both internal design pressure and external load in pipe installed without casing under railroads and highways [see Code Section 434.13.4(c)] shall not exceed the applicable allowable stress value S determined by Code Section 402.3.1(a), (b), (c), or (d).
Section 402.3.3 of Code B31.4 covers limits of calculated stresses due to occasional loads in operation and test conditions.
Wall Thickness Calculations Section 404.1.2 of Code B31.4 gives the basic pipe hoop stress formula relating internal pressure, pipe wall thickness, pipe diameter and stress value: Pi D t = --------2S or 2St P i = -------D (Eq. 400-8)
where: t = pressure design wall thickness, in. Pi = internal design gage pressure, psi D = nominal outside diameter, in. S = allowable stress value, psi, (per Section 402.3.1(a) of Code B31.4) Per Section 404.1.1 of Code B31.4 the nominal wall thickness tn of straight sections of steel line pipe shall be equal to or greater than the sum of the pressure design wall thickness, and allowances for threading and grooving, corrosion, and prudent protective measures: tn ≥ t + A (Eq. 400-9)
where A = sum of allowances for:
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Threading and grooving (per Section 402.4.2 of Code B31.4) (zero for welded line)
•
Corrosion (per Section 402.4.1 of Code B31.4) (zero if the line is protected against internal and external corrosion per Chapter VIII of Code B31.4). For stocks where corrosion (or slurry erosion) is expected, a corrosion allowance must be provided, and consultation with the Materials and Engineering Analysis Division of the Engineering Technology Department is recommended
•
Increase in wall thickness as a reasonable protective measure (under Section 402.1 of Code B31.4) to prevent damage from unusual external conditions at river crossings, offshore and inland coastal water areas, bridges, areas of heavy traffic, long self-supported spans, and unstable ground, or from vibration, the weight of special attachments, or abnormal thermal conditions
The nominal wall thickness shall not be less than the minimum required by prudence to resist damage and maintain roundness during handling and welding. The appropriate minimum should be evaluated for the particular installation conditions. As a rough guide, the following is suggested: • • •
0.188 inch wall for sizes up to and including NPS 12 0.219 inch wall for NPS 14 through 24 A maximum D/tn ratio of 120 for pipe over NPS 24
These represent minimums for reasonable cross-country laying conditions. Consideration must also be given to buckling of double-jointed lengths of pipe and to fatigue stresses if extensive cyclical loading is possible during transport from the mill to the job site. The latter problem is discussed in API Recommended Practices RP 5L1, Railroad Transportation of Line Pipe; RP 5L5, Marine Transportation of Line Pipe; and RP 5L6, Transportation of Line Pipe on Inland Waterways.
Canadian Standard CAN3-Z183, Oil Pipeline Systems Canadian Standard CAN3-Z183 is similar to ANSI/ASME B31.4. The engineer must consult CAN3-Z183 to ensure compliance with it. In Alberta there is a lower allowable stress factor for sour service.
443 Pipe Stress and Wall Thickness Calculations for Gas Transmission Pipelines per ANSI/ASME Code B31.8 The organization and some aspects of the design procedure in Code B31.8 differ from Code B31.4. See especially Code B31.8 Chapter IV, Design, Installation, and Testing, Sections 840 and 841.
Population Density Index and Location Classification Code B31.8 relates calculations for allowable design pressures to damage resulting from the failure of a gas pipeline, and classifies locations by population density. For each mile of the pipeline, Section 840.2(a) of Code B31.8 defines a zone one quarter-mile wide (centered on the pipeline) and one mile long. Within each zone buildings intended for human occupancy are counted, with each separate dwelling
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unit in a multiple-dwelling-unit building counted as a separate building. Each zone is classified by the number of buildings it contains, as follows: •
Class 1. 10 or fewer buildings; for example, wasteland, deserts, mountains, grazing land, farmland, sparsely populated areas, and offshore
•
Class 2. More than 10 but less than 46 buildings; for example, fringe areas around cities and towns, industrial areas, and ranch or country estates
•
Class 3. 46 or more buildings (except where a Class 4 location prevails); for example, suburban housing developments, shopping centers, residential areas, industrial areas, and other populated areas not meeting Class 4
•
Class 4. Areas where multistory buildings are prevalent, traffic is heavy, and where there may be numerous other utilities underground. Multistory is defined as four or more floors above ground, including the first or ground floor
A Class 2 or 3 location that consists of a cluster of buildings may be terminated oneeighth mile from the nearest building in the cluster. Section 192.5(f) of 49 CFR 192 further provides that Class 4 locations end one-eighth mile from the nearest building with four or more stories. Section 840.3 of Code B31.8 advances additional criteria that take into account the possible consequences of failure near a concentration of people, such as in a church, school, multiple dwelling unit, hospital or organized recreational area. In establishing location classes consideration must also be given to the possibility of future developments.
Steel Pipe Design Formula Section 841.11 of B31.8 gives the hoop stress formula (Equation 400-10) relating internal design pressure, pipe wall thickness, pipe diameter, and factors applied to the specified minimum yield strength (SMYS) to establish a pipe stress value. 2St P = -------- ⋅ F ⋅ E ⋅ T D PD t = -----------------------------2S ⋅ F ⋅ E ⋅ T (Eq. 400-10)
where: P = design pressure, psig D = nominal outside diameter, in. t = nominal wall thickness, in. S = specified minimum yield strength (SMYS), psi, stipulated in the Specifications to the manufacturer
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F = construction type design factor per Code B31.8 Table 841.1A, ranging from 0.72 to 0.40, for four construction types, determined from Tables 841.15A, .15B, and .15C, and Sections 841.122 and 841.123. In setting the values for F, due consideration has been given and allowance has been made for the various underthickness tolerances provided for in the specifications approved by Code B31.8 E = longitudinal joint factor per Code B31.8 Table 841.1B. For pipe normally considered for new lines, E=1.0 T = temperature derating factor per Code B31.8 Table 841.1C. For temperatures of 250°For less, T=1.0 Although mill tests for particular runs of pipe may indicate actual minimum yield strength values higher than the SMYS, in no case where Code B31.8 refers to SMYS shall a higher value be used in establishing the allowable stress value (see Section 841.121(f) of Code B31.8). Code B31.8 Section 841.121(d) warns that the minimum thickness, t, required for pressure containment by Equation 400-10 may not be adequate to withstand transporting and handling during construction, the weight of water during testing, and soil loading and other secondary loads during operation, or to meet welding requirements. Table 841.121(d) gives least nominal wall thickness for all sizes through NPS 64, but Company practice is more conservative. Code B31.8 Section 816 requires pipe with a D/t ratio of 70 or more to be loaded in accordance with API RP 5L1 for rail transport, API RP 5L5 for marine, or API RP 5L6 for inland waterway. If it is impossible to establish that transporting has been done in accordance with the appropriate recommended practice, special hydrostatic testing must be done. Code B31.8 makes no specific reference to internal corrosion allowance, but Section 863 in Chapter VI, Corrosion Control, discusses internal corrosion control in general. Code B31.8 Section 841.121(b) limits the design pressure P for pipe not furnished to specifications listed in the Code or for which the SMYS was not determined in accordance with Section 811.253 of the Code. Section 841.121(e) covers allowable stress for cold-worked pipe that has subsequently been heated to 900°F for any period of time or over 600°F for more than one hour. Section 841.13 of the Code B31.8 covers protection of pipelines from hazards such as washouts, floods, unstable soil, landslides, installation in areas normally underwater or subject to flooding, submarine crossings, spans, and trestle and bridge crossings.
Canadian Standard CAN/CSA-Z184, Gas Pipeline Systems The provisions of Canadian Standard CAN/CSA-Z184 are similar to those of ANSI/ASME Code B31.8. The engineer must consult CAN/CSA-Z184 to ensure compliance with it. In Alberta there is a lower allowable stress factor for sour gas service.
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444 Coating Selection See the Coatings Manual and Section 340 of this manual for coating selection. Different coatings may be required to suit different terrain and soil conditions along the line. There are often a number of acceptable coatings, and the type and application method will depend primarily on the following: • • •
Ground corrosivity and effectiveness of cathodic protection Line temperature Cost of coating
In selecting coatings, attention should be given to factors such as: •
Data obtained from a field soils resistivity survey made early in the design phase of the project
•
Level of ground water table throughout the year
•
For cohesive clay soil, data on pipe-to-soil friction
•
In rock excavations, damage to the coating caused by the pipe hitting the trench walls while being lowered, and by rocks in the backfill
•
In tropical locations, termite attack
•
Potential damage to plant-applied coating in transit to job site
•
For plant-applied coating: – – – –
•
For over-the-ditch coating: – – – –
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Cost of plant application, and incremental shipping and handling costs Incremental field handling costs, and cost of repairs in the field Cost of field joint materials and application Availability, feasibility, and cost of setting up and operating a modular coating plant near the job site
Cost of coating materials, and shipping and storage costs Construction costs for coating, including pipe cleaning Capability of a construction contractor to apply the coating satisfactorily Standard over-the-ditch coatings are far less reliable than plant-applied systems, particularly at higher-than-ambient temperatures and under wet conditions
•
Use of additional coating thickness or higher quality coatings at highway, road and railroad crossings, either cased or uncased, and in developed areas
•
Service life anticipated for the pipeline
•
Comparative quality of the coatings over the service life the pipeline
•
Differential cost, if any, for the cathodic protection system
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445 Burial—Restrained Lines and Provision for Expansion Long cross-country pipelines are generally buried for several obvious reasons: •
Allows surface use of land by private owners and the public
•
Protects the line from accidental and intentional damage
•
Protects the line against temperature expansion and contraction from ambient temperature changes and radiant energy gains and losses
•
Minimizes effects of temperature changes on fluid viscosity
•
Provides restraint along the length of line
•
Aboveground installation may not be allowed by governmental authorities
On the other hand, in undeveloped areas some major pipelines and, often, flow and gathering lines are designed and installed aboveground for one or more of the following reasons: •
Economy of construction, especially where ditching is costly, since there are savings in both excavation and pipe coating
•
Benefit of solar radiation in keeping waxy oils above the pour point
•
Use of insulation and tracing arrangements on heated lines that would not be feasible for burial
Designs of hot lines and aboveground lines need to incorporate restraints and provision for thermal expansion, and must be examined individually.
Burial Cover Sufficient cover to protect the pipeline should be provided both for existing conditions and for any anticipated grading, cultivation, or developments that would require a very costly lowering of the line in the future. Company practice in many areas, especially for production field lines, is to increase cover over required minimums, since the cost of a deeper ditch in normal excavation is small compared to the added protection; five feet is recommended. Deeper burial is usually required for heated lines to provide restraint, and water and slurry lines should be buried below the ground frost depth. In some areas, it is advisable to place a yellow warning tape about a foot above the pipe to serve as a marker to anyone excavating across the right-of-way. Yellow Terra-Tape is one such tape and can be purchased with a metallic strip for burial over fiberglass pipe. Minimum Cover for Liquid Lines. Section 434.6 of Code B31.4 requires the cover over the top of a line to be appropriate for surface use of the land and for a normal depth of cultivation, and sufficient to protect against loads imposed by road and rail traffic. Code B31.4 Table 434.6(a) gives minimum requirements for cover. See Figure 400-10.
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Fig. 400-10 Minimum Cover Requirements for Liquid Lines Normal Excavation
Blasted Rock Excavation
LPG and NH3 Normal Excavation
Developed areas
36 in.
24 in.
48 in.
River and stream crossings
48 in.
18 in.
48 in.
Drainage ditches at roads and railroads
36 in.
24 in.
48 in.
Any other area
30 in.
18 in.
36 in.
If these minimums cannot be met, additional protection must be provided to withstand anticipated loads and minimize damage by external forces. Minimum Cover for Gas Lines. Section 841.142 of Code B31.8 gives minimum covers for gas transmission lines and discusses special considerations. See Figure 400-11. Fig. 400-11 Minimum Cover Requirements for Gas Lines Blasted Rock Excavation Location
Normal Excavation
NPS 20 and Smaller
Over NPS 20
Class 1
24 in.
12 in.
18 in.
Class 2
30 in.
18 in.
18 in.
Class 3 and 4
30 in.
24 in.
24 in.
Drainage ditches at roads and railroads
36 in.
24 in.
24 in.
Restrained Lines It is important to examine the effect of temperature differentials in a heated line restrained by burial or equivalent anchorage, and the resulting combination of tensile (positive) hoop stresses and compressive (negative) longitudinal stresses. Section 419 of Code B31.4 deals with expansion and flexibility; the following analysis will indicate whether detailed study is advisable. The Materials and Engineering Analysis Division of the Engineering Technology Department can assist in these calculations. The net longitudinal compressive stress due to the combined effects of internal pressure and temperature rise are computed using the following equation from Section 419.6.4(b) of Code B31.4: S L = E α ∆T – ν S H (Eq. 400-11)
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where: SL = longitudinal compressive stress, psi SH = hoop stress due to fluid pressure, psi (=PD/2t) ∆T = T2 - T1 T1 = temperature at time of installation, °F T2 = maximum operating temperature, °F E = modulus of elasticity of steel, psi (= 30 × 106 psi) α = Linear coefficient of thermal expansion of steel, in./in./ °F (= 6.5 × 10-6/ °F) ν = Poisson’s ratio for steel (= 0.3) so: SL = (30 × 106 × 6.5 × 10-6 × ∆T) - 0.3 SH = 195 ∆T - 0.3 SH If the temperature rise is great enough, the compressive stress caused by the restraint on pipe growth will exceed the tensile stress due to internal pressure. If the net longitudinal stress, SL, becomes compressive, then absolute values are used for pipe stresses in accordance with the Tresca Maximum Shear Theory, as follows: | SH | + | SL | = equivalent tensile strength ≤ allowable stress (Eq. 400-12)
Adding the absolute values of hoop stress and longitudinal stress when the values are of opposite sign to arrive at an equivalent tensile stress is a departure from separately comparing hoop stress and longitudinal stress to allowable values. The allowable value for equivalent tensile stress is limited to 90% of SMYS (per Section 402.3.2(c) of Code B31.4). Using this limit and Equations 400-11 and 400-12 the maximum temperature difference (°F) for a fully restrained pipe operating at a maximum allowable pressure at 0.72 × SMYS is: ∆Tmax = 0.002 × SMYS (Eq. 400-13)
If the design temperature difference is greater, the maximum allowable pressure will have to be reduced below 0.72 SMYS, or, alternatively, higher grade pipe used. When lowering or repositioning pipelines, or in portions of a restrained line aboveground, beam bending stresses must be included in the net compressive longitudinal stress calculation. The depth of burial required to provide restraint is a function of pipe diameter, soil and backfill strength properties, bend configuration (overbend or sidebend), bend radius and angle, temperature difference, and pipe-soil friction. Given operating
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temperature and soil type, diagrams for a specific pipe—one for overbends and one for sidebends—should be developed relating depth of cover to angle of bend, as indicated in Figure 400-12. See Appendix F for the method used to develop these diagrams.
Provision for Expansion or Anchoring The pipeline transition zone from underground to aboveground represents a change in conditions from fully restrained to unrestrained, and deserves a discussion of the deflections and stresses encountered. Determining the longitudinal stresses and deflections due to internal pressure and temperature change is important in the layout and design of aboveground piping because, if economic methods cannot be found to provide enough flexibility to accommodate the deflections, anchors must be designed to constrain movements. Fig. 400-12 Depth of Burial vs. Angle of Bend (See Appendix F)
Fig. 400-13 Transition from Underground to Aboveground Pipe
Consider a pipeline in the transition zone without anchors (see Figure 400-13). The transition of stress and strain between points A and B is assumed to be linear, with the length L dependent on the longitudinal resistance of the soil (pipe-soil friction), as follows: At point A: Net longitudinal stress SL = Eα ∆T - ν SH = 200∆T - 0.3SH (compressive) Longitudinal strain = 0 (Eq. 400-14)
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At point B: Net longitudinal stress SLB SH = ------- (tensile) 2 Longitudinal strain ε B S L B νS H = α∆T = ---------- – ---------E E SH = Eα ∆T + ------- – 0.3S H ⁄ E 2 200∆T + 0.2S H -------------------------------------- = E (Eq. 400-15)
The length L over which the transition occurs depends on the longitudinal soil resistance (pipe-soil friction) Fs, and can be determined by: ( S LB – S LA ) L = A pm ------------------------------- ft Fs SH ------ + 200∆T – 0.3S H 2 = A pm -------------------------------------------------------FS
200∆T + 0.2S H = A pm -------------------------------------- Fs
(Eq. 400-16)
where: Apm = Area of pipe metal, in.2 It is recommended that a soils consultant or the Civil and Structural Division of the Engineering Technology Department be consulted for appropriate values of soil resistance Fs, since Fs is highly variable with type of soil. For rough approximations of soil resistance in sand and clay, the following can be used.
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•
Sand Fs = 2.25 D Hπ (Eq. 400-17)
where: Fs = soil resistance, lb/ft D = outside diameter of pipe, in. H = burial cover, ft Sand density assumed to be 100 lb/ft3 π F S = --- ⋅ αS u 2 •
Clay (Eq. 400-18)
where: αSu =
cohesion, lb/ft2
The value of αSu can range from 75 lb/ft2 in loose disturbed clay to 1500 lb/ft2 for compacted stiff clay. A range of 200 to 300 lb/ft2 is suggested for general soils. The total movement at point B will be the average strain from point A to point B over the length L, or: ∆L = (εB/2) × L If the expected expansion ∆L at point B has adverse effects on aboveground piping or support arrangements that cannot be accommodated by providing flexibility, then anchors must be designed to constrain the deflection. The force F acting on the anchor simply becomes the stress difference across the anchor times the metal area of the pipe, or: F = Apm (SLA - SLB) = Apm [(200 ∆T - 0.3 SH) + 0.5 SH] = Apm (200∆T + 0.2 SH) This force can be very great. The design of the anchor itself should be in accordance with good practices of civil engineering including consultation with a geotechnical consultant. Considerations should include soil friction and lateral bearing pressure, transfer of loads from the pipe to the anchor, transfer of loads from the anchor to the soil, and whether other loads from aboveground piping should be superimposed. The Civil and Structural Division of the Engineering Technology Department may be consulted if problems are encountered.
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446 Seismic Considerations The major seismic hazards for pipelines are: • • •
Differential fault movement and ground rupture Landslides Liquefaction
Ground shaking is a major design consideration for station and terminal facilities and aboveground sections, but not for buried lines, since the pipeline moves with the ground with no relative displacement. Where a pipeline crosses or lies within a seismic zone, the adequacy of the line to withstand the effects of earthquake action must be assessed. Comprehensive treatments of this subject are contained in Guidelines for the Seismic Design of Oil and Gas Pipeline Systems and Seismic Design of Oil Pipeline Systems (see Section 480), which present the available (1983) earthquake practices. Geotechnical and seismological consultants with knowledge of pipeline performance in seismic zones should be consulted early in the project so that pipeline routing and designs can minimize risks from earthquakes and mitigate effects of an earthquake on the pipeline. The design level of the earthquake, nature and importance of the project, cost implications, and risk assessment of items such as public safety, loss of product or service, and damage to the environment must be considered. The extent of geotechnical investigations should be consistent with risks and consequences of seismic activity. These investigations would include the following: • • • •
Fault location and expected movement Soil stability on slopes during earthquakes Locations of soils prone to liquefaction Passive pressures of backfill material
Fault Movement It is critically important to design pipeline for possible fault movement and the accompanying ground ruptures which can occur along an extended length of the fault. Fault movement is not necessarily confined to a single fault plane or zone, but may occur at substantial distances from the main trace of the fault. Pipeline alignment in fault zones should be such that the expected fault movement will produce tensile stresses in pipe—not compressive stresses, which are likely to promote buckling failure. Pipelines should be laid in relatively straight sections in areas of potential faulting and ground rupture, crossing the fault at an angle of between 60 and 80 degrees, without sharp changes in direction and elevation that could act as anchors. Depth of cover over the pipe should be minimized to reduce soil restraint during fault movement, and backfill should be loose to medium granular soil without cobbles or boulders. If native soil differs substantially from this, oversize trenches should be excavated for a distance of about 200 feet on each side of and through the fault zone. Use of heavier wall pipe in the fault zone will increase the pipe’s tolerance for fault displacement at a given level of maximum tensile strain, as will a hard, smooth coating such as fusion-bonded epoxy. It is
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suggested that heavy wall pipe and epoxy coating, with controlled backfill and cover, be used for a distance of 1000 feet on each side of and through the fault zone.
Landslides Landslides are mass movements of the ground and can be triggered by seismic shaking. Slopes showing signs of recent movement and instability may be seismic risk areas, depending on the nature of ground movement. If slope instability involves deep translations and rotational displacement, the potential ground movements in the vicinity of the pipeline may be very large, and, in light of the substantial costs required to stabilize such slopes, relocation of the pipeline must be considered. If, on the other hand, instability involves slumps and shallow slides, slope stabilization may be an effective means of correcting the difficulties and promoting long-term performance. When crossing a zone of potential instability, it is generally better to locate the line along a contour of constant elevation at a relatively shallow burial depth. This minimizes grading slope disturbance, and lessens the chance of compressive strains imposed by slope movement at oblique angles to the pipeline.
Liquefaction Liquefaction is the transformation of a saturated cohesionless soil, such as loose to medium-dense sands and nonplastic silts, from a solid to a liquid state as a result of increased pore pressure and loss of shear strength. Liquefaction can lead to lateral ground spreading, loss of bearing, and uplift of buried objects due to buoyancy. Areas that are particularly vulnerable to liquefaction include loose fills near waterfronts, toe areas of alluvial fans and deltas, active flood plains, river channels, and saturated colluvial deposits. The combined consequences of lateral spreading of the ground and buoyancy is a severe condition for a buried line, and it is difficult to pinpoint zones of potential spreading within a region susceptible to liquefaction. Under these conditions, it seems prudent to evaluate pipeline performance for the entire region in terms of its response to lateral spreading. Pipelines that can accommodate moderate amounts of lateral spreading should be able to sustain deformations from buoyant forces. A suggested design solution is to design the line to be buoyant under earthquake condition, with shallow burial so that its upward movement is limited. In areas where landslides or liquefaction may occur, it may be prudent to locate line block valves or check valves, as appropriate, on either side of the seismic hazard zone.
Design Level Earthquake Selection The ASCE Guidelines propose that design criteria for important oil and gas pipelines encompass two levels of earthquake hazard. The lower level, the probable design earthquake (PDE), normally has a return period of approximately 50 to 100 years. The pipeline system should be able to operate through and following such an earthquake. The higher level (stronger) event, is the contingency design earthquake (CDE). It has a longer return period, of about 200 to 500 years or more. The Guidelines suggest that in some situations it may be expedient to use only the CDE level, and this is the basis for most Company installations. On this basis, a pipeline system would be shut down at the time of severe seismic activity,
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and would resume operation after careful inspection of facilities, and appropriate repair measures or pipe replacement as might be needed. The ASCE Guidelines point out that in the dual design earthquake concept the lower level PDE should be considered the earthquake for which design criteria in regulations and codes are intended; current codes are for earthquakes that have return periods of the same order as other extreme environmental conditions associated with wind, rain, snow, etc. The higher level (and less likely) CDE, however, is associated with a design level that goes beyond the intent of codes. Under these conditions code stress criteria should be relaxed somewhat and strain criteria should be introduced. The strain criteria used generally allow the pipeline to take advantage of available ductility without rupture.
Allowable Strain Criteria A primary concern is the ability of buried pipelines to accommodate abrupt ground distortions from faulting, landslides, lateral spreading, and liquefaction. For such soil movements, the strains in the pipeline will usually exceed yield. Since the load condition is an applied displacement, strains are limited to the amount of deformation necessary for the pipeline to conform to differential ground movement. For these reasons nonlinear analysis methods are used for buried pipelines and strain limit criteria are imposed. Table 4.5 of the Guidelines (Figure 400-14) summarizes recommended allowable pipeline strains. Fig. 400-14 Recommended Allowable Strain Criteria for Above Ground and Underground Oil and Gas Pipelines and Piping Strain Component
Allowable Strain
Internal pressure, live and dead loads, plus local, nonvibratory induced loads such as faulting, slope instability, and liquefaction.
Tension: 2% to 5%. Only applicable to straight sections of pipe. In regions and field bends, more restrictive criteria should be used. Compression: Onset of wrinkling.
Internal pressure, live and dead loads, plus shaking effects due to the CDE
50% to 100% of the onset of wrinkling.
Guidelines Sections 5.2, Pipeline Performance under Large Differential Ground Movements; 5.3, Analysis of Pipelines Subjected to Fault Movements; and 5.4, Factors Affecting Pipeline Performance at Fault Crossings should be referred to for situations where pipelines cross known fault zones, or are in likely areas of lateral movement. Section 5.5, Special Fault Design Considerations, discusses approaches to pipeline fault-crossing strategies, and assesses the consequences, cost, and reliability of particular fault crossing designs. Some special design concepts discussed include placement of the line in an aboveground berm constructed of low-strength soil, placement of the line in oversized trenches surrounded by low-strength, crushable material or selected backfill, casing the line in buried oversize culverts, placement of the line on aboveground sliding supports, and increasing wall thickness to improve ductile behavior.
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447 Crossings Nearly all pipelines involve water crossings, highway and railroad crossings, and crossings of other pipelines. Permits are always required from regulatory agencies and owners of existing facilities, and requirements set forth in the permits must be met. General guidelines for design are included in the following Codes: •
ANSI/ASME Code B31.4 for liquid lines – –
•
Section 434.6, Ditching Section 434.13, Special Crossings
ANSI/ASME Code B31.8 for gas transmission lines – – – –
Section 841.13, Protection of Pipelines and Mains From Hazards Section 841.143, Clearance Between Pipelines or Mains and Other Underground Structures Section 841.144, Casing Requirements Under Railroads, Highway, Roads or Streets Section 862.117, Casings
River and Stream Crossings Any river or stream crossing involves unique design and construction considerations, and is usually influenced by conditions imposed by regulatory agencies. In a conventional installation the pipeline is laid in a trench excavated in the river bed and bank. However, the horizontal directional drilling method offers distinct advantages, and should be the first choice for major rivers—unless the line can be laid across a dry river bed. In some cases an overhead crossing on a bridge or selfsupported span is indicated. In addition to topographic surveys to develop cross section profiles of the river bed and banks in the area of a proposed crossing, investigations should be made to determine composition of the bottom, scouring, bank variation and stability, seasonal variations of water depth and current velocity, and environmental restrictions such as fish spawning seasons. Particular attention should be given to geophysical and hydrological investigation to predict the river scour zone and to provide data for horizontal drilling techniques. Lines should be laid 5 to 7 feet below the scour zone, regardless of installation method. Except for small stream crossings, consideration must be given to obtaining access and sufficient land on one or both sides of the river for fabricating pipe sections and for construction equipment needed to install the line. The significant advantages of the horizontal drilling method are as follows:
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The line lies in undisturbed soil well below the scour zone
•
There is no environmental impact such as the silting and disturbance of river bottom and banks that accompanies trenching in a moving stream
•
Weight-coating or other protection from mechanical damage is not needed
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Disadvantages include the following: • •
Potentially higher cost Limited number of qualified contractors
In the hydraulic drilling method, a pilot hole is drilled, directionally controlled, and followed by a larger reamer. Then the full length of pipe is pulled through the hole. Drilling muds are used to facilitate drilling, stabilize low-cohesion soils, and facilitate pipe installation. Heavier wall pipe is usually but not necessarily used at the crossing. Coating should be fusion-bonded epoxy to provide a durable, smooth surface on the pipe. See Model Specification COM-MS-4042 in the Coatings Manual. Heavier wall pipe is nearly always used at trenched river crossings to provide additional protection from mechanical damage and to keep pipe stresses within limits during installation. The heavier wall also provides some additional weighting of the pipe to obtain stability of the submerged line. The weight of the installed pipe, filled with the operating fluid or gas, must be greater than the buoyancy produced by the displaced water or the cohesionless “fluid soil” backfill that may be placed or naturally settle around the pipe. For all gas lines and for larger oil lines (say, over NPS 10) additional weighting is usually required. As a guide, a submerged weight (negative buoyancy) of at least 5 lb per lineal foot should be provided. Weighting may consist of concrete weight coating applied over the pipe coating or concrete weights clamped on at intervals. If the line is to be pulled across the river bottom, continuous concrete-weight coating is preferable to clamped on weights. Set-on weights, without bolting, are not recommended except for larger lines in dry flood plain areas. The required additional weight-coating Wc above pipe weight Wp needed to achieve a design submerged weight Ws calculated as follows: Ws + ρwA – Wp W c = ---------------------------------------ρw 1 – ------ρc (Eq. 400-19)
For which the outside diameter, Dc, of the weight-coated pipe will be Ws + ρc A – W p D c = 13.5 -------------------------------------ρc – ρw Wc = 13.5 -------- + A ρc Dc – D t c = ----------------2 (Eq. 400-20)
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where: A = cross-sectional area of corrosion-coated pipe of outside diameter D (without weight-coating), ft2 = 0.00545 D2 Ws = submerged weight of pipe and coating, lb/ft Wc = weight of concrete in air, lb/ft Wp = weight of pipe in air, lb/ft D = diameter, ft tc = concrete thickness, ft ρc = density of weight-coating, lb/ft3 (approx. 140 for normal concrete weight-coating) ρw = density of water or cohesionless backfill, lb/ft3 To calculate the submerged weight for pipe that is already weight-coated: Wc W S = ( W p + W c ) – ρ w -------- + A ρc (Eq. 400-21)
Highway and Railroad Crossings See API Recommended Practice 1102, Recommended Practice for Liquid Petroleum Pipelines Crossing Railroads and Highways, (see Section 2300) which covers both cased and uncased crossings. API RP 1102 gives guidelines for design and construction, sets forth minimum cover requirements, and includes the formula, graphs and nomographs for determining circumferential stresses in uncased line pipe. It includes a table for minimum wall thickness for casing, but Company practice is to use greater minimums: 0.188 inch up through NPS 16, 0.250 inch for NPS 18 through 36, and 0.312 inch over NPS 36. API RP 1102 can also be used to design casing for gas transmission lines. Also, see Appendix I of this manual for the calculation of bending stress in a buried pressurized pipeline due to external loads. Highway or railway authority requirements given in the crossing permit must be met and may be more stringent than API RP 1102. It is advisable to provide a drawing for each crossing, showing the crossed facility, ground profile, pipe or casing cover, casing length (for cased crossings), casing diameter and wall thickness, spacers and end seals, vent details (if required), and, for uncased crossing, the line pipe wall thickness, coating, and installation method. Uncased Crossings. It is preferable to make highway, road and railroad crossings without using a casing, and uncased crossings are becoming accepted by the controlling authorities. Generally, thicker pipe walls are used to provide for external loading by crossing traffic and to reduce the possibility of maintenance repair at the
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crossing during the service life of the pipeline. A high-quality coating is used on the crossing section consisting of fusion bonded epoxy, often with an outer coating of smooth concrete. Where traffic cannot be diverted to allow open trenching, the line pipe is installed by the same boring and jacking method used for casing installation. External loading due to traffic over the line must be carefully assessed and, if necessary, depth of burial, pipe wall thickness or both increased. Sections 402.3.2(e) and 434.13.4(c) of Code B31.4 for oil lines requires that the sum of circumferential stresses due to internal design pressure and external load shall not exceed the applicable allowable stress value S determined by Code B31.4 Section 402.3.1. Metal fatigue by cyclical loading at crossings subject to high-density heavy traffic must also be considered. Code B31.8 for gas transmission lines approaches design for uncased crossings by adjusting to the construction type design factor F in accordance with Code B31.8 Table 841.15A. Cased Crossings. Pipeline crossings of highways and railroads have traditionally been made by installing a casing pipe, at least two sizes larger than the line pipe, by boring and jacking. Short sections of casing pipe are sequentially welded to the casing during the jacking process; usually the casing pipe is not coated. The line pipe can then be pushed through the casing, supported on electrically non-conductive spacer supports. The annular openings at both ends of the casing are sealed with end caps of electrically non-conductive material. Electrically insulating the line pipe from the casing pipe is critical in order to properly maintain the line under cathodic protection. See Section 364 for descriptions of casing insulators and seals. Company preference is for uncased crossings wherever feasible and acceptable to the authority because, over time, differential settlement between the casing and line pipe has been known to damage the nonconductive spacers, end seals and pipe coating. This results in failure of cathodic protection on the line, and requires very costly maintenance to repair or replace the crossing. Government regulations require correction of shorted casings, with fines assessed if corrections are not made in a timely fashion.
Crossings of Other Pipelines Clearance. Spacing between crossing pipelines should be provided to minimize (1) the risk of damage to either line during construction or maintenance, and (2) the effect of one line’s cathodic protection system on the other. Section 434.6(c) of Code B31.4 requires a minimum of 12 inches between lines or from any buried structure. Section 841.143 of Code B31.8 requires at least 6 inches clearance wherever possible, but Section 192.325 of 49 CFR 192 requires a minimum of 12 inches. Company practice is to provide 12 inches, with sandbags or compacted backfill between the lines so that the clearance is maintained. Cathodic Protection Test and Bonding Leads. It is the usual and recommended practice to install test and bonding leads to both the line under construction and the existing line. Reference should be made to Section 465 of this manual and to the Corrosion Prevention Manual.
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448 Special Considerations This section alerts the engineer to some problems involving pressure surges, slurry pipeline erosion and corrosion, and crack arrestors.
Pressure Surges The pressure surges that result from rapid shutoff of liquid flow in a pipe are normally not severe for pipelines. Section 800 of the Fluid Flow Manual gives a simplified method for calculating pressure surges. Section 402.2.4 of Code B31.4, Ratings—Allowance for Variations from Normal Operations, requires that surge calculations be made, along with adequate provision to ensure that the level of pressure rise does not exceed the allowable design pressure at any point in the system by more than 10%. Section 454 of this manual discusses line pressure control and relief.
Erosion/Corrosion Allowance for Slurry Pipelines The abrasive action of solids in a slurry pipeline, often combined with some corrosive action, requires pipe wall thickness beyond that required for internal design pressure. Besides an allowance applied to the entire length of the line, attention should be given to additional allowance for conditions such as: •
High velocity at the walls of sharp bends and at steep downhill sections where slack flow may occur
•
High oxygen content in the water leaving the slurry-preparation station, (subsequently reduced by chemical reaction with the pipe steel). The Materials and Engineering Analysis Division of the Engineering Technology Department has reference files on this
•
Greater abrasion leaving the slurry-preparation station (until solid particles are “smoothed” in transit)
Crack Propagation Control Localized mechanical damage to high pressure (ANSI Class 600 and above) gas pipelines, caused, for example, by excavating equipment, can result in critical failures involving longitudinal cracking along many hundreds of feet of pipe. This type of failure is termed dynamic ductile fracture. Research on this type of crack propagation has been conducted and continues in the United States, Canada, Europe and Japan. In the United States Batelle, Columbus Laboratories has, in association with the Pipeline Research Committee of the American Gas Association, led in this investigation and in designs to arrest cracking. Pipelines in high-pressure gas or supercritical fluid service require pipe toughness and sufficient wall thickness to avoid crack propagation. In open country, crack arrestors are used in lighter-wall sections to minimize damage should a propagation crack occur. Pipe dimensions and grade, and material properties including steel toughness, internal pressuring medium and external environment are parameters used to predict whether or not unstable fracture propagation will occur and at what fracture
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speed. See Section 313 for a more detailed discussion and the toughness required by ANSI and recommended by Chevron. When crack arrestors are indicated by semi-empirical calculations or experimental testing, mechanical sleeve collars, joints of heavier wall pipe, or both can be placed, as necessary or as prudent, at intervals and at critical locations such as river and highway crossings and line valves. Both were used on the Chevron-managed 16inch CO2 pipeline constructed in 1985 from Rock Springs, Wyoming, to Rangely, Colorado. See Figure 400-15 for the crack arrestor installation guidelines for that project.
450 Pipeline Appurtenances Section 360 describes piping components for pipelines. This section gives guidelines for application of these items and other pipeline appurtenances. Requirements of governmental jurisdictions should be determined at an early design stage in designs, so the facilities will be in compliance. Design and selection of all line valves, mainline bends and fittings must provide for passage of scrapers and inspection pigs. See Sections 452 and 453 of this manual. For gas transmission systems, it should be noted that in Location Class 1 areas where the Type A construction design factor F of 0.72 applies to line pipe design, Section 841.122 of ANSI/ASME B31.8 requires that fabricated assemblies such as line valve manifolds and scraper traps be designed with a Type B factor F of 0.60.
451 Line Valves Through-conduit line valves spaced at intervals are used to sectionalize the pipeline for one or several of the following purposes: •
Initial hydrostatic testing (see Section 770 of this manual) and subsequent inservice hydrostatic testing (see Section 830 of this manual)
•
Isolation of a section of line to reduce the quantity of fluid drained, or volume of gas to be depressured in the event of: – –
•
Maintenance work to repair or replace a portion of the line Damage to or rupture of the line
As block valves at station plot limits (usually the fence lines)
These valves may be manually operated, remotely controlled, or automatically actuated, depending on the purpose and the need for fast closing in the event of line damage or rupture. Consequences of closing valves against line flow must be considered, particularly pressure surges produced by fast-closing valves. See Section 800 of the Fluid Flow Manual and Section 454 of this manual. Through-conduit check valves are often used with block valves to provide immediate control of draining or depressuring in the section of line downstream of a damaged or ruptured section.
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Fig. 400-15 Crack Arrestor Installation-Rangely CO2 Pipeline
A. General Crack arresting collars are to be installed at certain locations along the CO 2 pipeline for the purpose of arresting ductile fractures which may occur in the event of a mechanically-induced pipeline rupture. These arrestors are intended to protect rivers, paved roads and other sensitive areas from damage, and to minimize the extent of damage in the cross-country sections of the pipeline should a propagating crack occur. Note that these collars offer backup arresting capability to 0.438 inch wall joints of pipe installed at 1000 foot intervals in thinner sections of pipeline. The 0.438 inch wall and thicker pipe is expected to self-arrest cracks.
B. Scope of Work Contractor shall provide all materials and installation of crack arresting collars as described herein.
C. Crack Arresting Collars The collars shall be fiberglass-reinforced plastic, as provided by Arco Pipeline Company. They will be 16.9 inch ( ±0.075 inch) I.D., 15 inches long, and will have a wall thickness of approximately 1/2 inch. A hole, 1/2 inch in diameter, will be drilled 4 inches from one end of each arrestor.
D. Locations and Spacing The collars will be installed at tie-in points only. Specific locations will be tie-ins on either side of all cased road crossings, river crossings, valves, and scraper traps. In addition, crack arrestors are to be installed at intervals no greater than 6,000 feet from the beginning of the line to the end of the 0.406 inch wall pipe near MP92. From that point to the end of the 0.375 inch wall pipe near MP127 the interval shall be no greater than 8,000 feet, and for the remainder of the line into the Rangely Field the interval shall be no greater than 12,000 feet.
E. Installation At specified tie-in points, arrestors will be slipped over the taped pipe and placed as far from the weld area as necessary to be out of the welder’s way. Two bands of Polyken 930 hand-wrap tape will be wrapped round the pipe, over the existing coating, spaced approximately nine inches apart so the centers of the bands are approximately 15 inches apart. These bands will be from 2-8 layers thick, as determined in the field, to produce a snug fit when the arrestor is slid over them. The arrestor will then be centered over these two bands so that approximately three inches of each band extend beyond the end of the arrestor. The arrestor will be positioned so that the hole will be on the downhill side on the bottom, to act as a drain. If, due to ovality of the pipe, a uniform snug fit cannot be obtained, a soft plastic wedge shall be inserted between the arrestor and the Polyken 930 tape to make a snug fit. Wedges shall only be employed on the top third of the pipe between the 10 o’clock and 2 o’clock positions. Polyken 930 hand-wrap tape will then be wrapped around the ends of the arrestor to prevent dirt from entering the annulus between the tape and the arrestor.
F. Materials Crack arrestors shall be as previously described. The hand-wrap tape shall be 6-inch wide Polyken 930, or as approved by Company. The plastic wedges shall be approved by Company.
Line valves should be located near roads or other easily accessed locations so they can be quickly reached for emergency operation and are conveniently accessible for maintenance. The valve manifold assemblies should preferably be above grade within a fenced enclosure. This provides good maintenance access, and any leakage at flanges or connections is readily visible. Where this is not practical for larger sizes or not allowed by permitting restrictions, the valves must be installed in belowgrade boxes or vaults.
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Below-grade installation poses the problems of ground water and run-off water drainage, as well as the possibility of an explosive condition developing in a confined space. Alternatively, the main line valves and branch piping can be coated and buried, with the pump-around valves, pressure gage connections, and main line valve handwheels or operators above grade within a fenced enclosure. This arrangement is suitable for ball valves, but less satisfactory for gate valves. Risk of vandalism may be a consideration for any aboveground facility.
Block Valves in Liquid Lines Section 434.15 of Code B31.4 covers requirements and guidelines for mainline block valves in liquid lines, as follows: •
Water Crossings. At major river crossings and public water supply reservoirs, a block valve on the upstream side of the crossing, and a block valve or a check valve on the downstream side. (For water crossings, 49 CFR 195.260(e) states that block valves are required wherever the crossing is more than 100 feet wide from high-water mark to high-water mark)
•
Other Locations. A block or check valve (where applicable to minimize pipeline backflow) at other locations, as appropriate for the terrain. In industrial, commercial, and residential areas maximum spacing of block valves for other than LPG or liquid anhydrous ammonia shall be 10 miles. Where construction activities pose a particular risk of external damage, provisions shall be made for the appropriate spacing and location of mainline valves consistent with the type of liquids being transported. For LPG and liquid anhydrous ammonia, maximum spacing of block valves in industrial, commercial, and residential areas shall be 7.5 miles
•
Pipeline Facilities. At pump stations, tank farms, and terminals, block valves on the line entering and leaving the station, whereby the station can be isolated from the pipeline
•
Remotely Controlled Facilities. At remotely controlled pipeline facilities, a remotely controlled mainline block valve shall be provided to isolate segments of the pipeline
At mainline block valves on oil lines the usual Company practice is to provide valved connections on each side of the block valve so that when a section of line must be drained, a portable pump can be connected, discharging either to the other section of line or to tank trucks. A typical manifold is indicated in Figure 400-16.
Block Valves in Gas Transmission Lines Sections 846.1 and 846.2 of Code B31.8 covers requirements and guidelines for sectionalizing block valves in gas transmission lines, as follows: •
Spacing between valves. This shall not exceed: – –
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20 miles in predominantly Class 1 areas 15 miles in predominantly Class 2 areas
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– – –
10 miles in predominantly Class 3 areas (49 CFR Part 192.179(a) limits this to 8 miles) 5 miles in predominantly Class 4 areas Spacing may be adjusted slightly to permit installation in a more accessible location, with continuous accessibility as the primary consideration
•
Other factors influencing spacing. These involve the conservation of gas, time required to blow down the isolated section, continuity of gas service, necessary operating flexibility, expected future development within the valve spacing section, and significant natural conditions that may adversely affect the operation and security of the line
•
Automatically actuated valves. These are not a Code requirement, and their use is at the discretion of the operating company
•
Blowdown valves. These shall be provided so that each section of pipeline between mainline valves can be blown down as rapidly as practicable. 49 CFR 192.179(c) further requires that the blowdown discharge be located so the gas can be blown to the atmosphere without hazard and, if the transmission line is adjacent to an overhead electric line, so that the gas is directed away from the electrical conductors
A typical mainline block valve manifold with provision for blowdown is indicated in Figure 400-17. Often a removable blowdown vent stack is brought to the location and connected only when blowing down. Optional installation of a smaller bypass valve between the blowdown connections allows better control than the mainline valve when pressuring or depressuring the entire length of line. For gas lines in cold climates aboveground piping will probably require special materials. Fig. 400-16 Mainline Block Valve Manifold with Pumparound Valves
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Fig. 400-17 Mainline Block Valve Manifold with Blowdown Connections
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452 Scraper Traps Scraper trap manifolds provide for insertion and removal of scrapers (also called pigs) or spheres at intervals along the line. Series of scrapers are run through the line as part of the construction program and for initial dewatering of the line. Inservice scraper runs are determined by the nature of the fluid(s) transported and by the expected fouling buildup on the pipe walls and at sagbends, which influences selection of the type of scraper, spacing between scraper trap manifolds, and frequency of runs. For relatively clean fluids spacing may typically be on the order of every 75 miles. Reference [3] is a comprehensive text on pipeline pigging. A typical station scraper trap manifold for liquid hydrocarbon service is depicted in Figure 400-18. See Section 363 of this manual for descriptions of closures and appurtenances for scraper traps. The trap barrel must have a pressure indicator and means to relieve the pressure before opening the barrel. See 49 CFR 195.426. Fig. 400-18 Scraper Trap Manifold
Scraper traps are installed at the initial pump station, most intermediate pump stations, and at the terminal. If spacing between the intermediate pump stations eventually installed is considerably closer than needed for scraper runs, it is possible to arrange valving and pump operation so that scrapers will run through the mainline valves at the station without an incoming trap on the suction side of the station and an outgoing trap on the discharge side of the station. Cross-country pipelines should have permanent facilities to run scrapers, even though expected operating conditions may never or only very infrequently require scraper runs. Where permanent scraper traps are not installed, or if pipeline construction sequence dictates initial scraper runs in sections where designs do not provide for a scraper trap, temporary removable scraper traps can be used, usually designed and provided by the construction contractor.
Design of Scraper Trap Manifolds Design of scraper trap manifolds depends on several key factors.
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Scraper Type. The type of scrapers to be run, both for operation and maintenance inspection, influences manifold design. There are four basic types of scrapers, all moved along the line by the fluid flow: •
A series of disc cups, usually with sealing lips on the circumference, mounted on a central shaft, often with wire brushes or blade scrapers for cleaning
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A cylindrical plastic plug (usually polyurethane) with a variety of surfaces from plain foam to hard plastic with grit or wire embedded
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A sphere, inflated to slightly larger diameter than the line ID
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Inspection pigs, propelled by disc cups and containing electronic equipment to measure and record pipe wall thickness
The length of the scraper trap barrel should easily accommodate the length of scraper to be run. Usually the barrel length will be determined by the length of an inspection pig. If several scrapers are to be run in a spaced series, the barrel of the incoming scraper trap must accommodate at least two. Also, there must be clearance at the end of the barrel to handle a scraper for insertion or removal. The length and mechanical configuration of scrapers and inspection pigs also will determine the minimum radius of bends in the main line, whether at scraper trap manifolds or anywhere else in the main line. If spheres are ever to be used, branch tee connections should not be larger than about 60% of the mainline diameter or there is a risk that flow will pass around the sphere, and the sphere will not move past the branch. For large lines where scrapers cannot be readily lifted by one or two men, davits or trolleys should be provided. Material Scraped From Pipe Walls. Waxy sludge that accumulates ahead of scrapers in lines carrying waxy crude oils is of particular concern: the barrel volume must be sufficient to contain a sludge plug as well as the scraper. Often the volume of the sludge plug can be reduced using a bypass pig, which allows some flow through the scraper to dilute the wax accumulation, or wax chopper grates on the outlet connection from an incoming barrel to break up the sludge flowing to booster pump suction or on down the line. Pigging on gas transmission lines is usually done to remove dust, dirt, and small amounts of liquid. In remote locations, the dirty gas ahead of the scraper can often be discharged to the atmosphere, but at other locations dust collecting facilities must be provided for pollution control. Stock Drained From the Scraper Trap Barrel. The scraper trap barrels on liquid lines must be drained before opening the barrel to insert or remove scrapers. Most of the liquid can usually be drained to a station sump, with the sump pump discharging to the incoming line, station tankage, or to a tank truck. At remote scraper traps where there are no other facilities a permanent or portable pump can be used to transfer oil from the scraper trap barrel to the main line or to a tank truck. Some liquid will still drain when the barrel is opened and from the scraper when it is removed. To contain this drainage, a slab with containment curb and drain should be provided, with a grating above the slab as a walking surface.
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Scraper Trap Foundations. Scraper traps generally only require sufficient support to hold the barrel and fluid weight. However some pipelines may require special foundations to account for: • •
Expansion of hot lines Uplift forces generated by impact of liquid slugs in gas lines
Branch Tee Connections Branch tee connections from the main line that are larger than about 25% of the line diameter should be provided with bar grates so that scrapers will pass along the main line without getting caught at the branch. See Standard Drawing GA-L99880, Standard Detail of Bars at Pipeline Tee Connections, in this Manual.
Scraper Detectors Scraper trap manifolds usually include a mechanical device to indicate passage of a scraper. The indication may be visual at the device, or electrically transmitted to a local panel or remote location. On outgoing traps the device is normally installed downstream of the trap block valve and normal-flow tee. On incoming traps the device is normally installed in a short section of line-size pipe downstream of the trap block valve. Sometimes a second device is located a distance upstream to give an advance signal of an incoming scraper.
Code References Section 434.17 of Code B31.4 gives general guidelines for scraper traps; Code B31.8 has no specific reference to scraper traps. For gas lines in cold climates aboveground piping will likely require special materials. Special attention must be given to sour lines since it may be necessary to provide a nitrogen purge before opening the scraper trap panel.
453 Electronic Inspection Pigs Inspection pigs are primarily used to detect pipe wall thickness anomalies, record them electronically for playback at the end of the run, and determine the location of observed defects along the length of the line. Crack detection, hard spot detection, geometry, camera, leak detection, and mapping smart pigs are also available. Capability to run inspection pigs should be provided in the design of the pipeline and appurtenances. Input should be obtained from one or more inspection services as to limitations affecting design of a particular pipeline, such as:
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Minimum radius of bends, and corresponding minimum pipe internal diameters. (Offshore risers should have a minimum radius of bends of at least five diameters.)
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Minimum length of straight pipe between bends
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Spacing between branch connections, size of side taps, and if the side taps are barred
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Length of the inspection pig
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Duration of batteries and maximum memory data storage capability (to determine length of line that can be inspected in one run for a given flow rate)
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Installing permanent position markers for locating the position of the pig along the line
The types of valves (check, gate, ball, etc.) and the minimum bore of the valves that the inspection pig will have to pass through. Magnetic Flux Leakage (MFL) and Ultrasonic (US) inspection tools are used to detect wall metal loss. Presently, MFL tools are more widely used due to the limitations of Ultrasonic inspection tools. Since Ultrasonic tools require a liquid couplant, these tools cannot be used to detect corrosion damage in gas or mixed phase pipelines unless the tool is run inside a liquid or gel slug. In addition, Ultrasonic tools require much cleaner pipe surfaces than MFL tools. Ultrasonic tools may not detect serious corrosion pitting due to minimum wall thickness requirements. Ultrasonic tools are capable of providing direct quantitative measurement of the pipe wall. As Ultrasonic technology improves it will become more competitive with MFL technology, but it will never completely replace MFL technology due to its limitations. There are two types of MFL inspection pigs: conventional and advanced. Conventional (these are also called first generation or low resolution MFL inspection pigs) MFL pigs provide qualitative information which is sufficient for many applications. Advanced (these are also called second generation or high resolution MFL inspection pigs) MFL pigs provide quantitative information after some data processing. The most widely used conventional MFL pigs are: Linalog of Tuboscope Pipeline Services in Houston, Texas, USA, Vetcolog of Vetco Pipeline Services in Houston, Texas, USA, and Magnescan of Pipetronix in Toronto, Canada. The most widely used advanced MFL pig is the British Gas On-Line tool of the British Gas On-Line Inspection Center in Newcastle, UK. Other advanced MFL pigs are under development and should be on the market soon. The number of sensors vary with each advanced MFL pig. One vendor claims to have a high resolution MFL pig, but his tool has only a few more sensors than a conventional Linalog pig. The greater the number of sensors, the higher the resolution of the MFL tool. Inspection cost increases as resolution increases, therefore use high resolution tools only when it can be economically justified. The most widely used ultrasonic metal loss smart pigs are the Ultrascan by Pipetronix of Karlsruhe, Germany, NKK in Tokyo, Japan, and Flawsonic by TDW in Tulsa, Oklahoma, USA. The following should be considered when planning an inspection run and choosing a pipeline inspection contractor:
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Pipeline Medium (gas, liquid, or mixed phase) and the effects on the inspection pig
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The flow rate range required for satisfactory inspection
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The maximum operating temperature of the inspection tool if it is to be used to inspect hot oil service pipelines.
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The minimum bore of the valves that the inspection pig will have to pass through
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The number of runs required to get a complete inspection due to maximum range limitations caused by battery, memory data storage, or tool speed limitations
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The pipe wall thickness(es) of the pipe to be inspected
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The method of locating the position of the pig along the line and the number of location reference points required
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Any obstruction that may trap the inspection pig such as check valves, tight radius bends, changes in pipe diameter, and unbarred large diameter side taps
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It is always desirable to run a geometry pig before running other inspection pigs. A geometry pig will detect obstructions that may trap a larger inspection pig such as a metal loss inspection tool. Geometry pigs should always be run on pipelines that have never been inspected. In addition, it is desirable to run geometry pigs on pipelines that may have been damaged between inspection runs by earth movement or other outside forces.
•
If pigging facilities exist, are they capable of launching and recovering the inspection pig without modification. If no pigging facilities exist, where will either permanent or temporary pigging facilities have to be installed.
Shear wave ultrasonic crack detection smart pigs are under research and development by both Pipetronix and British Gas On-line. These pigs are expected to be on the market soon. In addition, Pipetronix is close to marketing a Pulsed Eddy Current crack detection pig. There are other inspection tools on the market and many improved devices are under development. Consult with Chevron Research and Technology Company Materials and Equipment Engineering as to the experience with and evaluation of various inspection tools.
454 Line Pressure Control and Relief The primary function of facilities for main line pressure control is either to maintain a full line downstream of hydraulic control points on liquid pipelines (preventing slack-line conditions) or to protect the pipeline from overpressuring in the event of inadvertent or emergency closing of a mainline block valve. Overpressure protection (relief valves or shutdown switches) on pump or compressor discharge piping should be provided as part of station facilities so that station discharge pressure does not exceed maximum allowable operating pressure for the line. Section 402.2.4 of Code B31.4 for liquid pipelines requires protective equipment to be provided so that variations from normal operations do not cause a pressure rise
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of more than 10% of the internal design pressure at any point in the piping system and equipment. Section 845 of Code B31.8 for gas transmission lines covers Control and Limiting of Gas Pressure. Section 845.212 describes types of protective devices, and Section 845.3 covers design requirements for pressure relief and pressure limiting installations. Section 845.411 requires pressure relief facilities to have the capacity and be set to prevent line pressure from exceeding the MAOP plus 10%, or the pressure which produces a hoop stress of 75% of SMYS, whichever is lower. Referring to the hydraulic profile for a liquid pipeline system, the hydraulic gradient at no-flow, with pumps still operating, becomes a horizontal line as indicated in Figure 400-19. Prudent pipe design usually provides sufficient wall thickness so that allowable pipe stress is not exceeded by closing a block valve against operating pumps or compressors. However, there are situations where, because of a large ground elevation differential, it is economic to provide pipe wall thickness adequate for normal operating line pressures rather than substantially greater wall thickness needed for shutoff conditions. Line relief must then be provided, discharging into tankage specifically assigned to relief at the terminal or at relief stations. Fig. 400-19 Hydraulic Profile: Normal Operation, Shutoff, Relief Flow
The hydraulic profile for a line relief situation is indicated in Figure 400-19. In this example, the line pipe is of the same grade and wall thickness for the entire length, and, with no-flow shut-off at the terminal, the pipe at the lower elevations upstream of the terminal would be overpressured. The hydraulic gradient that keeps line pressures below the maximum allowable pressure establishes the maximum relief set-
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pressure and the minimum relief flow that the relief system must handle. To be conservative, the relief facility should be designed for somewhat lower set pressure and greater flow than indicated in Figure 400-19. For pressure control equipment, see the Instrumentation and Control Manual, or consult with the Instrumentation and Control Group of the Engineering Technology Department. For line relief, if needed to prevent overpressuring of liquid pipelines under shutoff conditions or to limit surge pressure rises, the Grove Flexflow valve system, manufactured by Grove Valve and Regulator Company of Oakland, California, or similar equipment, is recommended. This type of valve is designed for pipeline application, for which conventional safety valves are not normally suitable.
455 Slug Catchers For pipelines carrying mixed-phase fluids (usually gas, oil, and water) or wet gas from which water or condensate may accumulate at sagbends, fluctuating liquid slugs that are either carried with the flow in normal operation or swept ahead of scrapers must be handled at the end of the line. Slug catchers of various designs are installed at the end of the line or at intermediate points to separate the liquids and provide volume for liquid level fluctuations. Typically, the slug catcher may be a knockout vessel, or banks of pipe lengths, called a harp, which act as long horizontal separators (see Figure 400-20). Fig. 400-20 Slug Catcher
Design of the slug catcher must both effect vapor-liquid disengagement and provide sufficient volume to contain the slug. Hence, one must make a realistic determination of the largest possible slug relative to the capacity of the liquid outlet line, and then be generous in sizing the slug catcher. Where slugs are expected with scraper runs, the frequency of scraper runs will be a factor in establishing the slug volume.
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The pressure rating of the slug catcher should be the same as the pipeline upstream of the slug catcher. Often, the harp is more economic than a heavy-wall large vessel. The incoming pipeline is manifolded into the harp’s parallel lengths of pipe, which are slightly inclined so as to drain toward the vapor and liquid outlets on each pipe. These outlets are manifolded to vapor and liquid headers. This arrangement allows for future increase in capacity by adding more parallel lengths of pipe.
456 Vents and Drains Installation of vents and drains is to be avoided on cross-country pipelines unless there are exceptional circumstances, such as a line installed on a bridge where the pipe can be isolated by block valves at each end of the crossing. Properly designed line scrapers will adequately sweep the line, both for full-filling with liquid and for dewatering with gas following a hydrostatic test—situations that require vents and drains in plant piping. However, installation of vents at liquid line high points is needed where scrapers cannot be run. Otherwise, air or other gas might be trapped, resulting in decreased flow capacity.
457 Electrical Area Classification Electrical area classifications for scraper traps, block valve assemblies, and other facilities on the pipeline should comply with the guidelines contained in API Recommended Practice 500C, Classification of Locations for Electrical Installations at Pipeline Transportation Facilities.
458 Line Markers Pipeline location markers and signs indicate the location of buried pipelines to protect against damage to the line by others working in the area and to give notice regarding the line service and proper contacts. Section 434.18 of Code B31.4 and Section 851.7 of Code B31.8 require installation of line markers, and API Recommended Practice 1109 gives guidelines for their installation. Markers should be located at each side of highway and road crossings, railroad crossings, water crossings, fence lines, and wherever feasible at such intervals that at least one marker can be seen anywhere along the route. Aerial patrol markers are used on cross-country pipelines to guide aircraft patrolling the pipeline route and aid in identifying locations along the route. At one mile intervals these markers have “milepost” signs visible from the air, and at changes in direction of the route, signs show arrows indicating the new direction. At stations and facilities along the route such as block valves and scraper trap manifolds, there should be signs showing the name of the operating company and contact information.
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460 Corrosion Prevention Facilities 461 General External corrosion of pipelines is controlled by application of a pipe coating and nearly always by a cathodic protection (CP) system requiring design and installation of facilities along the line. Cathodic protection is required by regulations for pipelines under governmental jurisdiction. Control of internal corrosion, if anticipated to be a problem, is handled either by internally lining the pipe, or by injecting a corrosion inhibitor into the fluid. In either case, no facilities along the pipeline are required. The following sections briefly describe cathodic protection facilities for pipelines so that they can be incorporated in overall system design. There are two types of cathodic protection systems: impressed current and galvanic anode. Generally, for long cross-country pipelines, the impressed current system is the economic choice. However, an economic analysis should be made to determine the proper choice. Data on soil resistivity is important for the design of a cathodic protection system. A field survey along the route early in the project design phase is usually warranted, and should be made in conjunction with the geotechnical survey. For design principles and details refer to the Corrosion Prevention Manual, and to the Materials and Engineering Analysis Division of the Engineering Technology Department. In many cases it is advisable to engage a technical contractor specializing in cathodic protection.
462 Impressed Current System for Cathodic Protection In the impressed current system, a “drain” cable connects the pipe to the negative terminal of the DC source, and an “anode” cable from the positive terminal connects to nearby buried anodes. Power sources spaced at intervals along the line are used to provide a DC current. These are usually rectifiers supplied with AC either from station power, or public utility power at intermediate points. Spacing is influenced by soil conditions and the quality of the pipe coating. At remote locations where power is not available, solar photovoltaic systems and wind-powered generators have been successful. If possible rectifier stations should be readily accessible.
463 Galvanic Sacrificial Anodes for Cathodic Protection In this system galvanic anodes (aluminum, magnesium, or zinc) connected by cable to the pipe are buried at close intervals along the line, either near the pipe or attached directly to the pipe. The anodes are consumed as current is produced, and thus must be designed to be sufficient for the life of the pipeline. See Section 900 for a discussion of bracelet anodes for offshore pipelines.
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464 Insulating Flanges and Joint Assemblies Insulating flanges or joint assemblies are used to electrically isolate the cathodically protected pipeline from connecting lines and station and terminal piping. Insulating gaskets and stud sleeves and washers are incorporated in a flanged connection, preferably a pair of standard line flanges that are separate from a valve. Manufactured insulating joint assemblies, welded into the line, are available, and for smaller pipe insulating couplings or unions can be used. Insulating flanges and joint assemblies should be installed above ground wherever possible so they will remain dry and can be readily inspected. If it is necessary to install them below grade, they must be either in a readily accessible, well-drained dry box, or carefully encapsulated with an insulating coating and buried. The insulating gasket, sleeves and washers should not be painted, since the paint film might be of sufficiently low resistance to allow current across the insulating flange. Similarly, dust and dirt settling between flange faces can affect the insulating effectiveness. This can be prevented by wrapping insulating tape around the flange circumferences to cover the gap between flange faces.
465 Cathodic Protection Test Stations and Line Bonding Connections Electrical test leads are connected to the pipe at intervals between rectifier stations or galvanic anodes, often as close as one mile apart, to determine the level of cathodic protection by measuring pipe-to-soil potentials and flow of current in the line, and to make other electrical measurements. Leads are also connected between parallel or crossing pipelines to determine the potential between separate systems or to bond the cathodic protection systems. The leads are usually brought up to a test box that is mounted on a post. Test stations should be located so as to avoid interference with land use and be reasonably accessible. The physical connection of wires to the pipe is done with a thermite weld kit, such as the CAD weld system. See the Corrosion Prevention Manual, Section 500.
470 References
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1.
Guidelines for the Seismic Design of Oil and Gas Pipeline Systems. Committee on Gas and Liquid Fuel Lifelines. ASCE Technical Council on Lifeline Earthquake Engineering. New York: American Society of Civil Engineers, 1984.
2.
Kennedy, R.R. et al. Seismic Design of Oil Pipeline Systems, Journal of the Technical Councils of ACSE, Vol. 105, No. TC-1. New York: American Society of Civil Engineers, April, 1979.
3.
J.N.H. Tiratsoo. Pipeline Pigging Technology. Houston: Gulf Publishing Company, 1987.
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500 SCADA Systems Abstract This section discusses Supervisory Control and Data Acquisition Systems (SCADA) and provides checklists of options to be considered when installing or upgrading SCADA systems.
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Contents
Page
510
Overview
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520
General Description
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Master Station Functions
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Basic SCADA Functions
532
Application Functions
540
Hardware
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Master Station
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RTU’s and PLC’s
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Protocol
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Field Instrumentation
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Equipment Facilities
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Master Station
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RTU’s and PLC’s
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Communications Requirements
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Performance Criteria
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Master Station Hardware and Software
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Availability
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Communications
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RTU’s and PLC’s
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Projects
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Master Station
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RTU’s and PLC’s
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Communications
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Maintenance and Online Operations
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Maintenance
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Online Operations
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510 Overview "Supervisory Control and Data Acquisition" (SCADA) systems are real-time computer systems used to monitor and control equipment or facilities located over long distances. Real-time means that the information retrieved and presented for monitoring and control is 5-60 seconds old. Devices that are controlled may be in unmanned, isolated locations, hundreds of miles away from the operator or user of the SCADA system. While SCADA systems impact the measurement, dispatching, scheduling, and accounting of our pipeline systems, this section does not specifically cover these four areas. This section provides information for project, operations, and maintenance personnel covering master station hardware and software, communications, and field equipment. For pipeline operations, a SCADA system enables one operator from one central location to safely and efficiently move commodities through miles of pipelines. SCADA systems are not unique to pipeline systems, but are also used for electric power and water distribution systems. The SCADA system will assist maintenance people in tracking, locating, and resolving problems in the pipeline systems. The Company has operational SCADA systems in place for pipelines that transport crude oil, petroleum products, CO2, natural gas, LPG, and phosphate slurry. Figure 500-1 is an example of a simple pipeline system transporting crude oil from a production platform to two terminals. Figure 500-2 illustrates how a SCADA system could be incorporated to enable monitoring and control capabilities from a central master station location. In this example, operators at the master station (24 hours a day, 7 days a week) monitor the various temperatures, pressures, flow rates, tank levels, valve status, and pump status on the pipeline. The operators may also start and stop pumps and open and close valves to safely transport the crude oil from the platform to the two terminals.
520 General Description A SCADA system has three primary components: master station hardware and software, communications equipment, and remote terminal units (RTU’s) or programmable logic controllers (PLC’s). Refer to Figure 500-3 for a “typical” SCADA system architecture. Generally, the SCADA master station is centrally located in the operations area. The master station hardware consists of computers, disk drives, magnetic tape units, visual displays with keyboards for the operators or dispatchers and printers for printing reports and logging alarms. The master station software consists of standard SCADA software to periodically scan values in the field, to execute operatorinitiated commands, and to alarm abnormal conditions. Other software at the master station performs pipeline applications such as leak detection and batch tracking. The master station sends and receives data from the field via communication links. These links may be radio, telephone, cable, microwave, or satellite.
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Fig. 500-1
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Fig. 500-2
SCADA System
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At the other end of the communications link at the operating facility is either an RTU or a PLC that monitors or controls equipment via field instrumentation. Figure 500-3 shows examples of typical data monitored by SCADA systems and typical supervisory control functions.
530 Master Station Functions Pipeline SCADA systems provide a set of basic SCADA functions that are similar in most SCADA systems and also provide application functions that are peculiar to pipeline systems. These functions are implemented in various ways in different systems.
531 Basic SCADA Functions Following is a list of some basic SCADA functions:
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Scanning data periodically or on demand from RTU’s or PLC’s
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Dispatcher-initiated control of valves, pumps, and analog setpoints
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Analog limit processing for high/low operating values and rate-of-change alarms
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Accumulator/meter processing
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Maintaining communication error statistics
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Tagging for points off-scan, alarm inhibited, or in alarm
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Building a dynamic, chronological list of alarms and abnormal points
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Permitting tabular and graphic displays both of which can be hardcopied
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Annunciation of abnormal conditions to the dispatchers
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Dispatcher acknowledgement of alarms
•
Logging of dispatcher events
•
Online data base and display editing capability
•
Report generating capability
•
Graphic trending
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Fig. 500-3
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Typical SCADA System
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532 Application Functions Typical application functions for pipeline SCADA systems are leak detection, batch tracking, and meter proving. Computer-assisted leak detection may take several forms in SCADA systems for individual pipeline systems: • • • •
net barrel line balance pressure pack volume balance pressure point monitoring predictive pressure profiling
Leak detection limits are checked periodically for violations. The periods range from each minute to daily, weekly, or monthly intervals. They are alarmed to the dispatcher as required. Batch tracking is used to monitor the progress of an interface between two different segregations (crudes or products) as they progress through a pipeline. The dispatcher is provided an estimated time of arrival for the batch interface at the pipeline terminal and a barrels-to-go value. Meter proving software is provided at some master stations to calculate a meter factor for a given meter for the operator’s use from data on successive meter proving runs. (For details on programming API tables for 60°F volume corrections, refer to the API Manual of Petroleum Measurement Standards, Chapter 11.1— Volume Correction Factors, Volume X—Background, Development and Program Documentation.) Record keeping and report generation are important functions of SCADA systems— both for operations and maintenance personnel and to comply with regulatory policies. Some typical reports are: • • •
Hourly DOT report (pipeline pressures) Inventory control reports Daily RTU communications statistics report
For more details on specific functions and dispatcher capabilities, refer to the Point Arguello SCADA System Functional Specification (PL-144) and the MODSCAN Functional Specifications and Operator Procedures for the New Orleans Empire Pipeline SCADA Project. API Publication No. 1113 "Pipeline Supervisory Control Center Checklist" also provides a list of functions to consider for SCADA master stations.
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540 Hardware 541 Master Station Figure 500-4 is a typical master station hardware configuration with the following noteworthy features:
Fig. 500-4
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Redundant hardware with a prime online device and available backup unit
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Multiple CRT’s with dedicated keyboards (or one keyboard shared with multiple CRT’s) for operator interface via tabular and graphic displays
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Dedicated CRT for alarm/events file
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Hardcopy devices for alarm/events, reports, and copying displays
•
Graphic trending on any CRT
•
Multiple channels for RTU/PLC communications; RTU’s and PLC’s may be party-lined on a single line
•
Magnetic tape units for archiving reports and logs
•
Master station computers with dial-up modems for off-hours access by hardware and software maintenance personnel
Typical Pipeline SCADA Master Station Hardware Configuration
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542 RTU’s and PLC’s Remote hardware consists of RTU’s or PLC’s: RTU’s are nonprogrammable or "dumb"; PLC’s are programmable (i.e., "intelligent"). RTU’s are used in locations where we simply monitor data and respond to scan and control requests from the master station. PLC’s are an option in locations where we want: PID (proportional integral derivative) control for control valves, to have safety shutdowns to protect equipment, permissive control sequencing, or other operational functions supported, like meter proving. As pump stations are upgraded, it is common to install PLC’s to replace existing station relay logic safety systems and provide a local touch-screen CRT for local operator interface for presenting data, alarms, and initiating controls.
543 Protocol The master station and RTU’s or PLC’s communicate via some "protocol," which is a predefined format for the hardware and software to communicate. Generally, each SCADA system, RTU, and PLC has a standard protocol peculiar to that vendor. But more often SCADA systems, RTU’s and PLC’s are adapted via programming to be able to communicate in a standardized protocol for a particular SCADA system.
544 Field Instrumentation Field instrumentation includes devices that present analog, digital, or accumulator signals to the RTU or PLC or accept either analog or digital signals from the PLC. Instruments that feed signals to the PLC include pressure, temperature, voltage, current, and vibration transducers. SCADA can receive analog signals (4 to 20 mA, for example,) that represent a percent of full scale measurement or on-off signals (contacts) that may represent switch closures or an alarm condition. The signals from SCADA include start/stop, open/close commands, and analog signals that represent a set point or position. Examples of field instruments are: • • • • • • • •
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Pressure and temperature transducers Tank level reading devices, Flow and pressure controllers Meters Densitometers Limit switches for valve status Scraper detector switches Low and high pressure switches
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Each instrument has its own characteristics that must be selected to match the expected operating situation and the RTU or PLC requirements. Additional information is available from the following sources: •
Electrical Manual
•
Instrumentation and Control Manual
•
API Recommended Practice 2350, Overfill Protection for Petroleum Storage Tanks
550 Equipment Facilities 551 Master Station Master station hardware is usually split between two rooms: a dispatch room and a computer room. The dispatch room contains the operators’ consoles with CRT’s and keyboards, voice communications equipment, and some printers or loggers. The computer room contains the remaining hardware of interest to maintenance personnel. Consideration should be given to the following items when setting up master station facilities: • • • • • • • •
Raised floor with removable floor panels Temperature and humidity control Electric power conditioning or an uninterruptible power supply (UPS) Emergency backup generator Fire protection (usually with halon) Nonglare, adjustable lighting Security for restricted access Telephone and radio facilities
552 RTU’s and PLC’s PLC’s and RTU’s have less stringent environmental requirements than master station hardware. PLC’s are usually located inside control rooms at stations and may require air conditioning and heating. RTU’s may be mounted outside in appropriate cabinets for the environment.
560 Communications Requirements The Communications Technology Department (CTD) of Chevron Information Technology Company (CITC) provides maintenance services for existing communications facilities and will provide new communications facilities to meet the requirements of OPCO’s.
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After identification of voice and data requirements for SCADA systems, CTD can determine the appropriate type of equipment to use: microwave, radio, phone lines, fiber optics, cable, or satellite. The review of requirements for data circuits for SCADA systems should consider the following items: • • • • • • •
Number of points and RTU’s/PLC’s System update times or scan rates BAUD rates (transmission rates) Channel loading levels Expansion requirements Reliability or percent availability Redundancy
570 Performance Criteria One reason for upgrading or replacing SCADA master stations is lack of space or CPU power to handle operating requirements. Therefore, it is important to establish and measure performance targets on SCADA systems to know the current state of systems and be able to forecast their life expectancy.
571 Master Station Hardware and Software The following are some considerations for master station hardware and software.
Sizing Consider existing, known future requirements and spare space when sizing SCADA systems. Parameters include the following: • • • • • • • • • • • • • •
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Number of RTU’s and PLC’s Number of telemetered points by type (analog, digital, accumulator) Number of calculated points by type Number of tabular and graphic displays Number of communication channels Number of CRTs and keyboards Number of loggers Trending data (duration and frequency of collection, number of points) Number of calculations Number of consoles Number of pipelines Number of sections per pipeline Number of receipts per pipeline Number of deliveries per pipeline
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Initially SCADA systems should have 50-100% spare CPU memory and disk space. The number of communication channels, consoles, and loggers should be expandable. In general, one should know what the limits are of each parameter and what is required to expand each parameter.
Performance Performance testing should take place at the Factory Acceptance Test (FAT) before shipment from the vendor facilities and during Field Acceptance Test (Field AT) onsite before the system is operational. The Field AT is usually a subset of the tests executed during the FAT. An Availability Test is also executed onsite starting when the SCADA system is operational (see below). Performance testing may be executed on the operational system as required to collect data. The term Site Acceptance Test (SAT) is used to refer to onsite testing of SCADA systems. Sometimes this includes both the Field AT and Availability Test—sometimes SAT only references the Availability Test. Performance should be executed under conditions similar to the ultimate load the system is expected to handle. Spare memory and disk space for expansion should be unallocated during testing. RTU simulators and modified scan rates may be used to simulate loading conditions. Editors and trending should be active. Several samples of measurements should be taken during performance testing to accumulate minimum, maximum, and average values. Testing should be performed with backup devices offline to ensure that performance is not impacted. Typical performance-time measurements include the following: • • • • • • •
Display response Alarm acknowledge Control commands completion Change of state or analog limit violation detection Screen lock while hardcopying Dispatcher data entry response Failover
Other measurements to consider with respect to the computer system are: •
CPU free time (should average 50% or more)
•
System input/output (I/O) measurements (For example, if maximum disk accesses that a system should see are 30 accesses per second, then the performance target should be 15 accesses per second.)
•
Channel loading and system update times
572 Availability Availability is the percentage time that the SCADA system hardware and software is fully operational. Availability % = 100 (1 - (scheduled + unscheduled downtime)/total time)
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The target for the availability of a SCADA system should be 99.91%, which is less than 1-1/2 minutes of downtime per day. Another factor in availability is the number of unscheduled restarts. These may be caused by both hardware and software failures, and in general, the target should be no restarts. However, reasonableness will tell us that one unscheduled restart per day is too many and one per month may be tolerable. Master station hardware is configured with no single point of failure in mind. We can lose one CPU and still be 100% operational. An Availability Test is executed once a system is operational and lasts for 30 to 60 days during which time all scheduled and unscheduled downtime (and restarts) are recorded. The agreed test procedures must address how software failures will be handled and how failures of individual backup devices will be handled.
573 Communications All SCADA systems should have a display or report that tracks RTU/PLC communications error statistics. Our target for communications availability should be 99.5%. However, this percent is usually a percent of successful scans of RTU’s versus total scans attempted—not a percent of time that communications are available. The communications error statistics report should have the following features: • • • •
Errors in absolute values and percent Manual resettable period as well as hourly, daily, and monthly statistics RTU/PLC errors distinguishable from communication errors Errors reportable on an RTU, PLC, port, communication type, and vendor basis
574 RTU’s and PLC’s RTU’s and PLC’s should exceed the 99.91% availability expected from the master station.
580 Projects In addition to the following items, API Publication No. 1113, "Pipeline Supervisory Control Center Checklist", provides a list of items to consider when developing or modifying a pipeline control center.
581 Master Station The following is a list of the various phases of a SCADA master station project with items to keep in mind: •
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Estimating
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– – – •
A/R Preparation and Approval –
– •
Policy 560 requires CITC’s concurrence on hardware and software. Send A/R direct to ETD (Monitoring and Control Systems Division, Technical Services Department) for review and forwarding to CITC. Allow 2 to 3 weeks for this process. If communications equipment is impacted, then CITC should get CTD to concur as part of the above process (per Policy 564).
Functional Specification – – – –
•
Figure approximately $1MM for mid-size SCADA Appropriations Request (A/R) to support up to 100 RTU’s/PLC’s. Amount of operations input and field work is variable depending on existing conditions. Expect a minimum 12-month schedule from contract award to system operational.
See references from Section 530. Operations Representative must be active in the review of the specification document. This is a specification of what the client wants. The more thorough the understanding and involvement of Operations here, the more likely the process will result in an end-product satisfying the client’s need.
Business and Legal Requirements Whether the SCADA system is being provided by the vendor or by ETD, the following points should be considered. This list is not all inclusive. For more details, refer to the Point Arguello SCADA Contract PA 84057 and ETD Work Order No. 9450 established for the New Orleans Empire Ostrica SCADA Consolidation Project. – – – – – – – – –
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Well-defined progress and milestone payment stipulations Clear guidelines for vendor-client communications Deliverable items including software source code Dates for customer inputs to the vendor/ETD for data base, display, and report definitions (significant operations involvement is beneficial) Mostly reporting and contents System shipment Changes in work and how to handle Defaults, delays, and liabilities Warranties
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•
Testing –
– •
Installation and Commissioning – –
•
–
– –
ETD is currently providing a MODSCAN SCADA system running on DEC’s PDP family of 16-bit CPU’s. ETD has a project in progress to migrate MODSCAN’s functionality to the 32-bit VAX environment—known as the UNICORN system Other vendors to consider for pipeline SCADA projects: Control Applications, Modular Data Systems, Valmet (Sentrol), and Texas Instruments (Rexnord/Tano).
Selection Criteria – – – – – – – –
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Usually an operations responsibility with project personnel bringing one Operations Representative up to speed on the system, who then trains the Dispatchers For the first few days that a SCADA system operational, project or operations personnel thoroughly knowledgeable in the operation of the SCADA system hardware and software should physically sit with the dispatchers 24 hours a day to answer questions as they arise; this in addition to more structured training.
Vendors –
•
Should be clearly scoped in functional specification Should be part of acceptance criteria on final milestone
Training –
•
Coordination and planning required between RTU/PLC field personnel, dispatching, communications, hardware, and software personnel Point-to-point RTU/PLC commissioning needed to verify the data base and displays
Documentation – –
•
Requirements for a FAT, Field AT, and SAT clearly scoped and performed; test plans written by the SCADA vendor or ETD, but approved by the responsible engineer before testing begins. Optional baseline testing before FAT, a useful progress milestone
Field-proven hardware and software Maintainability Availability of hardware and software support personnel Cost Expandability Meeting functional requirements Off-the-shelf, standard hardware and software versus custom Reliability
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582 RTU’s and PLC’s PLC projects are similar to master station projects in that both hardware and software are involved and require clear scoping so that the client understands what the end product will be. PLC projects can range from $50M to $100M depending on the scope. Possible PLC vendors include Siemens, G.E., Allen-Bradely, Westinghouse, Modicon, and Texas Instruments. RTU projects are less complex than PLC’s because any software work is usually limited to protocol issues. RTU vendors include Texas Instruments, Computer Products, Control Applications, and Valmet (Sentrol). The criteria for selecting PLC’s and RTU’s is essentially the same as listed above for master station projects. In addition, operating areas should standardize on one RTU vendor and one PLC vendor to minimize the technical expertise required with various vendors and to reduce the spare parts inventory requirements.
583 Communications Communications projects are handled by CTD. We identify our requirements as discussed in Section 560, and CTD prepares the A/R and handles the project.
590 Maintenance and Online Operations This section contains some ideas to keep in mind regarding the daily support for SCADA systems.
591 Maintenance Inventory requirements for hardware spares will be subject to your maintenance philosophy: repair to board level or repair to component level or use hardware maintenance contract or operating personnel. Whole unit spares may sometimes be assembled and used for hardware board testing, software development, and/or operator training. Hardware maintenance activities should be logged for tracking recurring problems with specific components and for tracking general requirement for maintenance. Two levels of SCADA software maintenance are required. The first level includes making data base changes, making display changes, editing system parameters, tuning leak detection limits, restarting the SCADA system, supporting the checkout of RTU’s and PLC’s, and making backups of the software. The first level support should be readily available on a daily basis. The second level of software support is to understand the SCADA software design to be able to make programming changes and correct software problems. The second level of software support should be onsite through SAT and continue onsite
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as required until the software is stable enough not to require a daily presence. SCADA software support (levels one and two) may be provided by Operations personnel, ETD, or by a contractor. The following items should be logged and documented from a maintenance viewpoint: •
Software problems
•
Software changes
•
Log of changes made to the online system
•
Technical notes for the programmer/engineer who is responsible for level one and level two software maintenance support
•
Master station block diagrams
•
Communications configurations
592 Online Operations The important item here is periodic client or user feedback to the project personnel providing SCADA systems and to the maintenance people supporting SCADA systems that the SCADA system is satisfying operations requirements. Timely response from CTD is required when operations reports that communications failures exist. Restart and availability data should be reviewed periodically and compared to targets. Communications availability data should be reviewed periodically and compared to targets. Alarm limits (especially leak detection) need to be reviewed periodically to ensure they are set appropriately. False alarms due to field instrumentation errors or due to lack of calibration need to be minimized to maintain dispatcher confidence in the SCADA systems. Dispatcher notes need to be maintained to supplement project delivered documentation whenever SCADA system changes are made impacting the way dispatchers operate.
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600 Construction Abstract This section discusses the methods and practices of pipeline construction on land. It presents brief descriptions of pipelining activities from grading to cleanup. Within these descriptions are recommendations, tips, and hints on ways to obtain a better product. It covers safety and general installation considerations, welding practices, treatment of coatings, crossings and appurtences, and guidelines on contract administration and construction planning and organization activities.
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Contents
Page
610
Safety
600-3
620
General Installation
600-4
621
Construction Reconnaissance
622
Front-End Operations
623
Clearing and Grading, Trench Excavation, and Padding
624
Pipe Stringing, Bending, Lineup, and Welding
625
Coating
626
Lowering-In, Backfilling, Grade Restoration, and Cleanup
627
Tie-Ins and Weld Repairs, Cathodic Protection Test Stations, Line Markers
628
Revegetation
629
Timing of Spread Operations
630
Welding
631
Regulations and Codes
632
Welding Procedure Qualifications
633
Welder Qualification
634
Weld Repairs
635
Arc Burns
636
Field Welding and Construction Conditions
640
Coatings and Linings
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650
Crossings
600-26
660
Appurtenances
600-28
670
Field Supervision Organization
600-29
680
Construction and Construction Service Contracts
600-30
681
Contracting Plan
682
Pipeline Construction Contracts
683
Contracts for Supplemental Personnel Services
690
References
Note
600-32
Note on Regulations, Codes, and Construction Specifications
The Code of Federal Regulations Title 49, Parts 192 and 195, and ANSI/ASME Codes B31.4 and B31.8 contain sections pertaining to pipeline construction methods. State regulations may have further requirements. Many sections of these codes give general guidelines with few specific requirements. The Company construction specification should incorporate all relevant regulation and code requirements as well as Company specifications for the particular pipeline project. If field changes are made that deviate from or supplement provisions in the construction specification, Company field personnel should refer to federal and state regulations and the ANSI/ASME codes to ensure compliance. Note
Note on Terminology
The pipeline right-of-way on a property has a specified width within which the Company has the right to construct and maintain one (or possibly more) pipelines with appurtenances. Payments are made to landowners for this right, and to landowners or tenants for all damages resulting from construction or maintenance both within and outside the defined width of a right-of-way. Construction forces commonly use the term right-of-way to describe the full construction working strip needed for construction of the line, very often a greater width than the actual right-of-way. The contractor should not encroach on lands outside the agreed working area. A pipeline spread is a single complete construction operation engaged in installing all or part of the line. Accordingly, a long line may be constructed by a single spread if time allows, or by two or more spreads (by the same or different contractors) proceeding concurrently on separate sections of the system. A pipe joint is a separate length of pipe, usually about 40 feet or 60 feet long, as shipped from the mill, A double-joint is made by welding two joints together at a field double-jointing yard before the pipe is strung along the pipeline route. A field joint is a field-applied corrosion coating over the uncoated (cut-back) ends of plantcoated pipe at the weld joining two pipe joints.
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610 Safety Construction contracts, practices, and procedures must incorporate safety requirements to protect: •
Company and contractor personnel and equipment
•
Pipeline facilities under construction
•
Facilities of the Company and others lying within and adjacent to the pipeline right-of-way and construction working area
•
Landowners, tenants and property, livestock, and crops on lands the pipeline crosses
•
The public, their property and lands
Specific construction operations and hazards that are likely to need particular attention are: • • • • • • • •
Excavation sloping and shoring Blasting Radiation sources (welding and radiography) Grass and brush fires Work over water Crossing roads, pipelines, cables, overhead power, and telephone lines Parallel existing pipelines Testing and dewatering
Company and contractor operations must comply with federal, state and local regulations. Construction and service contractor compliance with these regulations is required by contract terms and conditions. It is a responsibility of the Company field organization to monitor and ensure the contractor’s compliance, but it is important that the proper contractual relationship be maintained in giving directives and instructions to contractors. Regulations and standards of the Occupational Safety and Health Administration (OSHA) apply to construction activities. If pipelines cross lands subject to the Mining Safety and Health Administration (MSHA) pipeline construction work must comply with its regulations even though not a mining activity. Pipeline construction work is generally classified as a peculiar risk under the law. Industrial injuries can be severe and can expose the Company to significant liability. Recent court decisions (Jimenez, 1986) have held that an owner may be liable if a contractor’s employee is injured and the owner makes no effort to warn of the risk involved. Before construction activities begin the Company field construction organization should develop and subsequently maintain:
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•
An accident-prevention program for the field organization, including appropriate safety and first-aid equipment, periodic safety meetings, and safety bulletins
•
List of doctors and hospitals, with names, addresses, and telephone numbers to be called in event of any injury—for both Company and contractor personnel
•
Arrangements for ambulance services and helicopter or air transport as appropriate
•
Fire-fighting procedures, with list of contacts for local fire-fighting agencies
•
Contact and procedures with Underground Service Alert Center or equivalent agency coordinating information on underground facilities
•
List of contacts for companies and agencies controlling facilities such as pipelines, power and telephone lines, highways, railroads, irrigation systems, and waterways
•
Procedures for dealing with damage to oil and gas pipelines and resulting spills
•
Procedures for preparation and distribution of accident and incident reports to the Company and authorities including notification to Company management in cases of serious incidents
•
Procedure for dealing with a bomb threat or similar event
Company and contractor communication systems are vital in emergency situations, and field personnel should be fully informed regarding use of communication equipment and facilities. Where construction is in the vicinity of an Operating Company pipeline system, key construction personnel should have mobile radios with the same frequency as the operating system dispatcher. Field personnel should have a directory of personnel to be contacted for various types of emergencies. Early consultation with an environmental/safety engineer of the local Operating Company is recommended, with intermittent reviews during the construction period.
620 General Installation This subsection briefly describes pipe laying operations. Other subsections provide further information on safety, welding, coatings and linings, crossings, and appurtenances. Also see Section 580 of the Piping Manual for guidance in pipe storage and handling. Reference [1] provides an excellent description of pipeline history and construction practices. It is especially well illustrated with color photographs. Reference [2] also describes many features of pipeline construction. Section 200 of this manual covers route selection, permit and right-of-way acquisition, environmental and technical investigations, and alignment surveys. Most of these functions will have been completed prior to the start of pipeline construction, although there will be continuing activity through the construction period by:
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•
Right-of-way and land agents in finalizing acquisition of permits and rights-ofway, contacting landowners and authorities during construction (coordinating with Company field personnel), settling construction damage payments with landowners, and obtaining construction damage releases
•
Environmental survey teams investigating archeological sites or wildlife activities not evident during surveys made in advance of construction
•
Land survey crews staking the route alignment ahead of construction, surveying minor route changes, and getting as-built data for record drawings
Before construction starts: •
Route alignment surveying should be done so that flags, visible from one to the next, identify the alignment
•
Location of existing parallel pipelines should be marked
•
The conditions of construction and restoration for each of the properties and lands covered by rights-of-way and permits, and for the existing highway, roads, pipelines, power and telephone lines, irrigation systems, and railroads, should be listed in an organized, readily understood form for use by Company and contractor construction personnel
•
Arrangements should be in hand for receiving, unloading, and temporary storage of pipe, field coating materials, casing pipe (if cased crossings should be required), valves and fittings, and other bulky items
621 Construction Reconnaissance Company and contractor construction representatives should reconnoiter the pipeline route well ahead of construction. The purpose of the reconnaissance is to discover construction difficulties that may be overcome by adequate advance planning and to locate sections of the route that may involve unusually high damages. By anticipating these problems well ahead of construction, it will be possible to work out the best plan for minimizing both damage and inconvenience to land owners, as well as construction problems. Occasionally, it may be desirable to relocate short sections of the pipeline. Although this requires additional surveying and additional work on the part of the right-of-way acquisition personnel, sufficient advantages may accrue to the Company to make it worthwhile. Relocations of the line may be justified if the Company benefits, either financially or by securing better workmanship—but one should take care to distinguish between relocations mutually beneficial to the Company and the contractor and those requested by the contractor solely for his convenience. The Company construction representative can determine areas in which construction may prove difficult and, thus, where the contractor’s operations should be more closely inspected.
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Land owners along the right-of-way must be contacted well ahead of construction by a construction representative or right-of-way agent, or both. This contact serves to keep the land owners informed of construction progress and to review special construction conditions that may or may not show in the right-of-way agreements. Obstacles such as buried lines, culverts, irrigation ditches, siphons and orchards should be discussed with the landowners, locations established precisely, and construction procedures discussed in order to minimize inconvenience. Agreements with property owners regarding reasonable special conditions during construction must be documented, distributed and updated for use by contractor and Company field personnel to ensure that the owners’ special requirements are followed. The Company construction representative should make preliminary contacts with the various owners and authorities for existing facilities crossed by the line to establish procedures for notification and inspection of the crossed facility during construction.
622 Front-End Operations Front end activities include:
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•
Contacts with landowners by a Company representative to advise them of imminent construction activities, and by a contractor representative to arrange for access where needed to cross a property to the right-of-way, and to discuss feasible work methods, timing, etc., that minimize interference with farming and livestock. "Before-construction" photographs should be taken of farmed and developed lands, private access roads, etc., and clearly identified with date and direction of view
•
Construction staking, usually at 200-foot intervals and offset from the pipe center-line so that stakes are not likely to be disturbed by construction operations. The offset distance is influenced by the contractor’s work method and equipment, and by the terrain, which determines clearing width. Construction staking is preferably done by a survey contractor for the Company, but may alternatively be done as a subcontract to the construction contract
•
Construction of temporary gates in existing fences across the construction working strip so that construction equipment can move along the route. Existing fences must be well braced where cut, and the temporary gates must open easily and close securely
•
Staking of locations for extra-depth ditch, as required by right-of- way or permit conditions, will be done in accordance with written directives from the Company to the contractor; the directives will give the survey stationing for each location. If this staking is done by the contractor, it should be monitored by Company personnel to confirm that it is accurate and clearly identifiable. (Extra-depth excavation determined by the terrain is the contractor’s responsibility.)
•
Staking of locations for special excavation or backfill to provide for earthquake or soil instability
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•
For hot lines, staking of extra-depth excavation or special backfill compaction needed to restrain the line at sidebends and overbends
•
Staking of existing underground pipelines, cables, culverts, etc., where known
•
Marking of trees or other plants that must be preserved, and protecting them as needed with temporary fencing
•
Staking of locations for pipe wall thickness changes, in accordance with written directives from Company to contractor giving the survey stationing for each location
•
Staking for valve and other appurtenance locations
623 Clearing and Grading, Trench Excavation, and Padding Clearing and Grading Clearing includes the removal of all brush, shrubs, trees, crops, and other obstacles. In wooded areas bulldozers with timber blade attachments can clear brush and small trees. Power saws are used on trees too large to be pushed over by bulldozers. Salvage of merchantable timber is often required; specific arrangements must be made and defined to the contractor for disposal of nonmerchantable timber, stumps, brush, etc. Clearing and grading of the construction working strip provides a relatively smooth "roadway" for the construction equipment and vehicles involved in laying the line. Grading is usually done by bulldozers, but it may be necessary to use rippers or blasting to assist in removing boulders and rock. In level, lightly vegetated land, or after initial bulldozer grading, motor graders can be used effectively. Care is taken to prepare a path free of obstructions so that subsequent operations can move along without interruptions. Graded material—soil, rock, grass and light vegetation—is pushed to one side of the working strip. Topsoil should be segregated so far as practical, so that it is available for replacing on the surface after grade restoration in order to promote revegetation. Normally clearing and grading will be several miles head of the remainder of the spread, in order not to bottleneck subsequent operations. Temporary bridges, flumes, or culverts are placed as needed so that equipment and vehicles can cross irrigation and drainage ditches. In very steep terrain, detours ("shoo-flys") may be needed for construction vehicles, while equipment for ditching and laying are assisted by bulldozers and winching. If special measures are needed for erosion control during the construction period, these will be installed by the clearing and grading crews.
Trench Excavation Trench excavation ("ditching") includes all work to construct the trench for the pipe. The most favorable ditching conditions are level terrain and rock-free dirt, where one or more wheel trenching machines can move down the graded working strip, excavating a neat, vertical-sided trench and giving a uniform spoil bank. In
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rough terrain or in areas having boulders and cobbles in the soil, excavation is done by backhoes. At wet locations such as creekbeds, backhoes, draglines, or clamshells do the excavating. In rocky terrain heavy-duty rippers mounted on bulldozers are often adequate to loosen the rock for subsequent excavation by backhoes. When the rock cannot be handled by rippers, wagon drills or drills suspended from sideboom tractors are used to bore holes in the rock along the ditchline. The rock is then blasted, with the broken rock removed from the ditch by backhoes. Blasting should be done before the pipe is strung since flying rock will damage the pipe. If it becomes necessary to shoot rock in cultivated areas or in the vicinity of pipe or surface structures, the blast should be thoroughly matted to contain all fragments. Six-by-six timbers lashed side by side with wire rope typically provide an adequate mat. Also, it may be necessary to reduce the powder charge in order to blast safely. (Blasting must be conducted by certified individuals.) Blasting alongside an existing buried pipeline must be handled very cautiously to avoid damage. Normally delay-type blasting caps should be used to stagger the individual detonations in any one charge, thereby reducing the peak shock transmitted to the adjacent structure. The safe charge to use is a function of the formation (granite, shale, lava, caliche), the depth of the drill hole, and the proximity to existing structures; it must be determined locally by experienced powder men. Test holes may be dug alongside an existing line in the vicinity of blasting to determine if the pipe moves as a result of the shock. Because a pipeline cannot follow the bottom of the ditch precisely, a little extra depth should be allowed to ensure obtaining required cover. This extra depth can be obtained at almost no extra expense during the initial ditching operation, but reditching or, worse, lowering the line after it has been welded and lowered-in is a very expensive and unsatisfactory alternative. The Company construction representative should make it clear to the contractor that such rework is at his cost. Company personnel should avoid passing judgment on the depth of ditch, as this may be interpreted by the contractor as relieving him of his responsibility to obtain the required cover and may lead to poor workmanship or additional cost to the Company. (Company’s acceptance or rejection of depth of cover should be made as the pipe is laid, before backfilling.) At washes and gullies the trench must be cut well below the bottom of these depressions, with gradual approaches on either side to avoid vertical bends in the pipe. Frequently, loose soil will be bulldozed into a sharp wash during grading. "False ditch" or ditch constructed in loose soil overlaying the natural bottom will be eroded with the first rain and leave the pipe exposed or inadequately covered. The depth of ditch must be measured from the original ground elevation. Many right-of-way and permit agreements for cultivated or grazing land require topsoil to be removed, preserved, and replaced on top of the backfill. Normally, this requires ditching twice, removing the topsoil first and throwing it out farthest from the ditch. The remainder of the ditch can be completed with the spoil bank adjacent to the ditch. This will permit the backfilling operation to replace the spoil in the proper sequence.
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Although there are exceptions, sometimes as a normal practice (many production field lines), sometimes owing to special circumstances (unusual environmental conditions) trench excavation generally precedes pipe stringing and welding. The amount of open ditch ahead of the pipe laying should be limited as influenced by local conditions. In terrain where the ditch will hold for several days, it may be desirable to ditch several miles ahead. In terrain where the open ditch impedes farming or irrigating operations, the ditch must be followed closely by the entire spread in order to minimize damages. Entire crops may be lost if pipeline ditching cuts off irrigation water for too long a period. In some types of soil, an open ditch will not stand more than a few hours. This condition must be anticipated and the spread must be closed up to follow immediately behind ditching. Occasionally ditching progress will be slowed by difficult excavation, and the pipe lineup crew will catch up to the excavation operations. A contractor will then want pipe lineup and welding operations to overtake ditching because loss of laying progress is costly. When this happens, it is necessary to bend the pipe by guesswork, which frequently results in short cover or misplaced bends when the ditch is finally completed. This practice should be stopped as soon as it is discovered. This will give the contractor an economic incentive to improve ditching progress by adding more equipment or working longer hours. At locations or areas where there are existing crossing pipelines and cables, these underground facilities should be located using line locators and exposed by hand, then carefully excavated with mechanical equipment. Before uncovering the existing facilities, the owner or authority should be notified so he can take whatever action is considered appropriate. Sufficient depth of ditch should be excavated so that a 12-inch minimum clearance will be obtained between the new line and the crossed facility. Normally new lines pass below existing facilities. Wherever men will be working in trenches over 5 feet deep, the trench sides must be sloped or shored to conform with OSHA regulations. Similar requirements apply in Canada. When soil conditions are unstable, or become unstable, as after rains or because of heavy equipment working too close to the edge, excavations shallower than 5 feet must be sloped or shored. Figures 600-1 and 600-2 (from the Company Safety In Designs Manual) indicate recommendations on sloping for various soils. Spoil banks should be kept at least 2 feet from the edge of any trench. See the Company Safety in Designs Manual and OSHA Safe Work Practices 2226, Excavating and Trenching Operations. (Company field personnel should be aware that at least one court ruling determined that an engineering firm could be held liable for injury and death of a contractor’s employee for failure to take appropriate action after discovering that safe trenching methods were not being followed. In Canada also, Company personnel can be held responsible.)
Padding Where rock and rocky soils could damage the pipe coating during laying and covering of the line, suitable bedding and backfill material must be provided. As the first step in achieving rock-free material around the pipe, normally a minimum of 6 inches of dirt or sand is brought in from another source and placed in the ditch
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Fig. 600-1
Pipeline Manual
Angle of Repose for Sloping of Excavations
Fig. 600-2
Excavation Benching for Compact Soil
bottom. Preferably, this padding material is preferably spread uniformly along the trench, but it is often acceptable to place padding in about three-foot long piles at 15- to 20-foot intervals along the ditch. Alternatively, sandbags filled with dirt or sand may be used to support the pipe off the ditch bottom, but care should be taken that spacing is close enough so that bearing loads at the sandbags do not damage the coating. Arrangements for acquiring and hauling padding dirt are normally the contractor’s responsibility, but should be monitored by Company field personnel to ensure the contractor is not getting material without proper arrangements. Where there is extensive rock and a scarcity of bedding and backfill soil, costs to obtain and haul suitable material will be great and other alternatives to protect the coating such as a tough "rockshield" wrapping or a urethane foam should be considered. The rockshield should be perforated so that it does not shield the pipe from cathodic protection current. The construction specification must be clear on the shielding method to be used because of the cost significance in bidding and construction.
624 Pipe Stringing, Bending, Lineup, and Welding Stringing This activity includes functions related to the unloading, stockpiling, loading out, hauling, and stringing of pipe along the route. Pipe may be shipped by truck, rail, or barge and unloaded and stockpiled at previously selected strategic points along the line route. The pipe is loaded out from a stockpile onto stringing trucks and strung along the line as construction progresses. Stringing must be conducted so as not to damage the coating, dent pipe or scar bevels. Often stringing is done by a subcontractor specializing in pipe hauling.
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Company field personnel should confirm that the stringing foreman has full information on the locations along the line for changes in pipe wall thickness and coating. Prior to stringing, stockpiled pipe or pipe directly off-loaded from railcars or barges should be visually inspected. Cracked coatings, pipe that is dented and damaged in transit, and pipe with out-of-round ends normally should be repaired before being strung. Any transit damage should be documented so that claims may be made against the carrier and disputes with the construction contractor prevented. See Section 740 for recommendations on stockyard inspection. Field plants for yard coating, double-jointing pipe, or both may be established at one or more stockpile sites. Special handling is required to avoid injury to the coating and may involve padded trucks and unloading with special hooks. Because of its increased length double-joint pipe may require special-steering pipe trailers regulated by law.
Bending Changes in direction and elevation of the ditch require bending of the pipe to fit the contour. Side bends will be laid in a horizontal plane; over bends and sag bends in the vertical; and combination bends in three dimensions. Normally bends can be of sufficiently long radius so that they are bent in the field. Tight bends need to be made in a shop equipped for induction-bending and then shipped to the field. Sections 320 and 330 of this manual cover bending of line pipe. Care must be taken during field bending to prevent wrinkling of the pipe wall, flattening or buckling of the pipe, and damage to the coating. Bends should be checked to see that they are within tolerances for ovality. This may be especially important during the initial days of spread operation in the event that the pipe-bending foreman is inexperienced or careless. Pipe bends that exceed tolerance for reduction in diameter may obstruct the passage of scrapers during testing. Also, a flat spot in the pipe is a point of weakness. Small-diameter pipe, generally NPS 12 or less, can be bent satisfactorily using a bending shoe attached at the bottom of the boom on a sideboom tractor. The angle of bend is visually judged by the bending crew. Bending of larger-diameter pipe is accomplished by horizontal or vertical bending machines powered hydraulically or by cable systems. The angle of bend can be closely controlled with the machine. Ditch angles are usually measured by the bending crew with hand survey instruments in advance of the actual bending operation. Each joint of pipe should be evenly strung end-to-end ahead of the lineup crew so that the position of the bend in a particular joint of pipe will fit the ditch when that joint is subsequently welded into the line.
Lineup and Initial Welding The "pipe gang" performs the lineup of each pipe joint to the already-welded line, the initial root-pass ("stringer bead") weld, and the next ("hot pass") weld. (A
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second "hot pass" weld is sometimes required by the welding procedure or to alleviate a cracking tendency.) This crew generally sets the pace for the spread and thus is the "money-maker" for the contractor. Problems of quality workmanship and productivity of this crew are critical and must be resolved quickly; speed is desirable, but it must not be achieved at the expense of good workmanship. Equipment with the pipe gang includes two or three sideboom tractors, welding machines (often the "stringer bead" machine is mounted on one of the sideboom tractors), and usually a water-sprinkler truck to control dust as equipment and vehicles move along the construction working strip. Before lineup, the beveled ends of each joint are thoroughly cleaned with power tools. The full length of the inside of the pipe is visually inspected for dirt and debris. A swab should be pulled through each joint to remove any dirt and debris. A sideboom tractor moves the pipe joint into position for alignment and supports the pipe until the "stringer bead" is complete. The pipe is aligned with the aid of lineup clamps. Internal clamps are normally used on lines NPS 10 and larger. External clamps are usually used on smaller sizes. The now self-supporting pipe is then lowered to timber skids along the side of the trench, and the "hot pass" is made before the weld area cools. Clamps are then removed and the process is repeated for a new pipe joint. The longitudinal weld seams on adjoining joints of ERW or SAW pipe should be offset from each other by at least 3 inches or 30 degrees, whichever is greater. Seams are normally alternated at the ten o’clock and two o’clock positions. At appropriate intervals along the continuously welded line, a weld is not made, and an overlap of a few feet is left at the unwelded ends of the pipe. Later when the line is lowered into the ditch, "tie-in" welds will be made to complete the line. This allowance for tie-ins permits some expansion and contraction of the welded pipe without upsetting the skids and some adjustment of the pipe to the ditch during lowering-in that would not be possible if the pipe were welded in a continuous string. Since tie-in welds are more expensive and require more time than a production weld, there may be a tendency on the part of the contractor to neglect tie-ins and to weld up long straight sections of pipe continuously. This practice should be watched for by Company field personnel and corrected. The proper distance between tie-ins depends on local conditions and should be determined on the job. The ends of the pipe at tie-in gaps should be capped temporarily with tight-fitting "night caps." This prevents foreign objects and animals from entering the pipe between the time it is welded and the time when the tie-ins are made. Experience has shown that open ends will cause trouble later in construction—small animals may crawl in the pipe; pieces of wood, including skids, may be left in an open end and welded in; and dirt, weld rod, odd pieces of clothing, and other foreign objects are sometimes found. Contractors may wish to substitute burlap sacks tied over the ends of the pipe or may insert a skid half way, leaving half the skid projecting. Neither of these alternatives is satisfactory.
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Filler and Cap Welding The "firing line" welders follow the pipe gang and complete the welding with filler beads and a cap bead. One or more filler beads may be required, depending upon the wall thickness and the particular welding method used. "Firing line" welders usually work singly to complete one or more passes at a weld, and then leap-frog ahead to the next series of welds needing filler and cap passes. "Firing line" welders normally own and operate heavy-duty pickup trucks mounted with an engine-driven welding generator and welding equipment.
Radiographic Inspection After individual welds are completed and cooled, field radiographic inspection is done, following the inspection specifications. One, or more often two radiographers perform this work, using a radioactive source or a portable X-ray unit and a darkroom mounted on a heavy-duty pickup truck. Review and interpretation of radiographs of the day’s welding progress should be completed by the end of that same day and be available to the Company welding inspector periodically during the day. See Section 750 for guidelines on radiography. When 100% radiography is required, one radiographic team and equipment set is needed for production welding and a second for tie-ins and backup.
Weld Repairs Welds requiring repairs, as determined by visual or radiographic inspection, must be clearly marked and visibly flagged so that they are not coated over. Repair work is usually done either by welders from the welding crew outside of regular working hours or more often by the tie-in crew welders. Repaired welds should be radiographed again.
625 Coating Field Joints and Coating Repairs on Plant-Coated Pipe Following radiographic acceptance of welds, a small crew puts on the specified coating at field joints, makes repairs to obviously damaged plant-applied coating, and inspects the coating with a holiday detector ("jeep"). The holiday detector must be operated and maintained in accordance with the manufacturer’s directions for the particular detector and coating. This work is done while the line is supported on skids. Heat shrinkable sleeves ("shrink sleeves") are most frequently used at field joints on extruded polyethylene, fusion-bonded epoxy, and coal-tar-enamel coated lines, and are manually applied with hand-held torches for heating. On fusionbonded epoxy coated lines, an epoxy coating is sometimes specified—either painted on or fusion-bonded with field induction-heating equipment. Hot-mix Somastic field joints are used on Somastic-coated pipe. Whatever the field joint method, thorough cleaning of bare steel and overlapped plant coating is required.
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Over-the-Ditch Coating On Bare Pipe A large crew and specialized cleaning-priming-coating equipment is needed for this operation. Lowering the pipe into the ditch proceeds immediately after wrapping. In this operation one or more sideboom tractors with roller cradles lift the line up off the skid supports, moving ahead along the line. An engine-driven cleaning and priming machine, supported by a sideboom tractor, closely followed by an enginedriven tape-wrapping or hot-asphalt or coal-tar coating machine—also sideboom tractor supported—and finally one or more sideboom tractors supporting the line with roller cradles to guide the pipe into position in the ditch, proceed steadily ahead. The coated pipe is "jeeped" for holidays (defects) in the coating immediately after coating, and repairs are made. For tape wrapping, the operation is stopped when new rolls of tape are placed on the wrapping machine and then quickly resumed. The Company no longer uses over-the-ditch asphalt or coal-tar coatings, but has used them on lines in the past.
626 Lowering-In, Backfilling, Grade Restoration, and Cleanup Lowering-in The pipeline should be lowered into the trench closely after the field joints are complete, using two or more sideboom tractors, by lifting and guiding the pipe into the ditch with roller cradles. Final "jeeping" of the line is done as it is lowered in, and any repairs to coating defects should be made immediately. As mentioned in the preceding paragraph, for lines coated over the ditch lowering-in is done in conjunction with the coating operation. In rocky areas, care must be taken in lowering-in that the pipe coating is not damaged by scraping against the sides of the trench.
Backfilling Backfilling the line should follow closely behind lowering-in and be complete within a few hundred feet of the lowering-in operation at the end of each day, because thermal expansion and contraction of the exposed pipe may cause coating damage where the pipe lies on hard, uneven trench bottom. Tie-in and weld repair locations, cathodic protection test station locations, and block valve and scraper trap sites are backfilled as those items of work are completed. With rock-free soil, backfilling is effectively accomplished by angle bulldozers or by special tractor-mounted backfiller attachments. Backfill soil should be placed so it rolls down the sloping face of the backfill, and is not dropped directly onto the pipe. Backfill material should be mounded up over the ditch to allow for settlement. The amount of berm (crown or roach) required depends on size of the ditch and soil conditions, and should be determined locally. If the right-of-way or permit agreement requires that excavated top soil be placed as the top portion of backfill, backfilling must be done accordingly. Where rocky soil is not suitable for backfilling, suitable "shading" material should be placed a minimum of 6 inches around and over the pipe. As with padding, shading dirt or sand will need to be brought in from another source. Shading needs
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to be done with care so that rocks from the sides or edges of the trench do not become loosened and fall onto the pipe. As with backfilling, sufficient shading should be done on the same day as lowering-in to prevent damage to the coating by thermal movements or by rocks falling from the sides of the ditch. Once the line is satisfactorily shaded, backfilling with excavated rocky spoil can proceed, but the next 12 inches of backfill should be graded so there is no rock over three inches in diameter. In rocky terrain, if no source of suitable padding and shading material is available within reasonable distance, "rockshield" wrapping around the pipe to protect the coating is suggested. Various types are available; the "rockshield" should be perforated or a mesh, so as not to shield cathodic protection currents from the pipe. On steep slopes where backfill is likely to wash out in heavy rains, trench plugs— sandbag "breakers" or urethane-foam plugs—should be placed at intervals around and over the pipe to fill the trench to control surface runoff and limit the length of backfill that would be washed out by erosion.
Grade Restoration Where side-hill cuts are made in grading the construction working strip, present practice and permit conditions generally require that the original grade be restored. Segregated topsoil should be spread over the final graded surface. Bulldozers are used for this work, possibly with some backhoe assistance in steeper terrain. In gently sloping country, motor graders may be adequate. Grade restoration generally follows tie-ins and installation of cathodic protection test leads. Grade restoration should also include measures for erosion control. Cross-drain ditches should be located at intervals on slopes to direct water across the construction working strip and avoid channelling along the backfill berm. Other measures include riprap at water-course banks and scattered straw or soil treatment to control dust in wind-blown areas.
Cleanup Cleanup of the construction working strip is very important for the Company’s public relations and should have close monitoring by Company field personnel. •
Fences must be replaced and left in as good or better condition than before construction
•
All debris including rock in cultivated and grazing areas, scattered during the construction operation, must be removed
•
Irrigation ditches and drainage canals not temporarily flumed must be restored as soon as possible to allow irrigation water and drainage to agricultural lands. In restoring irrigation ditches, permanent repairs must ensure that ditch may be placed in service without washing out
Extent and timing of cleanup work needed is determined by land use and type of terrain. Cleanup operations are done concurrently with grade restoration.
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Trash and debris generated by construction activities should be picked up and properly disposed of daily by the crews responsible, e.g., weld rod stubs, coating containers, used oil filters, and discarded parts after equipment maintenance. Any construction activity done after the cleanup crew has left an area, such as late installation of appurtenances or line repairs during testing, must include cleanup at that area of work.
627 Tie-Ins and Weld Repairs, Cathodic Protection Test Stations, Line Markers Separate crews follow the main pipe laying activities. A tie-in crew handles pipe fitup, welding, and coating at line tie-ins and usually makes weld repairs and installs coating field joints at the repaired welds. The crew equipment usually includes two sideboom tractors and a bulldozer. Short pieces of pipe cut off at the tie-ins should be clearly marked to identify pipe grade and wall thickness. Pieces over six feet long should be moved ahead and welded into the line to minimize wastage. A two-man crew usually installs cathodic protection test stations, making CADwelded cable connections to the pipe and to crossed lines and running the cable leads to a postmounted test box. Company field personnel should closely monitor this work to ensure test stations are at reasonably accessible locations and proper cable color coding is followed. Backfilling of the line at test stations is usually done by the bulldozer working with the backfilling, tie-in, or grade restoration crews. After backfilling and grade restoration, a small crew installs line location warning markers and aerial markers. Aerial mile post markers are located at approximate mile-post stations where they will not interfere with surface use of the land; line stationing at these markers is normally determined with the completion alignment survey.
628 Revegetation Reseeding and fertilizing uncultivated land is becoming a common practice. It is often a requirement of right-of-way and permit conditions, usually specifying a particular seed mixture, or may be a prudent measure to control surface erosion of the disturbed soil on the construction working strip. Timing of reseeding may be influenced by seasonal conditions. This work is normally done by a specialist subcontractor to the construction contractor, but may be contracted directly by the Company. Responsibility for reseeding of areas where germination is unsuccessful should be clearly defined in contract specifications. In some cases, right-of-way and permit conditions may require more extensive revegetation, such as replacing trees and ornamental plants. These cases need to be handled as the particular situation demands. Replanting of cultivated crops is left to the landowner or tenant. Damage payments cover loss of crops and costs to replant and restore the land.
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629 Timing of Spread Operations As a basic rule both Company and contractor benefit by keeping spread operations closed up. This minimizes construction interference with landowners and the public, because there is not an extended time between the initial clearing and grading on a property and final cleanup; and it allows better supervision of spread crews by both contractor and Company. It is particularly critical to keep the time the ditch is open—between ditching and backfilling—short. The contractor, however, tends to keep clearing, grading, and ditching well ahead of the pipe gang so that these operations will never slow down the high-cost crews that do lineup, welding, and coating (if over-the-ditch). Also, because of cost, the contractor is usually reluctant to bring earthmoving equipment and equipment operators onto the job to handle short-term difficult situations. Thus, clearing, grading, and excavation are likely to get far ahead of pipe laying, and grade restoration and cleanup to lag behind. The Company field representative must be alert to this trend and enforce specification requirements keeping the spread within limits of time and distance. There will usually be sections of the route where grading and excavation are particularly difficult, and highway, railroad or river crossings where work should or can be done well in advance of pipelaying. These should be identified prior to construction and a mutually agreed-upon schedule developed by Company and contractor for work at such locations. Construction scheduling and sequence of work along the line may be determined by environmental conditions, such as fish and wildlife activities. These conditions should be identified, preferably during project planning and before bidding on construction, and certainly before the start of construction.
630 Welding The most common method for welding pipelines in the field is the shielded metal arc welding (SMAW) process, using cellulosic (EXX10) electrodes. The direction of welding is normally downhill. Electrodes are selected to meet the mechanical properties (tensile strength and toughness) of the pipe and for welding characteristics needed to obtain sound welds. Both welding procedures and welders are required to be qualified by the code covering the pipeline system. The codes require direct Company involvement in the qualifications of both procedures and welders. For welding procedures, this can be accomplished by either actually witnessing all qualifications or providing Companyqualified welding procedures. All welder qualifications should preferably be witnessed by the Company. Records must be kept of each qualified welding procedure being used and all welder qualification tests.
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631 Regulations and Codes The national regulations and codes that have requirements concerning pipeline welding are: 49 CFR 192
Transportation of Natural and Other Gas by Pipeline
49 CFR 195
Transportation of Hazardous Liquids by Pipeline
ANSI/ASME B31.4
Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum Gas, Anhydrous Ammonia, and Alcohols
ANSI/ASME B31.8
Gas Transmission and Distribution Piping Systems
API Standard 1104
Standard for Welding Pipelines and Related Facilities
API RP 1107
Recommended Pipe Line Maintenance Welding Practices
ASME Section IX
Welding and Brazing Qualifications
Both ANSI/ASME B31.4 and B31.8 permit qualification of procedures and welders to either API 1104 or ASME Section IX. Generally, API 1104 is the more appropriate code for pipeline welding and is the reference for discussion of welding procedure and welder performance qualifications in the sections that follow. API STD 1104 is included in this manual. See Section 860 of this manual regarding maintenance welding.
632 Welding Procedure Qualifications Welding procedures are composed of two parts: the procedure specification and the procedure qualification. The procedure specification form is shown in Exhibit A of API STD 1104 and the information to be filled in ranges from process to speed of travel. These will be discussed individually later on. The procedure qualification form shown in Exhibit B of API STD 1104 documents the mechanical properties (such as strength, ductility, and hardness) of the welding procedure established in the welding procedure specification. Mechanical properties are determined by destructive testing of a test weld. After the welding procedure is qualified, changes to the procedure specification may be made providing they are not changes to the essential variables. Any changes to the essential variables require requalification of the welding procedures and revision of the welding procedure specification. The essential variables that have to be considered for the SMAW process are: • • • • • • • •
Yield strength range of the pipe group Major change in joint design Welding position Wall thickness group Filler metal group Time lapse between root and hot pass Direction of welding Travel speed
There are additional essential variables for automatic welding, and API STD 1104 Section 9.0 should be consulted for these.
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Welding Procedure Specification The following is a discussion of the individual entries on the API STD 1104 procedure specification form. Process (Essential Variable). Each process is identified by name and as manual, semiautomatic, or automatic. The most common process is shielded metal arc welding (SMAW), which is a manual process. Other processes are also recognized by API STD 1104. These are: • • • •
Gas metal arc welding (GMAW) Gas tungsten arc welding (GTAW) Flux cored arc welding (FCAW) Submerged arc welding (SAW)
SAW is often used for double jointing of pipe where productivity gains can be achieved through automation. The other welding processes (GMAW, GTAW, and FCAW) can be used either semiautomatically or automatically depending upon the application. Material (Essential Variable). Pipe and fitting materials are identified as to specification (e.g., API SPEC 5L and grade, or ASTM number). The materials are grouped into three strength ranges based on specified minimum yield strength (SMYS). These are: • • •
SMYS of 421 ksi or less SMYS of more than 42 ksi but less than 651 ksi SMYS over 65 ksi (each grade requires separate qualification)
Generally, the Company does not have experience with line pipe grades above API SPEC 5L X65, although X70 has been used by others. Diameter and Wall Thickness (Essential Variables). The separate groups are: Diameter Groups
Thickness Groups
Under 2-3/8 in.
Less than 3/16 in.
2-3/8 to 12-3/4 in.
3/16 to 3/4 in.
Over 12-3/4 in.
Over 3/4 in.
Joint Design (Essential Variable). The most frequently used joint design is a Vgroove having the configuration shown in Figure 600-3. Offset (high-low) during fitup should be restricted to 1/16 inch maximum. Offset greater than 1/16 inch should be reduced by equally distributing it around the circumference of the pipe. Filler Metal (Essential Variable) and Number of Beads. The American Welding Society specification and electrode classification is listed. For SMAW, AWS Specification A5.1 or A5.5 is used, depending upon the minimum tensile strength of the electrodes. Note that minimum tensile strength (ksi) is indicated by the first
1.
Qualification at the maximum strength qualifies all of the lower strength materials within the group.
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Fig. 600-3
V-groove weld joint
two digits of the electrode classification and is different from the pipe groupings that are based on SMYS. Electrode sizes and minimum number of beads commonly used are shown in the table and with the sketch on Page 2 of the procedure specification. Company practice requires a minimum of three weld passes and limits maximum electrode sizes as follows: Stringer Bead
Hot Pass, Filler and Cap Passes
5/32 in. max.
3/16 in. max.
Electrodes furnished by Lincoln Electric Company are most commonly used. These are listed in Figure 600-4 by trade name, AWS class and specification, group, and typical API material grade application. Fig. 600-4
Lincoln Electric Company Electrode Specifications
Trade Name
AWS Class
AWS Specification
API Group
API Material Grades
Fleetweld 5P
E6010
A5.1
1
B, X42, X46
Fleetweld 5P +
E6010
A5.1
1
(1)
Shield-Arc Hyp
E7010-G
A5.5
1
X42–X66
Shield-Arc 85
E7010-A1
A5.5
1
X42–X56
Shield-Arc 70 +
E8010-G
A5.5
2
X60, X65
(1) For use on root and hot pass only on all grades.
Electrical Characteristics. The normal electrical characteristics for cellulosic electrodes are direct current-reverse polarity (i.e. the electrode is positive). An exception to this is that straight polarity has been sometimes used for the root pass for better penetration control. This practice is acceptable provided that it is included in the procedure qualification. Voltage and amperage ranges for each electrode size should be shown in the table of the procedure specification. Position (Essential Variable). Roll welding and position welding are terms used to describe whether the pipe is being rotated or is fixed during welding. Roll welding
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is done with the pipe rotated about a horizontal axis and the welding performed near or at the top center for a flat position weld. Position welding can be done with the pipe axis horizontal, vertical, or sloping. When the pipe axis is horizontal, the position of the weld is vertical. If the pipe axis is to be other than horizontal, it should be clearly described. Direction of Welding (Essential Variable). The direction of welding for position welding using cellulosic electrodes is normally downhill for pipeline welders. Downhill welding is much quicker than uphill welding. The direction of welding does not apply if the position of the weld is flat (roll welding) or horizontal (where the pipe axis is vertical). Number of Welders. For position welding, the number of welders varies with pipe size. Generally, two welders can be used for pipe sizes over NPS 8 and three for pipe sizes over about NPS 24. The use of more than one welder helps to balance shrinkage stresses and increase productivity. Time Lapse Between Passes (Essential Variable). For welding with cellulosic electrodes, the time lapse between completing the stringer bead and starting the hot pass is important to avoid cracking. Good practice is to start the hot pass within five minutes of completing the stringer bead. Where the hot pass cannot be started within five minutes, the stringer bead should be reheated to 100°F minimum and checked for cracking prior to welding. Weld joints that have not had the stringer bead completed at the end of the day should be rejected. Type of Lineup Clamp. This refers to the method of aligning the pipe and whether internal or external lineup clamps are used. In rare cases, lineup clamps will not be used and "none required" should be stated. Removal of Lineup Clamp. The percent completion of the stringer bead required before removal of the lineup clamp should be specified. For internal lineup clamps, generally 100% of the stringer bead is completed before removal is permitted. For external lineup clamps, API STD 1104 requires not less than 50% of the stringer bead to be completed in equal segments around the circumference before removal is permitted. Cleaning. Standard pipeline procedure is to grind the root pass and power wire brush all remaining passes. Preheat and Stress Relief (Postweld Heat Treatment). Preheat requirements will vary with pipe grade, carbon equivalent, and wall thickness. Preheat is generally not required except for low initial pipe temperature, repair welds, and heavier wall thicknesses. Both Codes B31.4 and B31.8 require preheat for carbon steel when the carbon content exceeds 0.32% or the carbon equivalent (C +Mn/4) exceeds 0.65% (this is a simplified carbon equivalent used only for determining the need to preheat). These are extreme cases for most pipe materials and rarely will be cause for preheat. For pipe temperatures below 40°F, preheat of 100°F minimum should be used. A preheat of 200°F minimum should be used for wall thicknesses of one inch or greater and all weld repairs.
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Stress relief is normally not required for wall thicknesses of 1-1/4 inches and less. (Code B31.4 permits up to 1-1/2 inches with 200°F preheat over 1-1/4 inches.) When stress relief is required, the temperature range and holding time should be specified. Shielding Gas and Flow Rate (Essential Variable). Applies only to the gas shielded processes (i.e., GTAW, GMAW, and FCAW). Shielding Flux (Essential Variable). Applies only to the granular flux used for submerged arc welding. Speed of Travel (Essential Variable). Travel speed should be specified as a range. The following are typical ranges for vertical down welding with cellulosic electrodes on larger pipe (e.g., over NPS 6 ). Weld Pass
Electrode Diameter, in.
Travel Speed, in./min
Stringer
5/32
9-15
Hot Pass
5/32
10-14
Filler
3/16
8-12
Cap
3/16
7-9
Procedure Qualification Test Results Procedure qualification test requirements are described in Section 2.6 of API STD 1104 for butt welds and Section 2.8 for fillet welds. Results are recorded on the coupon test report form in Exhibit B of API STD 1104. This is a record of the actual results for the tensile, bend, and nick break tests. Additional tests, such as Charpy V-notch and hardness, are recorded on a separate sheet. The testing laboratory performing the tests normally prepares this form or one similar to it. For work performed by contractors, the Company can either require them to qualify their welding procedures or permit them to use a Company-qualified welding procedure.
633 Welder Qualification Section 3 of API STD 1104 covers the requirements for the qualification of welders. The stated purpose of the welder qualification test is to determine the ability of a welder to make sound welds using previously qualified welding procedures for butt welds or fillet welds. The Company requires welders to be qualified in the presence of a Company representative. Essential variables differ between procedure qualifications and welder qualifications. API STD 1104 has two different types of welder qualification tests and the essential variables differ between them.
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Single Qualification Test In the single qualification test the welder follows a specific procedure qualification and is limited to the range of thickness and diameter specified in the welding procedure. Other essential variables requiring welder requalification are changes in process, direction of welding, electrode grouping (cellulosic to low hydrogen or vice versa), position, and joint design (major). Welder qualification tests are generally performed for each specific pipeline project.
Multiple Qualification Test The multiple qualification test is generally used for line maintenance welding. The test is used for both Company and contract welders because of the breadth of qualification. A welder passing this test on NPS 12 pipe (1/4-inch minimum wall) is qualified to weld in all positions, on all wall thicknesses, joint designs, fittings, and on all pipe diameters. The test involves welding two separate pipe assemblies. The first assembly is a butt weld in fixed position (horizontal or 45-degree inclined). The second is a full-size branch pipe connection with the pipe horizontal and the branch vertical. The test requires that the welder must lay out, cut, fit, and weld the branch connection. The only essential variables requiring requalification are changes in process, direction of welding, or electrode grouping (cellulosic to low hydrogen or vice versa). Destructive testing results from welder qualification tests are recorded on the coupon test report in Exhibit B of API STD 1104. In order for a welder to maintain his qualification, he must have been engaged in a given process of welding during any six-month period. In addition, Code B31.8 requires requalification at least once each year. Welders are required to identify their work and should be given a unique identification number for that purpose.
634 Weld Repairs Section 7 of API STD 1104 requires that special treatment be given to weld repairs. Repairs to cracks in welds and previous weld repairs require qualification of a special repair procedure and the Company generally prohibits these repairs. Single repairs to any given area of a weld are usually permitted provided the defect is not a crack and a preheat of 200°F minimum is used.
635 Arc Burns Arc burns can happen during welding when poor contact between the ground lead of the welding machine and the pipe causes arcing. Arc burns are considered stress concentrations and are to be prevented or eliminated. Arc burns are treated seriously because of the area of high hardness caused by the arcing and the risk of leaving an imbeded crack or sharp discontinuity surrounded by a zone of high hardness. Arc burns can be prevented by proper attention to grounds (design, maintenance, and application). Arc burns should be removed by cutting out and replacing
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a cylinder of pipe at least 12 inches in length or 1.5-times pipe diameter for sizes up through NPS 24, and equal to pipe diameter for larger sizes. Code B31.4 Section 434.8.7 provides an alternate method for removal of arc burns by grinding providing the minimum wall thickness is not violated. Complete removal of arc burns is determined by progressively grinding and etching with a 20% solution of ammonium persulfate to check for the elimination of the hard heataffected zone. Any remaining hard zone will etch as a dark spot, and grinding is progressively performed until the dark spot no longer appears after etching.
636 Field Welding and Construction Conditions Weld Bevels Weld bevels should be checked for compliance with the joint detail shown in the welding procedure. Quality pipeline welding starts with properly prepared bevels. The bevels should be buffed or wire brushed prior to welding. The bevels should be checked for laminations, splits, or other defects such as handling damage and burning serrations. Defects should be repaired or removed. Removal will generally require rebeveling of the pipe.
Weld Joint Fit-Up In addition to properly prepared bevels, quality pipeline welding also requires good fit-up. Offset (high-low) should be restricted to 1/16 inch maximum. Where greater offset is found, it should be reduced by equally distributing it around the circumference of the pipe. When the pipe being joined is of different internal diameters (different wall thicknesses), the inside wall of the thicker pipe should be smoothly tapered (3:1 minimum) to the inside diameter of the thinner wall pipe. If different grades of pipe are being joined with different inside diameters, then: 1.
The thicker wall pipe can be tapered if it is the same or higher grade
2.
The thicker walled pipe should not be tapered if it is the lower grade. A transition spool should be used which is at least 1-1/2 pipe diameters in length (12 inches minimum), equal in wall thickness to the thicker wall pipe and equal in grade to the higher grade pipe. The spool should be internally tapered at one end to match the wall thickness of the thinner wall pipe. See Section 360 for a more complete discussion of wall thickness transition spools.
Weather Conditions Weather conditions can adversely affect weld quality during construction and provision must be made for protection against wind, dust, cold, and rain. In warm, sunny weather with wind speeds below 10 mph, no protection is generally needed during welding. As wind speed increases and weather conditions change, protection requirements can vary from simple wind breaks around the weld joint to full enclosures for rainy or extremely cold conditions. For temperatures below 40°F, the Company requires preheating of the weld joint to 100°F minimum. Completion of the hot pass within 5 minutes of the stringer pass is required in all cases.
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The best index of the adequacy of weather protection being provided is the frequency of weld repairs due to excess porosity and any occurrence of cracking. Either of these should initiate a Company response to check on the weather protection being provided. Wind and dust above 10 mph should be shielded from the weld area during welding. Rain should not be permitted to fall on the weld joint until it has naturally cooled to ambient temperature. Maintaining heat during welding is one of the most important cracking avoidance measures, particularly at low ambient temperatures. The method of preheat and weather protection should work together to keep the weld clean, dry, and out of the wind during welding.
Welding Access for welding is important for proper electrode angles and visibility of the weld puddle. API STD 1104 requires 16 inches minimum working clearance around pipe when it is welded above ground. Working clearance for welding in the bell hole is not specified by API STD 1104, but 16 inches is still a good rule-ofthumb to be used. The starting and stopping locations in the weld are a source of defects in all passes from the root through the cap pass, and API STD 1104 requires that no two beads be started at the same location. This is generally not a problem on 100% X-ray work as welders are sensitive to increasing their risk of repair from stacking up start-stop locations on successive beads. API STD 1104 requires pipe welds to be substantially uniform in cross-section around the entire circumference. No point of the crown (cover pass) is permitted to be below the outside surface of the pipe nor raised above the parent metal by more than 1/16 inch. The face of the completed weld should be approximately 1/8 inch wider than the width of the original groove. Electrodes. The storage and handling of cellulosic electrodes is not difficult if reasonable precautions are taken. The greatest damage that can occur results from handling, and electrodes showing cracking or spauling of the coating should be scrapped. The moisture level for cellulosic electrodes is normally quite high (3-5%) and atmospheric exposure is generally not a problem unless they are mistreated, i.e., allowed to become wet, contaminated (with dirt, grease, etc.), or dried out. In these cases, electrodes should be scrapped. Identification. The identification of the welders for each weld is important quality control information and should be shown on or adjacent to each weld. Identification should be semipermanent (paint stick or equal) and should identify all welders. Stamping should not be permitted. Stringer bead welder identification should be discernable from the other welders. The identification of the welders for each weld should be picked up by the radiography crew and transferred to the record sheets for the radiographs. Quality control is discussed in Section 700, but early identification of substandard welders is important for corrective action. See also Model Specification PPL-MS-1564.
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640 Coatings and Linings Pipeline coatings and linings are covered elsewhere in this manual, as follows: •
Section 340, External Pipeline Coatings Provides a brief overview of the recommended types of corrosion prevention coatings for buried pipelines.
•
Section 350, Internal Coatings and Linings Briefly outlines the internal pipeline coatings section of the Coatings Manual. See Section 400 of the Coatings Manual.
•
Section 750, Pipeline Coating Inspection Provides a detailed account of inspection requirements for internal and external coatings, including transportation, storage, and handling of the coated pipe, plant and field inspection, specifications surface preparation, application, post-coating inspection for fieldapplied coatings, etc.
650 Crossings Section 440 of this manual describes design considerations for river and stream crossing, highway and railroad crossings, and crossing of other pipelines, and includes construction method alternatives for these crossings. Construction specifications should define crossing details meeting design requirements and permit conditions required by the owner or authority responsible for the facility crossed. Company field personnel must contact field representatives of these owners or authorities to inform them and clarify details of permit conditions.
River and Stream Crossings The horizontal, directionally-controlled drilling method is the preferred installation technique for major river and canal crossings. The line pipe is pulled through a drilled hole below the river bottom, avoiding a usually difficult and lengthy excavation in the river and resulting downstream siltation, as well as the risk of damage to the coating during and after installation. This work is done by a specialist contractor such as Inarc Drilling, Inc., Tulsa OK; Land and Marine, Houston TX; Cherrington, Sacramento CA; Horizontal Drilling International, Rungis, France. At smaller stream and water course crossings, a trench is excavated by backhoe or dragline, and the line carried by sideboom tractors or pulled into place. Precautions to be taken to assure a satisfactory installation are:
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Check excavation depths just before line installation
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Protect coating from damage by concrete coating, "rock-shield," or 2 x 4 timbers strapped around the pipe
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When pulling, avoid or minimize interruptions to reduce risk of the line getting stuck
•
Measure top-of-pipe depth after installation to determine that it is at design depth below stream bottom and bank scour zone
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Banks of streams and dry washes should be excavated so that the pipe can be "roped-in" without field bends at the banks. Heavy runoff from spring thaws or rainstorms can cause severe flooding and stream courses may change drastically. Corrective work to lower the line in such a situation is at best difficult, but is more easily done if the line was originally installed without sags or overbends at the banks. Where there is evidence of recent meandering of a stream in flat bottom land, it may be advisable to excavate sufficient depth across the entire bottom land to maintain the pipeline below the natural channel bed elevation. Crossings of seasonally dry river and stream beds should be scheduled to take advantage of dry working conditions, even if it means using a separate crew or contractor out of sequence with other work. Similarly, for wet crossings, it may be economic to schedule crossing work during low water flow. Winter crossings may be made using snow bridges for streams (with care taken not to place debris into the water course) or with ice bridges on larger rivers and lakes. Crossing designs should specify required line weighting to assure stability when submerged, as well as pipe wall thickness and coating. See the discussion on crossings in Section 440. Whether or not weighting is needed, it is advisable to fill the line with water after installation to its proper depth. Weighting may be required across flood plains adjacent to a river, as well as at the actual crossing. Company field personnel should examine and evaluate actual conditions at crossings well in advance of construction. Construction problems can be anticipated and any significant discrepancies or oversights in designs can be identified. Occasionally, where horizontal drilling or trenching is not feasible because of rock, cliffs, or environmental restrictions, the pipeline can be installed on a bridge. The bridge may be constructed solely for the pipeline or an existing structure may be used if permission can be obtained. Pipeline bridges are generally suspension types with horizontal cables to limit pipe sway. At long crossings with relatively small diameter pipe, wind induced vibration may become a problem and additional measures may be needed. At short crossings an arched configuration of the pipe itself may be possible and economic.
Highway, Road, and Railroad Crossings Though often not feasible, open trench excavation is the lowest-cost method of making these crossing and should be considered wherever traffic control or routing make it possible. As discussed in Section 440 of this manual, it is highly preferable to install the line pipe at these crossings without casing. Where open trenching is not possible, the line pipe (or casing) is installed by the bore-and-jack method. This uses a rotating auger to excavate a hole, while simultaneously jacking a section of pipe (or casing) behind the auger tip. The boring equipment, for powering the auger and hydraulically jacking the pipe (or casing), is set in an excavated pit on one side of the crossing. This equipment will limit the length of the separate sections of pipe (or casing) that are jacked into the crossing before another section is welded to the crossing string.
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Problems that may be encountered in this method are: •
Misalignment, vertically or horizontally, of the boring
•
Rock or other hard material stopping or deflecting the boring auger
•
Sand or similar cohensionless soil collapsing ahead of the boring auger, resulting in a cavity over the jacked line (or casing)
For cased crossings, installation of casing insulators and end seals should be done in accordance with the supplier’s instructions and carefully inspected. Vents on the casing may or may not be required by the operating company or the highway or railroad authority; vent connections should be welded before the line pipe is installed so there is no chance of damaging the pipe coating by the welding.
Pipeline and Cable Crossings All phases of construction activity—in particular, trenching, pipe installation, and backfilling—should be conducted so as to minimize risk of damage to the crossed facilities. Damage may also be caused by heavy construction equipment crossing over a shallow buried facility; additional temporary dirt covering or matting may be needed. Critical lines carrying hazardous contents or for which interruption of service may have significant consequences should have contingency plans for notifications and action in the event damage should occur or be suspected.
Overhead Power and Telephone Line Crossings Where overhead clearance is restricted, warning signs and other precautions should be taken to avoid damage to the facility or contact with high-voltage electrical power lines. The National Electric Code and government regulations dictate minimum clearances to power lines. Most cranes and boom-type equipment should have electric arc prevention clearance charts posted in the operator’s cab. Blasting done near overhead lines should be matted so that flying rock fragments do not nick or break overhead cables.
660 Appurtenances Section 450 of this manual describes line valve manifolds, scraper trap manifolds, line pressure control and relief, "slug catchers," vents, drains, and line markers. Section 360 describes piping components that go into piping for appurtenances. Construction specifications should define details for those appurtenances. Shop fabrication of piping assemblies with appropriate shop inspection, is recommended for economy and better quality control; subassemblies may be necessary because of size restriction. If field welding is required other than buttwelding for which pipe line welders have been qualified, a suitable field welding procedure must be developed and welders qualified for piping fabrication welding.
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Installation of appurtenances often proceeds concurrently with pipe laying, but at locations distant from laying. Company field inspection coverage will need to include both areas.
670 Field Supervision Organization Company field supervision of pipeline construction is vital for a successful project: •
To assure compliance with conditions of rights-of-way and permits
•
To establish and maintain relationships with landowners, tenants, and governmental agencies that promote good public relations for the Company
•
To administer construction contracts
•
To enforce the technical provisions of the construction specifications, both specific and implied as good practice
•
To coordinate with the project design team
•
To obtain and produce records required by regulations and codes and needed for operation and maintenance of the pipeline system
•
To coordinate with operating organization personnel involved in the project
In addition to field engineering and inspection, the Company construction organization is usually responsible for material control, field cost accounting, and progress reporting, and coordinates with Company land representatives responsible for acquisition of land, rights-of-way and permits, and settlements of construction damage claims. Where the pipeline is a portion of a major project, some of these support functions may be handled by the overall project staff. The scope of the pipeline project naturally determines the size and make-up of the field supervision office. For larger projects a construction manager will be responsible for a construction office staff covering all field support functions and field engineers and inspectors. A typical organization chart is indicated on Figure 600-5 (see following page). Construction supervision for smaller projects will be headed by a spread engineer reporting to a project manager in the home office. Operating Companies usually handle production field gathering and flow lines, or short transmission pipelines within the existing framework of the organization. The field inspection organization is discussed in Section 790 of this manual. A Company land department usually has the responsibility for acquisition of rightsof-way, permits, and settlement of construction damage claims, and will handle any contracting for needed services.
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Fig. 600-5
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Typical Company Organization for a Major Pipeline Project
680 Construction and Construction Service Contracts 681 Contracting Plan The Project Contracting Plan summarizes intended contracts and timing. Dependent on project scope and circumstances, construction and construction service contracts will cover: •
Construction of the facilities, usually separately for the pipeline and for stations and terminals. For stations and terminals different phases may be contracted separately—site preparation, civil, mechanical, electrical, instrumentation, tanks, buildings, etc.
•
Construction support services—radiographic inspection and nondestructive testing (NDT), alignment and property surveys, third-party inspection when required by permit conditions for certifying the facilities, catering and camp maintenance services (in remote areas), security, medical, airplane, and helicopter, communications, etc.
•
Supplemental personnel working under Company direction when Company does not have needed staff available
•
Temporary facilities and utilities for field offices, storage sites, vehicles, camps, etc.
Contracting guidelines and policies are included in the Chevron Construction and Services Contract Manual. The Contracts staff of the Engineering Technology
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Department can be consulted regarding types of contracts, contract forms, compensation items, and contractor performance.
682 Pipeline Construction Contracts We recommend that all contracts be either lump-sum contracts with unit price adjustments or unit price contracts based on a described scope of work. The general scope of work can usually be well defined when bids are invited, but several item quantities may not be exactly known until time of construction, with resulting increase or decrease in compensation. For example: length of line, cased and uncased crossings for highways and railroads, block valve installations, average length of pipe joints (determining the number of welds and field joints), extra cover requirements required by right-of-way, and permit conditions, etc. Where rock or other difficult working conditions are anticipated but where the extent can not be readily determined ahead of construction, incremental unit prices for such work should be included in the schedule of payments, rather than trying to cover the unknown extent in the bidder’s contingency. Major river or other watercrossings may be included in the overall construction contract, separately priced in the schedule of payments, or separately bid and contracted directly with a contractor specializing in such work. It may be advantageous for the Company to work directly with the specialty contractor. The contract schedule of compensation should include schedules of labor craft rates and equipment rental rates for extra work requested by the Company not covered by unit price adjustments, or for standby in the event of delay for which the Company is contractually responsible. Contracts should also require the contractor to produce proof of sufficient property damage and vehicle accident insurance, and workers compensation insurance. In some cases, it is wise to have the Contractor post a performance bond, although the bidder selection process should have rejected underqualified bidders.
683 Contracts for Supplemental Personnel Services Contracting for inspection personnel is a common practice when qualified Company personnel are not available to cover inspection duties. Contracts are usually on a reimbursible basis. Successful contracts have provided compensation based on all-in hourly rates incorporating overtime premiums and daily travel-time allowance, a per diem living allowance, and a one-time mobilization charge. This allows objective evaluation of competitive bids and greatly simplifies contract administration and accounting. Chevron Pipe Line Company and the Engineering Technology Department can offer guidance on reputable inspection service firms that have performed satisfactorily on projects. Contracting for other field staff personnel can be handled similarly.
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690 References
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1.
Hosmanek, Max. Pipeline Construction. Austin, Texas; Petroleum Extension Service, Division of Continuing Education, the University of Texas. 1984.
2.
Schurr, B. Manual of Practical Pipeline Construction. Houston: Gulf Publishing Company, 1982.
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700 Inspection and Testing Abstract This section discusses the nondestructive inspection methods used for line pipe, from mill purchase to installation in the ground. It provides guidance on the purpose, the suitability, and the application of mill surveillance and field inspection (pipeyard). The makeup and duties of inspection and/or monitoring crews are detailed. Pipeline welding inspection and pipeline coatings inspection are covered. This section also covers the construction activities of hydrotesting, dewatering and drying, and the organization of large and small field inspection activities. For inservice inspection of pipe wall thickness conditions using electronic inspection pigs, see Sections 453 and 831.
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Contents
Page
710
Inspectors and Inspection Methods
700-3
711
Types of Inspectors
712
Inspection Methods
713
Acceptance Criteria
720
Mill Surveillance
721
Recommendations for Use of Mill Surveillance
722
Mill Surveillance Teams
723
Mill Inspector Duties
724
Qualifications of Mill Inspectors
730
Post-Mill Inspection
731
Types of Field Inspection Services for Line Pipe
732
Qualification of Inspectors and Inspection Companies for Line Pipe
733
Recommendations for Pipe Inspection
740
Pipeline Welding Inspection
741
Duties and Qualifications of Welding Inspectors
742
Qualification of Welding Procedures and Welders
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743
Documentation and Quality Control
744
Visual Examination
745
Radiography of Field Welds
750
Pipeline Coating Inspection
751
Inspection Methods for External Coating
752
Plant Inspection of Internal FBE Coatings
753
Plant Inspection of Internal Cement Linings
754
Field Inspection Methods for External Coatings
755
Field Inspection of FBE Coated Field Joints
756
Field Inspection of Heat Shrink Sleeves
757
Protection of Coating During Laying
760
Completion Testing
761
Completion Scraper Run
762
Completion Hydrotesting
763
Test Procedure and Program
764
Line Rupture and Leakage
770
Dewatering and Drying
771
Dewatering
772
Drying and Dehydrating
773
Gelled-Fluid Pigs
780
Typical Field Inspection Organization
781
Objectives
782
Selection of Field Inspection Personnel
783
Inspection Functions and Staffing
784
Inspection Reports
790
References
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710 Inspectors and Inspection Methods 711 Types of Inspectors Inspection of line pipe materials (Sections 720-723), pipeline welding (Sections 740-745) and installing (laying), and line pipe coating (Sections 750-757) involves many inspection methods, and several types of inspectors with different expertise. It is done at various stages of the project from production of pipe in the mill to laying of pipe in the ditch. Figure 700-1 shows a schematic of the various inspection sites. The various inspectors and inspection agencies fall into several groupings: •
Company Inspectors. Company inspectors, including CRTC’s Quality Assurance Team Engineers may be used to oversee supplier or contracted inspectors or actually inspect pipe, and may be involved throughout the project, from production of the pipe to welding and pipe laying.
•
Supplier Inspectors. Employed by the supplier or manufacturer, supplier inspectors are the line pipe mill, coating company, or welding contractor’s inspectors.
•
Service Company Inspectors. These individuals and/or service companies usually have special inspection equipment. They are contracted by CRTC’s Quality Assurance Team or the project staff to perform specific tasks such as inspection of butt welds, ultrasonic inspection on the line pipe weld seam, and thickness measurements on coatings.
•
Third-Party Inspectors (Monitors). Contracted by Chevron (not contractors or suppliers), third-party inspectors independently monitor the inspection work of others. Third-party inspectors perform mill surveillance by monitoring the mill inspectors and/or inspecting the final product. In the field they monitor the field inspection. In the coating plant they verify coating integrity.
712 Inspection Methods This section presents a general overview of inspection procedures and techniques that are used for inspection of line pipe and field welds. Specific procedures for inspection and the criteria for acceptance are discussed in Section 730, 750, and 770. Consult the latest editions of the following sources for more details:
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Company Welding Manual
•
API RP 5L8, Recommended Practice for Field Inspection of New Line Pipe
•
Metals Handbook, Vol. 17, Nondestructive Evaluation and Quality Control, ASM International
•
Nondestructive Testing Handbook, American Society for Nondestructive Testing (several volumes)
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Fig. 700-1
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Inspection Points and Methods
(720)(730) (710)(710) (710)(730)
(710)(730)
(710)(730)
(710)(730) (710)(730)
(750)(730)
(710)(730)
(710)
(710)(740)
(710)(750)(750)
(750)
Numbers in ( ) refer to sections of the manual, as follows: (710) Visual
(730) Pipe Yard Inspection
(710) Magnetic Particle
(740) Weld Radiography
(710) EMI - Flux Leakage
(750) Shop-Applied Coating
(710) Radiography
(750) Over-the-Ditch Coating
(710) Ultrasonics
(750) Field Joints
(720) Mill Surveillance
(750) Protection During Laying
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•
API STD 1104, Standard for Welding Pipelines and Related Facilities
See Section 790 for additional references.
Visual Inspection Visual examination is the first level of material inspection. It involves the use of the eyes, either unaided or with a low power magnifier, to look for imperfections and flaws. Visual inspection has obvious advantages: it is easy, straightforward, fast, and inexpensive; it requires little special equipment and provides important information with regard to pipe surfaces. Its limitations include an inability to evaluate metal interior, so other methods such as radiography and ultrasonics must sometimes complement visual examination. On bare pipe, visual inspection detects gouges, ERW weld irregularities (excessive trim or flash), SAW weld irregularities (contour, high-low, undercuts), dents, scale, pits, scores, notches, and sometimes laps or seams. For butt welds, visual examination is useful for detecting surface porosity, high-low (with access to inside surface), bead contour, and severe undercutting. Visual examination of the weld bevel can reveal damage, seams and laminations. The typical tools for visual inspection are magnifying glasses, flashlights, and mirrors. To look down the ID of pipes and tubes, an instrument called a borescope is used. Flexible fiber optic scopes are also available that permit the transmission of light and images around corners or through twisted or crooked channels. Gages, micrometers, calipers, rulers, tapes, etc., are also used for visual inspection. These devices are used to verify dimensions such as bevels, thickness and diameter. Experience is required in the use of some of these tools.
Magnetic Particle Inspection General Magnetic particle inspection (MPI) is a nondestructive method for detecting surface discontinuities or cracks in magnetic materials. MPI using AC current can also detect defects that are slightly subsurface, but is not totally reliable for this purpose.
Basic Principle The basic principle of magnetic particle inspection involves the following steps:
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Creating a magnetic field in the material so that magnetic poles are set up at discontinuities
•
Applying magnetic particles to the surface of the material
•
Visually examining the surface for any concentrations of the particles and evaluating the cause of the concentration (indication)
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Let us consider these stages in turn.
Establishing a Magnetic Field A suitable magnetic field can be established in the object by using a central conductor, coils, permanent magnets, yokes or prods (see Figure 700-2 and 700-3). Flaws that are perpendicular to the field set up local poles and form a leakage flux, thus attracting magnetic particles. Surface discontinuities are thus outlined by a buildup of magnetic particles (powder). The type of current can either be DC, AC, or rectified AC current. DC produces a deeper field and can, therefore, detect subsurface defects more effectively. AC is most effective for surface discontinuities but is ineffective for subsurface defects. Single-phase current (half-wave rectified AC) provides optimum sensitivity, and is the most commonly used on newer, portable equipment.
Magnetic Particles—Dry and Wet Once a suitable magnetic field is set up within the material, the magnetic particles are applied to show the leakage fields or discontinuity indications. Particles can either be dry powders or wet suspensions. In addition, particles suspended in liquid can be coated with a dye that makes them fluoresce brilliantly under ultraviolet light. This is known as black light or wet fluorescent mag particle inspection (WMPI). Dry magnetic particles should contrast with the pipe surface. Grey, yellow, and white magnetic particles are typically used. The WMPI method is a more sensitive method than the dry method.
Interpretation Interpretation of magnetic particle inspection is usually done by eye. The cause of indications can usually be seen unaided, but sometimes a magnifying glass is required. Indications are marked with a waxed crayon or paint. Depending upon the job specifications, indications are sometimes probed to investigate depth or to determine if the indication is merely superficial.
Magnetic Flux Leakage Inspection Magnetic flux leakage inspection, commonly referred to as electromagnetic inspection (EMI), is a variation of magnetic particle inspection. It is employed for full body pipe examinations either in the manufacturer’s mill, the field or pipeyard. Pipe inspection is performed automatically in an inspection unit. The pipe is magnetized either by passing it over a current-energized central conductor that induces a circular field in the pipe, or by passing the pipe through a coil which induces a longitudinal field in the pipe. See Figure 700-3. The circular field finds longitudinally oriented imperfections, such as seams and long cracks, while the longitudinal field finds circumferential imperfections, such as cracks and gouges. Instead of particles, EMI uses electronic sensors to detect the flux leakage. This allows a continuous inspection of the full pipe body excluding 6 inches to 12 inches of the pipe ends.
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Fig. 700-2
700 Inspection and Testing
Magnetic Field Induction Methods
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Fig. 700-3
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Pipe Body Magnetization Methods
EMI inspection is sometimes included in the mill’s quality control line. These units are adjusted for mill production speeds (which may exceed 200 feet per minute) but are generally not as accurate as field EMI units which operate at approximately 40 feet per minute. EMI services can also be purchased in the field. This inspection is very common for downhole casing and tubing but is performed on line pipe only in special cases. One cautionary note is necessary. Any residual magnetism in the pipe will cause welding difficulties. The surveillance inspection should ensure the EMI unit does not leave residual magnetism greater than 30 gauss when measuring with an electronic magnetometer (gaussmeter). If a mechanical magnetometer is used, the residual magnetism should not exceed 8-10 gauss.
Radiographic Inspection Introduction Radiography (also called RT) is a nondestructive test method that uses X-rays or gamma rays to detect defects in solid materials. A radiograph is a shadow picture produced by passing the rays through an object and onto a film. Thin sections of metal absorb less radiation and, therefore, make a dark pattern on the film. Thick sections allow less of the radiation energy to reach the film, producing a lighter image. For example, where porosity exists in a weld, there is effectively less solid material to absorb the radiation, resulting in characteristic dark round spots on the film. See Figure 700-4 for a simplified sketch of the technique. Radiography is the most commonly used weld inspection method for evaluating weld integrity; it is not generally used on the line pipe body. One advantage is that
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Fig. 700-4
Basic Elements of a Radiographic System
RT provides a permanent record of a weld which can be examined and evaluated by more than one person. The method is limited in that certain types of planar defects, such as cracks, can be missed if they are oriented at an angle to the beam of radiation or are tight and do not present enough change in density. Other drawbacks are that special equipment, training, and techniques are required, and it is somewhat slower and more expensive than other methods. However, in spite of these limitations, it is still a widely used method for evaluating the quality of a weld.
Equipment and Basic Principles The most common radiographic sources are X-ray machines and artificiallyproduced radioactive isotopes of certain metallic elements, such as Iridium 192. The isotopes emit gamma ray radiation. X-ray machines are used in the mill and, sometimes, portable units are used in the field. Gamma ray sources are used primarily on pipeline and field construction jobs where the source must be mobile. X-rays and gamma rays differ primarily in wavelength. The energy level (wavelength) of each isotope is fixed, while the energy level of an X-ray machine is a function of its tube and applied voltage. Also, the strength (number of rays per area, or flux) of an isotope source decays with time, but the strength of an X-ray machine is constant and controllable. The thickness of metal that can be penetrated by the radiation depends on wavelength. Shorter wavelengths (higher energy) permit deeper penetration. Exposure time for radiographing a thickness of metal depends on the energy level (or wavelength) of the source (see Figure 700-5), the type and thickness of the metal, the strength of the source, the film type, the use of intensifying fluorescent screens, and the source-to-film distance. The inverse square law, which states that the intensity of radiation varies inversely with the square of the distance from the
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source, governs exposure time. Figure 700-6 shows the effect of changes in variables such as radiation source and film type on radiograph quality. Fig. 700-5
Radiographic Sources and Approximate Applications
Source
Energy
Steel Thickness Range, inches
X-rays
80-120 Kev
0 to 1/4
120-150 Kev
0 to 1/2
150-250 Kev
0 to 1
250-400 Kev
1/4 to 2
6-31 Mev
1 to >8
Iridium 192
0.38 Mev
1/2 to 2 1/2
Cobalt 60
1.2 Mev
1 to 4
Fig. 700-6
Effects of Changes in Variables on Radiographic Quality
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Contrast and Films A number of factors control contrast, but the two most important are the energy level of the radiation and the type of film. Regardless of film type, contrast decreases as the energy level increases. Since Iridium 192 has a lower energy level than Cobalt 60, a radiograph from Iridium 192 will have higher contrast. This is also true of X-rays, the higher energy machines producing radiographs of lower contrast. Generally, X-rays produce more contrast than any gamma-ray service. Radiographic films have various degrees of speed. The faster the film, the less exposure is needed to produce a chosen density. However, fast films are grainy, and the grains become increasingly coarse as the speed of the photographic emulsion increases. Extreme coarseness does not record detail, and Company specifications do not allow the use of fast, coarse-grained films. For the best quality, ASTM E 94 type 1 or 2 film should be used. These are, respectively, low and medium speed films. For example, Kodak AA is a type 2 film, while Kodak Industrexm is a type 1 film. Type 3 and 4 films have high and very high film speeds, respectively, and should not be used.
Screens Radiographic film is held in a cassette, sandwiched between two screens. The two principal screen types are lead foil and fluorescent. Lead foil screens are the most widely used and give higher quality exposures than fluorescent screens. Lead screens serve a dual purpose: they act as intensifiers by emitting electrons and characteristic rays under the action of the primary radiation that aid in producing the radiograph. At the same time, they act as filters to absorb the scattered radiation that tends to fog the film. Lead screen thicknesses vary with source strength from 0.001 inch to 0.01 inch. Fluorescent screens are usually made of calcium tungstate crystals deposited on a thin background material. The X-rays or gamma rays cause these crystals to emit light that intensifies the film image. They decrease the necessary exposure time, compared with lead, but give less image sharpness. Most authorities and Company specifications discourage the use of fluorescent screens, since the sacrifice in film quality can result in the masking of significant defects. Either type of screen must be in close contact with the film during the exposure for good image sharpness. Also, the screens must be free from blemishes, scratches, dents, and any dirt that could be recorded on the film and misinterpreted as a defect in the weld.
Image Sharpness Other factors being equal, fine grained film produces the sharper image, but the size of the source is also a factor: the smaller the source size, the sharper the image. Increasing the source-to-film distance compensates for a large source. In general, the source-to-film distance should be at least seven times the thickness of the material being radiographed. Most radiographic work is done at much higher ratios, such as 30:1. Vibration or movement of the source or film during an exposure will cause a fuzzy image.
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Penetrameters A penetrameter indicates the image quality or sensitivity of the radiograph and is the true test of a radiographic procedure. In the United States, penetrameters usually consist of thin strips of metal with various size holes. In other countries, fine wires or small spheres may be used. Penetrameters are placed on the part being radiographed, and the ability of the radiograph to show a particular hole size or wire establishes the image quality. Figure 17 in API STD 1104 details the configuration of a penetrameter. The penetrameter image is the inspector’s most important tool for evaluating the quality of the radiograph. He should know the penetrameter requirement for the work or item he is inspecting and make sure the proper type is used in an acceptable manner. The applicable specification or code usually requires that penetrameters be properly shimmed to compensate for weld reinforcement and be placed on the source side of the weld.
Film Processing Many factors are important during film processing to assure quality radiographs. The most important are fresh, clean, properly mixed solutions, proper developer bath temperature (68°F is ideal), appropriate development time, and proper agitation, washing, fixing, and drying.
Viewing of Radiographs To properly interpret a radiograph, the viewing equipment should be in a darkened room. To prevent films placed against it for viewing from overheating and curling, the illuminator should have an adjustable cold fluorescent light or incandescent bulbs with forced ventilation. Commercially available variable intensity viewers are more versatile and provide particular advantages when viewing high or low density negatives. The film should be placed on the viewer and all light visible around the edges masked off. The first thing an inspector should look for is the penetrameter, to see if it is the proper size and shows evidence of good film quality, i.e., the outline of the penetrameter and two-thickness (or 2T) hole are visible. Quite often a film artifact is mistaken for a weld defect. The principal causes of such artifacts are: •
Dirty, scratched, or bent screens, which cause imperfections in the image
•
Localized pressure on a film, which causes easily recognizable pressure marks when the film is processed
•
Poor processing techniques, such as water marks from improper drying and scratches from handling
It is the inspector’s duty to learn to recognize film artifacts. Most film artifacts become obvious when the film surface is viewed at an oblique angle under white light.
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Interpretation and Acceptance Standards The ability to interpret the radiograph is a demanding skill that the inspector must become proficient in and strive to keep informed on, so that he can judge the welding according to the applicable standards. Radiographs fall into one of three evaluation categories: unquestionably acceptable, clearly rejectable, and borderline. In the last category honest differences of opinion will occur. Experienced interpreters will assess image sharpness, film type, identification, location markers, and proper density as indicators of film quality. The interpretation of the significance of a discontinuity is sometimes influenced by the interpreter’s knowledge of the film quality. For example, a serious defect may appear insignificant in a poor quality film, and an experienced interpreter will take this into account. In addition, of course, he must be thoroughly familiar with the applicable specifications and acceptance standards. Acceptance limits for particular defects in pipelines are specified in API STD 1104, Standard for Welding Pipelines and Related Facilities. API STD 1104 is also referenced by ANSI/ASME Codes B31.4 and B31.8. See Section 742. An alternate approach for acceptance standards based on a defect’s true threat to structural integrity is called fitness-for-purpose. This approach is more lenient with respect to pipeline welding quality, focusing rather on detailed engineering analysis of each case and knowledge of actual weld metal and base metal toughness. Because it is more cumbersome than arbitrary workmanship standards, it is hard to justify except in special situations. See API STD 1104 Appendix A. Note Amendment 195-52, page 33388 of the Federal Register, dated June 28, 1994, now allows pipeline operators to use Appendix A of API STD 1104, 17th edition.
Ultrasonic Inspection Ultrasonic (UT) inspection methods use sound waves to detect internal, external, and subsurface defects including those in ERW and SAW pipe weld seams, the depth of surface imperfections, and wall thickness. A transducer which can both transmit and receive a sound wave is placed on the material. With the aid of a couplant, such as grease, oil, or water, the sound beam penetrates the material and travels in a straight line until it hits a reflecting surface. This may be the opposite surface of the material, a crack or seam penetrating from the OD or ID, a subsurface crack or seam, a lamination in the material, weld porosity, undercutting, highlow, or lack of weld fusion. The beam reflects off this surface and is detected by the receiver portion of the transducer. Electronics convert the time it takes the beam to traverse the material to a length dimension. Note that flaws must be approximately perpendicular to the sound beam (plus or minus 10 to 15 degrees) to reflect effectively back to the transducer.
Longitudinal or Compression Wave Inspection A longitudinal (compression) wave is transmitted normal to the surface of the pipe and reflects off the internal wall. This method is useful for determining pipe wall thickness and internal laminations.
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Several types of instruments are available for longitudinal wave inspection, as follows:
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A cathode ray tube (CRT) displays a horizontal line with a peak on the far left-hand side. This peak is the initial pulse of the sound wave. When the transducer is placed on a surface, a peak will appear on the right. The distance between the two peaks is proportional to the thickness of the material. With proper calibration, the CRT displays wall thickness. Figure 700-7 shows the technique on a normal pipe wall. Figure 700-8 shows the display when a midwall lamination is present. Figure 700-9 shows the display for pipe with eccentric wall thickness.
•
A meter display can be calibrated to show full thickness at full scale. The wall thickness is read directly from the meter.
•
A digital display, properly calibrated, will directly indicate wall thickness.
Fig. 700-7
Compression Wave Ultrasonics, Normal Pipe Wall
Fig. 700-8
Compression Wave Ultrasonics, Mid-wall Lamination
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Fig. 700-9
Compression Wave Ultrasonics, Wall Thinning, Showing CRT Display
Transverse or Shear Wave Inspection Transverse (shear) wave UT inspection uses a transducer to transmit a sound wave into the material at an angle. The wave will reflect at defects that are normal or near normal to the wave. Defects such as cracks, rolled-in seams, weld root defects, and toe cracks can be detected by this method. The transducer is mounted in a plastic head that is machined at a prescribed angle (normally 45° to 60°). The wave reflects off a defect and, in part, back into the receiver portion of the transducer. Figure 700-10 shows the principle involved. A CRT screen is used for readout. Unlike longitudinal waves, the display consists of an initial peak and a small peak to the right which will move as the transducer is moved. When the transducer is moved a greater distance from the flaw, the indication disappears from the screen. Interpretation of the results of shear wave inspection requires a very knowledgeable, experienced operator.
UT Applications for Line Pipe There are several methods of applying UT to the field inspection of line pipe. Refer to Section 731 for the basic descriptions of UT weldline (crab) units, full body UT units, or compression wave UT (including pipe end area inspection).
713 Acceptance Criteria The acceptance of defects found by UT, magnetic particle, visual, or EMI inspection is based on API SPEC 5L, API STD 1104 or Chevron specification requirements. API SPEC 5L only requires mandatory full body pipe inspection (seamless pipe only) using any one of three alternative inspection methods (MPI, EMI, UT) when Supplementary Requirement SR4 is specified. Model Specification PPL-MS1050 suggests API SPEC 5L SR 4 inspection, using ultrasonics (UT) only, as a supplemental requirement (see Section 310 for pipe selection criteria). Model Specification PPL-MS-1050 also requires UT weldline inspection of ERW line pipe with walls thicker than 0.188 inches, and further requires the UT be done per API 5L SR 17 after hydrostatic testing using an N10 notch (10% of specified wall thickness) for calibration. This is much more stringent than the basic API 5L which allows
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Fig. 700-10 Shear Wave Ultrasonic Inspection
ERW weldline inspection to be performed using UT or EMI, does not define location (e.g., after hydrostatic testing), and allows V10 or Buttress notches or a drilled hole as calibration standards.
720 Mill Surveillance Mill surveillance (third-party inspection or monitoring) is performed on new line pipe at the manufacturer’s facility. Contract pipe inspectors are retained by CRTC’s Quality Assurance Team or by project management to perform the following: monitor critical pipe production operations, such as welding, sizing, heat treatment, and testing; and/or (2) monitor the mill’s internal nondestructive examination (NDE) inspections. At times, the third party inspectors may also perform extensive dimensional checks and visual examinations (these duties are performed by “bench inspectors” - see Section 723); however, most surveillance activities are currently typically limited to production and NDE monitoring with some random dimensional checks and visual examinations. Specific duties and responsibilities are given in Section 723.
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Mill surveillance provides assurance that the requirements of API Specification 5L and Company specifications are met. It increases the probability of culling defective joints that may be missed by the mill’s inspection and minimizes defective pipe delivered to the jobsite.
721 Recommendations for Use of Mill Surveillance Figures 700-11 and 700-12 summarize suggested inspections for line pipe. Fig. 700-11 Inspection Recommendations for Mill-Order Pipe, Chevron, or API Specifications Mill Surveillance: Inspection
Weld Seam UT
Critical Service(1)
Yes, if >50 tons(2)
Yes, all orders
If Had Surveillance SMLS
Visual(4)
General Service
If Had No Surveillance ERW
If Had No Surveillance(3)
If Had Surveillance
ERW
SAW
SMLS
SAW
SMLS
ERW
SAW
SMLS
No
No
No
Yes
-
(5)
Yes
Yes
(5)
(6)
No
-
No
No
No
ERW
SAW
No
No
No
Yes
Yes
Yes
-
(5)
No
-
(5)
(6)
No
No
(7)
(8)
No
Full-Body UT (or EMI)
No
No
No
(7)
Job Site Visual(9)
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Review MTR’s(10)
No
No
No
Yes
Yes
Yes
No
No
No
Yes
Yes
Yes
(1) (2) (3) (4) (5) (6) (7) (8) (9) (10)
Critical service is defined as high pressure gas >1440 psig, offshore, populated areas, or sour service. Example: 3400 ft of 12-3/4 inches x 0.219 wall. Not usually applicable, since mill surveillance is recommended for critical service. This could vary from a random visual to 100% visual depending on the extent of other inspection(s) done. (It may also include dimensional checks such as ring gaging pipe ends.) See decision tree in Section 312 - refer to the mill class definition explanation which denotes when and how much weld seam UT may be required. For API pipe, additional weld seam UT may be required - consult with CRTC’s Quality Assurance Team. Case by case basis; consult with CRTC’s Quality Assurance Team. Consider if previous problems with mill occurred or pipe is in critical service as defined in (1). In the case of mills which do not perform any EMI or UT, a minimum of 10% (General Service) or 25% (Critical Service) is recommended. See decision tree in Section 312 and supplemental specification requirements noted therein. For pipe body and bevel handling damage; inspection typically done by welding Contractor personnel. The material test reports (MTR’s) should be reviewed for conformance to API and/or Chevron requirements for all pipe not subjected to mill surveillance. Special emphasis is placed on the Carbon Equivalent (for weldability) and mechanical properties.
722 Mill Surveillance Teams Figure 700-13 shows the recommended minimum mill surveillance team size and makeup for seamless, electric weld (ERW), and submerged arc weld (SAW) mills.
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Fig. 700-12 Inspection Recommendations for Distributor Stock Pipe from Approved Sources(1) (2) (Post Mill at Pipeyard) Inspection
Critical Service(3)
General Service SMLS
ERW
SAW
SMLS
ERW
SAW
Yes
Yes
Yes
Yes
Yes
Yes
Weld Seam UT
-
(5)
(6)
-
(5)
(6)
Full-Body UT or EMI
(7)
No
No
(7)
(8)
No
(9)
Yes
Yes
Yes
Yes
Yes
Yes
Review MTR’s(10)
Yes
Yes
Yes
Yes
Yes
Yes
Other
(11)
(11)
(11)
(11)
(11)
(11)
Visual
(4)
Job Site Visual
(1) (2) (3) (4) (5)
(6) (7)
(8) (9) (10) (11)
An approved source is a mill that CRTC’s Quality Assurance has audited and approved. This pipe will be API with no chance of mill surveillance. Critical service is defined as high pressure gas > 1440 psig, offshore, populated areas, or sour service. This could vary from random visual to 100% visual depending on the extent of other inspection(s) done. (It may also include dimensional checks such as ring gaging pipe ends.) See decision tree in Section 312 - refer to the mill class definition explanation which denotes when and how much weld seam UT may be required. For API pipe, additional weld seam UT may be required - consult with CRTC’s Quality Assurance Team. (From nonapproved sources a minimum 25% frequency for General Service; a minimum 50% frequency for Critical Service.) Case by case basis; consult with CRTC’s Quality Assurance Team. (From nonapproved sources a minimum 25% frequency for Critical Service.) Consider if previous problems with mill occurred or pipe is in critical service as defined in (3). In the case of nonapproved sources or approved sources which do not perform any routine EMI or UT, a minimum 10% frequency for General Service; a minimum 25% frequency for Critical Service. See decision tree in Section 312 and supplemental specification requirements noted therein. For pipe body and bevel handling damage; inspection typically done by welding contractor personnel. The material test reports (MTR’s) should be reviewed for conformance to API and/or Chevron requirements for all pipe not subjected to mill surveillance. Special emphasis is placed on the Carbon Equivalent (for weldability) and mechanical properties. Other inspection methods may also be appropriate on a case by case basis. These include: full length MPI; Pipe end MPI; UT of ERW or SAW pipe ends for laminations; and so on. Consult CRTC’s Quality Assurance Team for guidance.
723 Mill Inspector Duties Duties of Supervisor The supervisor or shift leader (lead inspector) carries out the duties listed below. Typically, if there are two (or more) mill inspectors per shift, one will be designated the shift leader, and if there is more than one shift per day, one shift leader will be designated as the overall job supervisor. The supervisor may also be the NDE inspector. This typically occurs when there is only one inspector per shift and only one shift per day. In this case, that inspector would perform the duties listed below, as time permits, but would typically concentrate 60 - 80% of his/her efforts on NDE surveillance as described under “Duties of NDE inspectors”.
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Completely familiarizes him or herself with the requirements of the order.
•
Meets with pipe mill quality control personnel before the start of production to review the specifications, review, discuss, and agree upon mill procedures, and to establish the proper lines of communication.
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Fig. 700-13 Team Makeup for Mill Surveillance of Line Pipe The most typical mill surveillance team makeup currently used for APPROVED mills with some documented Chevron knowledge/history is indicated below. These team makeups are the minimum typically used. An increase (or decrease) in coverage may be warranted based on an analysis of the many factors listed below.(1) Mill Type
Minimum Number of Mill Inspectors/Shift
Seamless
ONE
(2)
Electric Weld (ERW)
TWO
(3)
Submerged Arc Weld (SAW)
TWO
(4)
Duties
(1) Some factors which affect team makeup are: a. Mill layout/general practices: compact or spread out facility; mechanical testing done concurrently with mill run or subsequently; NDT prove-up near inspection unit or at a remote location. b. Seamless mill: typically do not monitor pipe rolling or steel making. c. Specific order requirements: diameter of pipe; general or critical service; sweet or sour service; quantity of pipe in order; number of supplemental requirements specified; Chevron specifications or API. d. Other: approved or nonapproved source; well-documented history on mill or no information. (2) Seamless pipe inspectors. Concentrate mill surveillance on final full body NDE (60%). Balance of inspectors time spent monitoring the following, as applicable: hydrostatic testing (5%); final inspection bench (15%); mechanical testing (10%); verify length and marking requirements, pipe handling (damage), collecting /tabulating daily reject figures, report writing, and so on (10%). (3) ERW pipe inspectors. Concentrate mill surveillance on two areas: the pipe welding/seam normalizing operations; and the final weld seam UT. There is typcially a shift leader and a full time UT weldline inspector for each shift. The shift leader monitors pipe welding/seam normalizing (70%). Balance of monitoring time spent on the following, as applicable: final bench inspection; hydrostatic testing; mechanical testing; verify length and marking requirements, pipe handling (damage), collecting/tabulating daily reject figures, report writing, and so on. The UT weldline inspector monitors final UT weldline inspection (70 - 90%) and utilizes balance of time to monitor UT of pipe ends (if applicable), and assists shift leader at final bench inspection. (4) SAW pipe inspectors. Concentrate mill surveillance on two areas: the pipe welding operations; and the final weld seam UT. There is typically a shift leader and a full time UT weldline inspector for each shift. The shift leader monitors pipe welding (60%). Balance of monitoring time spent on the following, as applicable: final bench inspection; hydrostatic testing; pipe expansion; mechanical testing; verify length and marking requirements, pipe handling (damage), collecting/tabulating daily reject figures, report writing, and so on. The UT weldline inspector monitors final UT weldline inspection (70%) and utilizes balance of time to review radiographs, monitor UT of pipe ends (if applicable), and assists shift leader at final bench inspection.
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•
Completely informs him or herself concerning the production and quality control operations and procedures of the mill.
•
Establishes the work schedule of NDE and/or Bench inspectors.
•
Conducts a safety meeting for each shift once per week.
•
Provides NDE and/or Bench inspectors with written inspection instructions that contain the applicable tolerances for the order and any special instructions pertaining to the order.
•
Maintains surveillance over all operations in the pipe mill.
•
Periodically visits the mill inspection bench to review problems, determine the type of defects occurring most frequently, and follow up on them to determine the cause.
•
Verifies that mill Bench inspectors are performing final visual and dimensional inspections in a competent manner.
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Verifies dimensions are done and recorded per the frequencies and procedures agreed upon in the pre-production meeting. These dimensional checks include pipe body outside diameter (o.d.), pipe end o.d., wall thickness, end squareness, bevel, root face, internal taper (seamless), and straightness.
•
Verify length, marking, demagnetization, ERW weld flash or trim, SAW weld contour, etc., meet order requirements.
•
Verify that pipe to be subsequently coated is free of mill varnish, grease, slivers, sharp protrusions, etc.
•
Witnesses the periodic calibration of the nondestructive testing equipment to assure its proper operation.
•
Reviews the radiographs on a spot check basis to assure proper interpretation. The number of radiographs reviewed will vary depending upon the results of the spot check.
•
Periodically witnesses the fluoroscopic inspection and assures that the speed of travel and settings are such that the penetrameter can be clearly defined.
•
Periodically checks railcars, trucks or ship holds before loading for debris and attachments that may damage pipe.
•
Periodically checks the loaded cars, trucks or ship holds to assure that they are loaded in accordance with API RP 5L1, Railroad Transportation of Line Pipe or API RP 5LW, Transportation of Line Pipe on Barges and Marine Vessels, or other specified recommended practices approved by the purchaser. This inspection should include a spot check for body and bevel damage due to improper handling during loading.
•
Checks hydrostatic testing charts and operation for conformance to order requirements. Includes verification that test gages and recorders are in current calibration.
•
Checks the welding and repair welding operation for compliance with the mill’s procedures. This includes a review of the procedure qualification test records and the performance test records of each welder to assure that the requirements of Appendix B of the API SPEC 5L are met. Particular attention should be taken to assure that low hydrogen electrodes, if used, are stored in an electrode dry rod box.
•
Checks loading crane hooks to assure that they are properly designed to eliminate bevel damage.
•
Witness as many mechanical tests as possible to assure that the test procedure is correct and all test equipment is in current calibration. This should include a spot check of the test specimen measurements.
•
Assures that the proper number of tests are made and the chemical and mechanical properties meet the required specifications.
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•
Assures that all shipping documents and mill chemical and mechanical test certificates are collected by the mill and forwarded to the Company office at the immediate completion of pipe production. If they are not then available, the mill personnel must be advised to forward them to the Company purchasing agent or project engineer.
•
Immediately reports any serious problems to the Company for review.
•
Collects the daily reject figures including types of rejects from all applicable sources, checks them for accuracy and forwards a summary of them to the Company at the required frequency (sometimes daily) and at the completion of the inspection assignment.
•
Tabulates the total number of feet of each size and wall thickness of pipe accepted each day, and keeps a cumulative record so that the status of the order is known at all times.
Duties of NDE Inspectors These are contract inspectors assigned to witness the final UT (or EMI) on seamless pipe or the final UT weldline inspection on ERW or SAW pipe. (Refer to Figure 700-13). In some cases, the NDE Inspector may also be the Supervisor/Shift Leader (when only one contract inspector per shift required). In this case, the NDE Inspector would concentrate his or her efforts on the final NDE (60 - 80%), but may also perform other mill surveillance activities included under “Duties of the Supervisor”. The NDE Inspector typically performs the following duties: •
Witness the periodic calibration of the NDE unit
•
Witness NDE inspection of all pipe
•
Verify calibration and operation of the NDE unit per approved mill procedures
•
Verify all pipe with indications exceeding the acceptance limit is thoroughly proven up, etc
•
Verify any defects (or imperfections) removed by grinding are completely removed and the remaining wall thickness is verified
•
Verify the weld line on ERW or SAW pipe ends not covered by automated UT is manually UT’d
•
As time permits, assist the Shift Leader monitoring the mill bench inspectors
•
As time permits, also monitor end area UT or MPI inspections
Duties of Bench Inspectors The previous (January 1990) edition of this manual detailed the duties of Bench Inspectors. As noted in Section 720, the extensive dimensional checks and visual examinations included such duties as checking the outside diameter of each end of each pipe, checking out of roundness on each end of each pipe larger than 20 inches
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NPS, checking the wall thickness of each pipe, close visual examination of each pipe, and so on. These duties essentially duplicated everything randomly checked by the mill bench inspectors and much more. This type of extensive dimensional and visual examination would now only be considered for nonapproved mills (or substandard mills) with whom Chevron has no previous experience or knowledge. Some of these duties may still be applicable for very critical orders. Consult with CRTC’s Quality Assurance Team for guidance.
Reporting Contract inspectors forward all reports, tallies, and problems to the Chevron Project Engineer or Quality Assurance Engineer who is handling the order.
724 Qualifications of Mill Inspectors Mill inspectors usually are certified by the American Society for Nondestructive Testing (ASNT) as Level II inspectors for specific inspection techniques such as magnetic particle, ultrasonics, etc. The inspection agency may also carry out certification and training programs on their own. A Level II inspector has demonstrated through tests and experience that he or she knows the principles of the inspection technique, can apply the technique with the desired results, and can interpret the indications that are found. Inspectors normally have worked for manufacturers in the inspection department or for a pipe user in a materials laboratory, quality assurance, or other similar position. It is the responsibility of CRTC’s Quality Assurance Team to confirm that the inspectors being used for mill inspection and surveillance are qualified and hold the appropriate certifications. Periodic requalifications are required to maintain certification. Resumes of the inspectors are usually reviewed by CRTC’s Quality Assurance Team to assess their level of experience, dates of last testing, and certification and performance. Inspectors that have performed poorly in the past are not permitted to work on Company jobs or projects.
730 Post-Mill Inspection Post-mill inspection of line pipe, commonly called field or pipeyard inspection, is done to detect transit damage, and defects missed by the mill inspection. The inspection is done visually, or by magnetic particle, EMI or ultrasonics. Radiography is not used. Field or stockyard inspection will not add to the quality of the pipe, but will minimize defective pipe delivered to the jobsite. Field or pipeyard inspection can be done at any location from the time the pipe leaves the mill production line to the time it is welded into the pipeline. Figure 700-1 shows inspection points and relevant sections of this manual. In some cases, post-mill inspection is done on the mill property by nonmill parties. It is not to be confused with mill surveillance, because it involves inspection with
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nonmill equipment and personnel. Post-mill inspection is also typically done in a pipeyard near the staging area for pipe shipment or stringing. Company inspection practice is summarized in Figures 700-11 and 700-12. Basic practice calls for mill surveillance on large pipe orders out of the mill. Post-mill inspection is recommended for some general service and all critical service pipe that has not undergone mill surveillance. On projects involving critical service applications, see Model Specifications PPL-MS-1050 and PPL-MS-4041. Pipeyard inspection should also be considered for API SPEC 5L pipe that is purchased from a non-Chevron-approved mill or from distributors stock. API RP 5L8, Recommended Practice for Field Inspection of New Line Pipe discusses inspection procedures and qualification of inspectors, and makes recommendations on good practices for carrying out inspections. This document should be used as a reference when specifying inspection procedures.
731 Types of Field Inspection Services for Line Pipe API RP 5L8 discusses standard inspection techniques and procedures for line pipe, including visual and dimensional inspection, magnetic particle inspection, electromagnetic inspection, and ultrasonic inspection. It details the procedures for evaluating inspections for pipe mill defects, pipe seam welds, mill grinds, wall thickness, dents, laminations, straighteness, diametrical parameters, etc. A discussion of the advantages and descriptions of the various inspection techniques are presented in Section 712. Figure 700-1 summarizes recommended inspection methods and points. Field inspection service companies perform any of the following inspections:
Chevron Corporation
•
Visual and dimensional inspection. Searches for visual imperfections, such as dents, gouges, pits, corrosion, wall thinning, and seam weld appearance. Dimensional parameters such as diameter, wall thickness, and bevel dimensions are monitored. Pipe markings are verified.
•
Magnetic particle inspection. Done on bevels to detect and evaluate defects such as cracks, mill seams, weld defects, and laminations. The procedure involves dragging a yoke along the bevel.
•
EMI electromagnetic inspection. EMI scans the entire pipe body for OD and ID defects such as seams, wall thickness eccentricity, gouges, pits, and scores. EMI is usually only done on seamless pipe.
•
Ultrasonic inspection. Shear wave ultrasonic inspection is used to evaluate weld seams. Angle transducers are mounted on a crawler or crab unit which moves along the weld seam. The signal is translated into a printout or a chart.
•
Compression ultrasonics. Used to check for wall thickness. This is done with hand-held units such as the Krautkrauer-Branson D-Meter. Also used to check pipe ends for laminations using either hand-held units or special semi-automated units.
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•
Combined shear and compression wave UT. These units are typically permanently mounted under roof units. although there are one or two such units available which are mobile, which are capable of scanning both the pipe body and pipe weld seam. They use angle transducers for detecting longitudinal and circumferential defects and straight (compression) wave transducers for wall thickness.
•
Radiographic inspection. Radiography is not done in the field to inspect pipe. It is, however, the most common method to inspect girth welds during pipeline construction and is discussed in Section 712 and 740.
Large companies providing field inspection services include the following: •
Tuboscope Vetco International P.O. Box 808 Houston, TX 77001-0808 Ph: 713-456-8881 Fax: 713-456-6197
•
Ico, Inc. 9400 Bamboo Houston, TX 77041 Ph: 713-462-4622 Fax: 713-462-4821
Small companies providing field inspection include the following: •
A&A Tubular Inspection, Inc. 3075 Walnut Ave Long Beach, CA 90807 Ph: 310-981-2351 Fax: 310-981-2354 (Also have a Houston, TX., location)
(UT Weldline Inspection ONLY) •
Reliant Oilfield Services, Inc. Rt. 1, Box 143 Linden, TX 75563 Ph: 903-756-5656 Fax: 903-756-5283
732 Qualification of Inspectors and Inspection Companies for Line Pipe There are generally two categories of field inspection personnel, as follows: •
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Service companies. Field inspection services are provided by large inspection companies such as Tuboscope Vetco International, Ico Inc, or small companies such as A&A Tubular and Reliant Oilfield Services. These companies provide the equipment and inspection personnel.
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•
Third parties. Third party inspections provide surveillance over service company crews. They may be useful when inspection service companies deploy less qualified crews or deploy crews unfamiliar with typical Chevron field inspection requirements, e.g., calibration notch requirements, frequency of calibration, etc., and therefore third party surveillance helps assure that inspections are conducted properly. Consult with CRTC’s Quality Assurance Team for guidance.
Field Inspection Companies CRTC’s Quality Assurance Team maintains lists of qualified inspection companies, including qualified equipment and equipment operators. These companies are qualified on the basis of their ability to do the job, the services they offer, the experience of their personnel, past performance, test joint evaluations, location of inspection units, and the cost of their services. An inspection service which has done acceptable work in one area, for example, on the Gulf Coast, may not be acceptable in the Rocky Mountains or West Coast. The engineer is encouraged to consult with CRTC’s Quality Assurance Team for acceptable service companies in the area where the job will be performed.
Field Inspector Qualification The inspection service company internally qualifies their employees in the various inspection services that are offered. Documentation concerning the specific training, examinations and experience of the inspectors should be available upon request. Inspector qualification documentation should show: •
Training programs or courses attended on each of the inspection methods in which the inspector is qualified
•
Records of written examinations
•
Records of hands-on examinations on calibration, operation, and interpretation of the various types of equipment the inspector is qualified on
•
A written record or resume of inspection experience
Field Inspection Crews A field inspection crew generally consists of two to four individuals. The job functions are as follows:
Chevron Corporation
•
The supervisor or crew leader is responsible for the inspection unit equipment and supervises the crew. This person requires the highest qualification since he or she is actually responsible for the job. This person has the ultimate responsibility of accepting or rejecting the joint of pipe, based on the specification.
•
The inspection helper is responsible for locating flaws and confirming whether or not these meet the specifications. He or she is supervised by the crew leader. The helpers qualifications should include written and hands-on
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examination as well as inspection experience, although he or she will usually be less experienced than the supervisor. •
One or two laborers are generally part of the inspection crew. They may be employees of the inspection agency or hired out of the local labor pool. They do not usually have any inspection qualifications, and should not perform any interpretations.
Third-Party Inspectors These inspectors monitor the service company inspection crews. They may be employed by an inspection agency such as Moody-Tottrup, or may be independent contractors. Typically, a few small independent contractors, which have been developed over many years, are used for monitoring. The experience of these individuals may include former employment with an inspection service company, line pipe user, or manufacturer. These individuals may have formal test certifications from the American Society of Nondestructive Testing (ASNT). A list of qualified third-party surveillance inspectors is maintained by CRTC’s Quality Assurance Team, which should be contacted if these services are required.
Duties of the Third Party The third-party inspector has a responsibility to: •
Represent the Company at the jobsite and aid in the interpretation of defects. The third-party inspection provides a link between the Company and service company, but is not involved in changing work orders or scheduling
•
Assure that the inspections are properly performed
•
Witness all calibration checks and assure that equipment is working properly
•
Monitor each new inspector to assure that they have the proper qualifications
•
Be present during the whole job or as directed
•
Review each rejected joint to assure that the cause of rejection is valid
•
Communicate the job status daily to the Company representative
•
Communicate difficulties with interpretation or inspection personnel to the Company representative
733 Recommendations for Pipe Inspection Recommendations for pipe inspection are given in Figures 700-11 and 700-12. Chevron has commonly performed mill surveillance inspections on line pipe for critical service. Critical services are defined as high pressure (>1440 psi), populated areas, offshore, and sour gas. Factors (in addition to critical service) which are important in making a judgment to perform further field inspections are as follows:
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•
Grade. Higher grades (X-60 and greater) are used for high pressure lines and have thinner walls
•
Weld Method. ERW versus SAW
•
Mill Origin. Some mills have better equipment for producing and inspecting pipe than others
Groups within Chevron that may be consulted to give guidance on pipe inspection include the following: •
CRTC, Materials and Equipment Engineering, Quality Assurance – –
•
510-242-4612 (Richmond) 510-242-3381 (Richmond - alternate)
CRTC, Materials and Equipment Engineering, Metallurgy –
510-242-3245
740 Pipeline Welding Inspection This section discusses the requirements and procedures for inspection of pipeline girth welds. Normally, the Company’s arrangements for pipeline welding inspection are independent of the pipeline contractor’s organization. The contracts for welding inspection and nondestructive examination (radiography) are based on applicable codes, regulations, and Company requirements. However, the Company’s quality assurance responsibilities must be carefully coordinated with the pipeline contractor to avoid lessening his sense of responsibility for the quality of the pipeline welding. The Company’s responsibilities include: •
Preparation of clearly written specifications for the inspection and nondestructive examination (NDE) of the pipeline welds
•
Providing qualified welding inspectors
•
Assuring that welding procedures and welders are properly qualified
•
Documenting or assuring documentation of all inspection results and providing quality control feedback to the pipeline contractor
•
Spot visual examination of pipeline fit-up before welding, the welding in progress, and the completed welds
•
Providing radiographic inspection through an inspection organization whose personnel are qualified to the American Society of Nondestructive Testing (ASNT) Recommended Practice No. SNT-TC-1A
National regulations and codes that have requirements concerning pipeline welding are listed in Section 630 of this manual. Pipeline maintenance welding is discussed in Section 860.
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741 Duties and Qualifications of Welding Inspectors Welding inspectors should be thoroughly familiar with API STD 1104, Standard for Welding Pipelines and Related Facilities, (or applicable local code) and Company specifications for welding and inspection of pipelines. API RP 1107 pertains to maintenance welding. The duties of a welding inspector for pipeline welding include but are not limited to the following: •
Witnessing welding procedure qualifications and assuring that the welding procedure specification is followed during the qualification. When required, witnessing the mechanical tests for the procedure qualifications and verification of the results provided by the testing laboratory
•
Witnessing welder qualification tests and assuring that the welding procedure specification is followed; documenting the test conditions and the welders taking the test. Terminating the test as soon as it is obvious that a welder lacks the skill to pass the test, particularly after the root and hot pass. Checking and grading test specimens and documenting results
•
Witnessing pipeline fit-up and checking for correct joint preparations, alignment, cleaning of the weld prep, and use of fit-up equipment
•
Witnessing pipeline welding and checking that all details of the procedure are being followed properly, including preheat, use of electrodes, time allowed between root and hot pass, weld cleaning and welding technique, verifying that welds are marked with the welder’s identification in a manner not injurious to the pipe
•
Checking of radiographs for repairs and proper identification as to weld joint number and welder symbols
•
Working with the chief inspector to identify and eliminate substandard welders through the quality assurance program
Qualification of Welding Inspectors API STD 1104 requires that welding inspectors be qualified on the basis of experience and training but does not provide specific requirements. The Company, then, has to establish its own requirements. In the past, inspection jobs tended to be given to more senior pipeline personnel and emphasized experience in pipeline welding. While welding experience is still important, a highly recommended alternative is that the welding inspector be certified by the American Welding Society (AWS). To be certified by AWS the welding inspector must take a written examination and have five years’ welding experience. The written examination requires understanding of code and nondestructive testing, and a broad background in welding. Certification renewal is required every three years, and includes an eye examination, maintenance of welding experience, and payment of a fee. In addition, AWS requires reexamination every nine years.
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Additional training should be considered for pipeline welding inspectors on major jobs to increase their familiarization with the codes and regulations. One organization offering a one-week training course is the National Pipeline Welding Inspection School, located in Houston, Texas. API STD 1104 requires that the documentation of a welding inspector’s qualifications include at least the following: • • •
Education and experience Training Results of any qualification examinations
Qualification of NDE Personnel ASNT Recommended Practice SNT-TC-1A, for certification of personnel, assigns three levels of proficiency in various NDE methods (radiography, liquid penetrant, magnetic particle, etc.) based on training and experience. The levels are categorized as I, II, and III in ascending order of qualification. Contract inspection companies performing radiography are required to have their personnel certified to SNT-TC1A as explained in Section 745. Welding inspectors who grade and interpret radiographs are also required to be certified to Level II or III.
742 Qualification of Welding Procedures and Welders Qualification of welding procedures and welders is the Company’s responsibility (see Section 630 and Model Specification PPL-MS-1564). API STD 1104 should be used for this purpose. The pipeline contractor may submit welding procedures for qualification or use procedures previously qualified by the Company. Welder qualification tests should be witnessed by the Company. Testing should be terminated any time it is apparent the welder cannot make a sound weld.
743 Documentation and Quality Control Documentation and quality control for pipeline welding should include both welding and radiographic inspection. Documentation should cover a minimum of the following:
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•
Welding Procedure Qualifications. Each welding procedure should be qualified and recorded as described in API STD 1104.
•
Welder Qualifications. Each welder should be qualified to use the procedure within the essential variables as described in API STD 1104. Requalification is required any time a welder has not used a given process of welding for a period of six months or more. ANSI/ASME B31.8 imposes additional restrictions for gas transmission piping.
•
Radiographic Procedure. Qualification of each radiographic procedure is required as described in API STD 1104 and in Section 745 following. The procedure should be signed by a level III radiographer.
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•
Radiographic Inspection. Results of radiographic inspection should be documented for each weld and signed by a level II or III radiographer. The weld number, radiographic procedure, and welder identification should be clearly stated.
•
Welder Identification. Each welder should be given a unique identification number or mark for his work which is traceable to his welder qualification records.
•
Weld Marking. Each weld should be given a unique identification number that can be traced to its location from the as-built drawings. Crayon or paint should be used for marking, not metal stamps.
Quality control for pipeline welding should be based on the results of the radiographic inspection of each welder’s work. Easy identification of a substandard quality record is important for weeding out poorly performing welders. Performance should be based on the percentage of welds requiring repair for each welder. This varies depending upon pipe size and wall thickness. A repair record of more than 2 to 5% is generally cause for warning, and for dismissal if poor welding continues.
744 Visual Examination Visual examination before, during, and after welding is one of the welding inspector’s most important jobs. Visual examination includes both the pipe and the welds. Documentation of visual examinations can vary from a minimum of daily field notes to formal checklists, depending upon the size of the job. The frequency of visual examinations can vary from 100% surveillance to selective spot checking, depending upon the location of the pipeline (i.e., urban, rural, crossing, etc.) and the risks to pipeline operations. The following is a list of the visual examinations which should be made or verified by the welding inspector: •
The pipe is in good condition and free of defects
•
Cold bends have been made properly without damaging the pipe or coating, and the pipe is free of wrinkles, flat spots, and excessive out-of-roundness
•
Each joint of pipe has been swabbed clean of trash and debris before it is placed in the line
•
Bevels and lands are satisfactory for welding and are: – – –
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Free of material defects (e.g., laminations) Properly cleaned and free of weld contaminants such as rust, grease, and other foreign material Dimensionally correct and within tolerances
•
The pipe is free of handling damage, or has been repaired
•
The pipe is properly supported by studs for welding
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•
The welding is performed as required by the procedure and has been checked for: – – – – – – – – – – – – – –
•
Pipe fit-up and alignment. Offset and gap dimensions are within tolerances Correct preheat Sound stringer pass without cracks, undercut, or excessive porosity. Proper grinding for the hot pass Adherence to the maximum time permitted between the stringer and hot pass Interpass cleaning (power wire bushing) and grinding starts and stops as needed Fit-up clamps used as specified in the procedures Correct types (AWS classification) and diameters of electrodes. Electrodes are in good condition for welding (i.e., free of damage and contamination) Correct welding polarity. (Generally DC+, but DC- is sometimes used for the root pass with certain electrodes, such as Lincoln 5P and HYP) Staggered starts and stops to avoid alignment with other passes No cracks, undercut, or excessive porosity in any bead Minimum number of passes as specified in the procedure for the thickness (but not less than three) Correct reinforcement and width of the cap pass and no excessive undercut of the pipe Welder identification marked in a manner not injurious to the pipe but permanent enough for pickup by the X-ray crew Weather, wind, and dust conditions not adverse to good welding practice
Defect repairs do not exceed more than one repair at any given location in a pipe weld, and the welder contributing to the defect is identified
745 Radiography of Field Welds The use and frequency of radiographic inspection is established by the Company. Radiography is performed to the acceptability standards in Section 6.0 of API STD 1104 and additional requirements of the Company (see PPL-MS-1564). Fundamentals of radiography are discussed in Section 712 of this manual.
Radiographic Procedure Before any radiography can be performed on a pipeline, a detailed procedure for the production of radiographs must be prepared, recorded, and demonstrated by the radiographic contractor to produce acceptable radiographs, in accordance with Section 8.0 of API STD 1104. API STD 1104 requires demonstration on test shots that the radiographic procedure produces acceptable radiographs. A written procedure is required that includes at least the following: •
Chevron Corporation
Radiation source. Covers type of radiation source, effective source or focal spot size, and voltage rating of X-ray equipment.
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•
Intensifying screens. Describes the type and placement of screens, and lead screen thickness (see Section 712). Lead screens are preferred for pipeline work. An exception is offshore construction from a lay barge, where remoteoperated, battery-powered, crawler-mounted internal X-ray heads are frequently used. These generally employ fluorescent screens to minimize exposure times and battery recharging frequency. Intermediate speed fluorescent intensifying screens (e.g., Du Pont Conex NDT 5) with fine grain medium speed film have proved satisfactory for this application. Fluorescent screens are very sensitive to dirt, dust, and scratches, and must be kept immaculately clean and replaced more frequently than lead screens.
•
Film. Film brand rather than film type should be specified, along with the number of films per cassette. Where more than one film per cassette is specified, how they will be viewed should be stated (e.g., single film viewing or double film viewing). In the past film type designations (Type 1 or 2) have been accepted in lieu of brand names. However, because of significant variations in the grain size and speed of films meeting the same type, this designation should not be used to obtain equivalent radiographic quality by substitutions made solely on the basis of film type.
•
Exposure Geometry. Exposure geometry refers to the relative placement of the source of radiation, pipe weld, film, penetrameters and lead markers (for film intervals and reference). The number of exposures per weld is also stated. Variations include the following: –
–
–
•
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SWE/SWV. Single-wall exposure with single-wall viewing. The radiation source is positioned for single-wall penetration. A typical setup would be with the source on the inside and the film on the outside. When the source is centered inside of the pipe, a single 360-degree exposure of the weld can be made. DWE/SWV. Double-wall exposure with single-wall viewing. The radiation source is positioned for double wall penetration, but only the weld from “one” wall (i.e., one side of the pipe) is recorded on the film. A typical setup is with the source on the outside of the pipe and the film on the opposite side. A minimum of three 120-degree exposures are required if the source is positioned within 1/2 inch of the pipe, otherwise four 90degree exposures are required (see Figure 700-14). DWE/DWV. Double-wall exposure with double-wall viewing. The radiation source is positioned for double wall penetration, with welds on “both” walls recorded on the film. NPS 3 and smaller pipe requires this technique with the radiation beam offset so that the source side and film side portions of the weld do not overlap in the area of the radiograph to be evaluated. Two or more exposures (N) are required with each shot, separated by 180 degrees divided by N.
Exposure Conditions. The exposure conditions depend on the exposure parameters of the radiation source (either X-ray or radioisotope). For X-ray units, they are measured in milliamperes, peak X-ray voltage (KVP), and exposure time. For radioisotopes they are measured in curie minutes.
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Fig. 700-14 Double-Wall Single-Image Radiography
•
Processing. The radiographic procedure should specify: – – –
Automatic or manual processing Time and temperature of solutions for development, stop bath (or rinse), fixation, and washing Drying method
•
Materials. Type and thickness range of material for which the procedure is suitable
•
Penetrameters. The type of penetrameter (API STD 1104 or ASTM E142), material, identifying number, and essential hole to meet the required sensitivity level should be specified. Shim material and thickness should also be given. The minimum sensitivity level is 2% unless otherwise stated
Double-Jointing Yard Inspection At double-jointing yards the pace of welding and radiography is quite rapid. Attention must be given to providing and achieving required radiographic inspection coverage. •
Repairs to rejected welds must be re-radiographed. Otherwise only the radiograph films of the defective weld will appear in the final documentation, and the missing record of the satisfactory repair will not be available to the authority inspecting and certifying the pipeline.
Weld Acceptance Standards Section 6.0 of API STD 1104 covers the standards of acceptability for radiographs. These are summarized in Figure 700-15 for easy reference.
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Fig. 700-15 Summary of Standards of Acceptability for Radiographic Weld Inspection Type of Defect
API Standard 1104
Notes
Cracks
None allowed except shallow crater cracks in the cap pass with maximum length of 5/32".
(1)
Incomplete Penetration at Root Pass
Max 1" length in 12" of weld, or 8% of weld length for welds less than 12" long. Max individual length 1".
(2)
Incomplete Penetration Due to HighLow Flow
Max individual length 2". Max total length of 3" in 12" of continuous weld.
(2)
Incomplete Fusion at Root Pass
Max of 1" length in 12" of weld, or 8% of weld length for welds less than 12". Max individual length 1".
(2)
Incomplete Fusion at Sidewall or Cold Lap
Max individual length of 2". Max total length 2" in 12" of continuous weld.
Burn-Through (NPS 2 and Larger)
Max 1/4" or wall thickness, whichever is less, in any dimension. Max total length of 1/2" in 12" of weld.
Internal Concavity
If radiographic image of internal concavity is less dense than base metal, any length is allowable. If more dense, then see burn-through above.
Undercut at Root Pass or Cap Pass (Radiograph Plus Visual)
Max allowable depth is 1/32" or 12 1/2% wall thickness, whichever is less. Max 2" length in any 12" or 1/6 of weld length, whichever is less, for depth of 1/64" to 1/32" or 6 to 12% of wall thickness, whichever is less. Depths less than 1/64" acceptable regardless of length.
Slag Inclusions (NPS 2 and Larger)
Elongated: Max width 1/16". Max length 2".
(3)
Parallel slag lines: considered separate if width of either exceeds 1/32". Isolated slag inclusions: max width 1/8" and 1/2" total length in any 12" of weld. No more than four isolated inclusions of 1/8" max width in any 12". Porosity
Spherical and piping: Max dimension 1/8" or 25% of wall thickness, whichever is less (6.61, 6.63). Max distribution shown in API STD 1104. Cluster: Max area of 1/2" diameter with individual pore dimension of 1/16 in. Max total length is 1/2" of weld. Hollow bead: Max individual length 1/2 “.
Max 2" total length in 12" of weld with individual discontinuities exceeding 1/4" in length separated by at least 2".
Weld Reinforcement at Finish Bead
Max 1/16" by approximately 1/8" wider than original groove.
Excessive Root Penetration
Not covered.
Misalignment
Maximum 1/16".
Accumulation of Discontinuities
Maximum of 2" in any 12" or 8% of weld length excluding high-low and undercut condition.
General
Rights of rejection: “Since NDT methods give two-dimensional results only, the Company may reject welds which appear to meet these standards of acceptability, if in its opinion the depth of the defect may be detrimental to the strength of the weld.”
(1) Cracks of any kind are detrimental and should not be allowed. (2) For sour service (partial pressure of H2S ≥ 0.5 psi (0.35 kPa)) Chevron Canada Resources specifies none allowed. CAN3-Z183 and CAN/CSA-Z184 codes suggest “additional restrictions on internal surface imperfections may be warranted for sour service.” (3) As for Note 2, but only at the root pass.
Company Weld Acceptance Standards The Company generally follows the API STD 1104 standards. Some Operating Companies, such as Chevron Canada Resources, specify more stringent standards for acceptance of girth welds. This is especially true for critical or sour services,
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Fig. 700-16 Code Mandatory Radiographic Weld Inspection Frequency ANSI/ASME Code
Canadian Standard
B31.4
B31.8
Weld Category
hoop stress
>20% SMYS
≤Gr 290
>Gr 290
≤Gr 290
>Gr 290
Production Welds
10%
—
15%
15%
visual sample
15%
Sour Service Welds <20% SMYS
—
—
15%
—
—
—
Sour Service Welds >20% SMYS
—
—
100%
100%
100%
100%
Populated Areas
100%(1)
—
—
—
—
—
1
—
10%
—
—
—
—
2
—
15%
—
—
—
—
3
—
40%
—
—
—
—
4
—
75%
—
—
—
—
Water Crossings
100%(1)
100%
100%
100%
—
—
Rail & Highway Crossings
100% (1)
100%
—
—
—
—
Offshore & Inland Coastal Waters
100%(1)
100%
—
—
—
—
Old Welds in Used Pipe
100%(1)
—
—
—
—
—
Tie-in Welds
100%(1)
—
—
—
100%
100%
Uncased Railway Crossings
—
—
100%
100%
—
—
Cased Crossings w/ F = 0.72
—
—
—
—
100%
100%
Crossings w/ F = 0.60, 0.50 or 0.40
—
—
—
—
100%
100%
Location Class
Notes:
Z183
Z184
1. All percentages are minimums. All inspection for 100% of circumference. 2. Sour service is 0.5 psi (0.35 kPa) partial pressure of H2S.
(1) Minimum 90% if some welds are inaccessible.
where the concern is crevice corrosion. The notes to Figure 700-15 show the more stringent requirements. The use of more stringent standards should be carefully considered for each project. In some areas it may be impossible to enforce higher standards because the welder expertise is not available. Inability to meet higher specified standards after the project has started could lead to disputes with regulatory agencies.
Radiographic Inspection Frequency ANSI/ASME Codes B31.4 and B31.8 and CAN3-Z183 and CAN/CSA-Z184 specify similar but slightly different inspection frequencies, depending on class location, design safety factor, installed location and fluid carried. See Figure 700-17.
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Fig. 700-17 Hydraulic Profile: Hydrotest Heads
Section 434.8.5(a)(4) of Code B31.4 and Section 826.2(b) of Code B31.8 stipulate these frequencies. Section 6.2.8.2 of CAN3-Z183 and Section 6.2.8.2.2 of CAN/CSA-Z184 provide similar frequencies. For noncritical lines the basic code frequency is quite low. In some cases this means the radiographic crew is underworked. It is therefore usual to have the crew work steadily for the full shift (if the crew is onsite anyway). For a small extra expense for added film, you can thus achieve up to 50% inspection coverage and greatly increased confidence.
750 Pipeline Coating Inspection Inspection of pipeline coatings is done at coating application plants and at the pipeline construction site. Because coatings are susceptible to damage in handling, visual inspection should be done at various stages in shipping the pipe from the application plant to final lowering into the ditch. Inspection of coating application at permanently established plants may be done by Company inspectors or
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contracted inspection agencies under the general supervision of a Company Quality Assurance organization. Inspection at field plants and as the line is laid is normally done by the Company field organization, with the Company inspectors or contracted inspectors reporting directly to the Company lead inspector. The National Association of Corrosion Engineers (NACE) offers an International Coating Inspector Training and Certification Program that is the only established qualification procedures for coating inspectors. Training by experienced Company inspectors and field engineers and by Materials Specialists will prepare an inspector for coating inspection, with emphasis on the particular coating systems for a project. Much valuable information on coating quality is available in industry publications (Oil and Gas Journal, Pipeline Industry, Pipeline, etc.) and in standards established by NACE. The CRTC Materials and Equipment Engineering Unit can provide classes on coatings inspection, tailored to the needs of individual projects. NACE also conducts regional and national meetings and seminars which include topics on coating quality and inspection, by which inspectors can gain inspection expertise and knowledge of coating application. Established coating applicators and suppliers of coating materials have testing methods and laboratory equipment for quality control of their production and for product development. Standard test procedures for many elements of coating quality have been developed by ASTM, NACE, API, AWWA, and DIN. Applicators, suppliers, and major pipeline operating companies have their own test procedures and modified standard procedures. The Richmond Materials Laboratory of the Chevron Research and Technology Company is equipped to perform a number of tests to evaluate coatings, and is available to conduct tests on coatings on request. Results of these test procedures are very helpful in evaluating the performance of coating systems and materials for a particular project, but generally these procedures are not applicable for inspection of coating application. This section presents guidelines for inspection of production coatings and girth weld field joint coatings. For descriptions of these coatings see Sections 340 and 350 of this manual, and the Coatings Manual. Coating systems covered here are:
External • • • • •
Fusion-bonded epoxy Extruded plastic film Coal tar enamel Tape Shrink sleeves
Internal • •
Fusion-bonded epoxy Cement-lining
For guidelines on other external and internal coatings consult with nonmetallic and pipeline coating specialists in the CRTC Materials and Equipment Engineering Unit.
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751 Inspection Methods for External Coating Systems Except for over-the-ditch application of tape or enamel coatings, careful coating inspection must be conducted at least two times: • •
When the coating is initially applied When the pipe is lowered into the ditch
The same inspection methods should be used for each inspection. The inspector must have full knowledge of the method of coating application for each coating system. Descriptions of specific application methods are available in the Coatings Manual, in Specification PPL-MS-1800, and in manufacturer’s product literature. Generally, inspection involves all of the following methods: •
Visual inspection of the entire coating surface to detect imperfections and flaws, lack of coverage, damage, etc.
•
Holiday detection utilizing specialized equipment by the applicator’s crew at the plant, and by the pipeline construction crew in the field, and closely monitored by the Company inspector. Holiday detectors are manufactured by Pipeline Inspection Company (SPY), Houston, TX; D. E. Stearns Co., Shreveport, LA; Tinker & Rasor, San Gabriel, CA; and others.
•
Production sample examination using destructive testing by several means described below.
Specifications These specifications are typical of those used for external coating inspection:
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COM-MS-4042, Fusion Bonded Epoxy for External Pipeline Coating.
•
COM-MS-5006, Coal-Tar Enamel Corrosion Coating of Submarine Pipelines.
•
NACE T-10D-10, Proposed Standard, Application Performance and Quality Control of Plant-applied Fusion Bonded Epoxy External Pipe Coating.
•
NACE RP-02 74-74, High Voltage Electrical Inspection of Pipeline Coatings Prior to Installing.
•
NACE T-10D-9C, Proposed Standard, Holiday Detection of Fusion Bonded External Pipeline Coating of 10 to 30 mils.
•
NACE RP-01 85-85, Extruded Polyolefin Resin Coating Systems for Underground or Submerged Pipe.
•
PA-129, Chevron Point Arguello Specification, Extruded Polyethylene Corrosion Coating with Butyl Adhesive. (CRTC Materials Division File No. 6.55.70)
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Shop Quality Assurance •
Fusion bonded epoxy: Refer to Section 6.0 of COM-MS-4042 and Section 9.0 of proposed NACE Standard T-10D-10.
•
Polyethylene: Refer to NACE RP-01 85-85 and Section 6.0 of Chevron Specification PA-129.
•
Coal tar enamel wrap: Refer to Section 8.0 of COM-MS-5006.
•
Shop-applied tapes: Holiday inspection in accordance with NACE RP-027474. The Inspector should inspect visually over 100% of the wrapped area, and include visual lap observation. The inspector should use a window-type patch test of the tape to pipe adhesion. Test frequency should be at the inspector’s discretion. The test is acceptable if the plastic backing peels off leaving a complete adhesive cover on the pipe or if strings of adhesive appear as the tape is peeled back from the pipe and no areas of zero adhesion are encountered. In the event of a failure, additional window tests should be made until acceptable bond is found. All the defective areas shall be cleaned to bare steel and rewrapped.
752 Plant Inspection of Internal FBE Coatings Specifications The Company does not have a specification for internal coating of pipelines with fusion bonded epoxy (FBE). API has a recommended practice, and an Aramco specification is available from CRTC. •
API RP 5L7, Recommended Practice for Unprimed Internal FBE Coating of Line Pipe
•
Aramco 09-AMSS-91, Shop-Applied Internal FBE Coating
Shop Quality Assurance Refer to Section 5.0 of API RP 5L7 and Section 7.0 of 09-AMSS-91.
753 Plant Inspection of Internal Cement Linings Specifications The recommended specifications for cement lining of pipe used for produced water, reinjection water, brine, and salt water service are:
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PPL-MS-1632, Cement-Lined Pipe
•
API RP 10E, Recommended Practice for Application of Cement Lining to Tubular Goods, Handling, Installation, and Joining
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Shop Quality Assurance Follow these sections of API RP 10E for guidance on inspection during shop fabrication: •
Section 4, Inspection and Rejection of Cement-Lined Pipe
•
Section 7, Typical Problems Experienced with Cement-Lined Tubular Goods
754 Field Inspection Methods for External Coatings Specifications •
Fusion Bonded Epoxy: Holiday inspection per NACE Proposed Standard T10D-9C.
•
Polyethylene: Holiday inspection per NACE RP-0274-74
•
Over-the-Ditch Applied Tapes: Field inspection of over-the-ditch applied tapes is essentially the same as for shop-applied tapes.
•
Concrete Weight Coating: Refer to Specification PPL-MS-4807.
Holiday Detection for All Coatings Inspection for holidays should be in accordance with NACE RP-0274-74. The coated pipeline should be 100% inspected with a pulse-type DC holiday detector employing an audible signalling device. Inspection is performed immediately prior to burial, i.e., after the last lowering-in side-boom. The electrode used for locating holidays must be in direct contact with the coating (with no visible gaps) and provide complete coverage of the whole coated surface. All holidays should be repaired and the repairs should all be checked with a holiday detector to verify that they are adequate. This final inspection procedure should be monitored by a Company Inspector. The holiday detector requires an electrical ground. In most cases, this is a flexible bare wire approximately 30 feet long which is attached to the detector and trailed along the ground. Wet or damp ground is best. Dry ground may not complete the circuit; in this case attach the wire to a sideboom tractor. The travel rate of the detector’s electrode should not exceed 1 ft/sec nor should it remain stationary while the power is on. The calibration of the holiday detector should be checked at least twice per 8-hour shift against a calibrated voltmeter and adjusted as necessary. The functional operation of the holiday detector may be checked in the field by making a small artificial holiday in the coating (not more than 1/8 inch in diameter.) If the detector is working properly, it will reliably signal the presence of the artificial holiday. Holidays should be clearly marked with a crayon immediately upon discovery. The Inspector should certify that the defective areas have been repaired prior to burial. The Inspector usually keeps a daily record of the number of coating repairs per joint.
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755 Field Inspection of FBE Coated Field Joints The inspector should check the following details for FBE field joints. If a joint coating fails any of these tests, test adjacent (in both directions) girth weld coatings until acceptable coatings are found. All defective coatings should be completely removed and the areas recoated. At least one of the repaired areas should be reinspected and the subsequent inspection frequency should be as given below. Thickness. Check the thickness on each coated weld joint using an approved, calibrated magnetic dry film thickness gage (e.g., Microtest, Elcometer or equivalent). The instrument should be zeroed before use with calibrated insulating shims of a thickness comparable to the coating film thickness to be measured. A minimum number of six readings should be taken on each field joint coating to verify compliance with the thickness requirement above. The readings should include the weld seam. Cure. On the first five joints of the job and twice each day thereafter, the quality of cure should be checked by maintaining a MEK-soaked pad in contact with the coating surface for 1 minute and then rubbing vigorously for 15 seconds. There should be no softening of the coating or substantial color removal from the coating. Holiday Detection. Perform detection in conjunction with the regular holiday detection for the coating, before lowering into the ditch. Destructive Testing. Using a sharp knife with a narrow flexible blade, make two, approximately 1/2-inch long incisions through to the metal substrate to form an X. Starting at the intersection of the X, attempt to force the coating from the steel substrate with the knife point. Refusal of the coating to peel constitutes a pass. Partial or complete adhesion failure between the coating and the metal substrate constitutes a failure. Cohesive failure caused by voids in the coating leaving a honeycomb structure on the specimen surface also constitutes failure. Perform this test once every hour. When five consecutive tests are successful, the frequency should be reduced to once every 2 hours.
756 Field Inspection of Heat Shrink Sleeves The following inspection methods and acceptance criteria are applicable to all heatshrink sleeve applications. Additional inspection requirements (if any) for specific types of sleeves should be given in the sleeve manufacturer’s recommended installation procedure. Nondestructive Inspection. The shrunk-on sleeves should exhibit the following characteristics:
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Both ends of the sleeves must be bonded around the entire circumference
•
The sleeve should be smooth. There should not be any dimples, bubbles, punctures, burnholes, or any other signs of holidays in the coating or of entrapment of foreign matter in the underlying adhesive
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•
For wrap-around sleeves, the total slippage of the closure patch during application should not exceed 1/2 inch
•
The sleeve should overlap the adjacent mill coating by at least 2 inches on each side
Holiday Detection. Perform detection in conjunction with the regular holiday detection for the coating, before lowering into the ditch. Destructive Inspection. Perform window testing on one sleeve of every 50 installed or twice per shift, whichever is the greater. On each sleeve tested, cut at least one window in each of the overlap area, across the field girth weld, and in the body of the sleeve. There should be no evidence of either voids extending to bare metal (or mill coating) or areas of no adhesion. The girth weld should be completely covered by adhesive. Sleeve application is acceptable if both of the following requirements are met: •
The maximum dimension of any of these defects does not exceed 2 inches
•
At least 95% of the adhesive layer is free of voids and/or lack of adhesion
If the sleeve does not meet the acceptance criteria above, the adjacent sleeves in both directions should be destructively tested until acceptable installations are found.
757 Protection of Coating During Laying To ensure coating integrity, inspection during pipeline laying operations should be a joint effort between the coating inspector, lowering-in inspector, and backfill inspector. They should:
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Inspect the ditch to ensure proper depth and sufficient width so as to provide cover and clearance after lowering-in is complete.
2.
When padding or rockshield are used, ensure that the pipe is placed on the padding or rockshield when lowered into the trench. If rockshield is the encirclement type, ensure that it is correctly installed.
3.
Ensure that all rocks, skids, roots and other damaging material are removed from the ditch.
4.
Ensure that all weld rods are removed from the ditch. They can cause mechanical and corrosion damage.
5.
Ensure that all field joint coating and line pipe is free of holidays or torn material. Witness 100% of final jeeping.
6.
Verify twice daily the calibration, voltage settings, battery charge, correct speed, and grounding of the holiday detector.
7.
Verify that all damaged areas in coating are properly repaired.
8.
Record total footage of pipe jeeped and coating repaired daily.
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9.
Ensure the overall safety of personnel, and suitability of equipment used in the lowering-in and backfill operations.
10. Ensure that mechanical equipment does not damage the pipe during backfilling, and that backfill material has no rocks or hard objects that may damage coating.
760 Completion Testing Completion testing of a pipeline after construction normally involves: • •
A scraper run of a series of pigs propelled by water Hydrostatic pressure testing of the line with water
Procedure Along with the source of water, the most important concern in developing a procedure for testing a long cross-country pipeline is the test pressures for different sections of the line. These depend on design operating pressures, maximum allowable pipe pressures for various wall thicknesses, and ground elevations. A procedure may be incorporated in the construction specification, but is more often developed by the Company field organization in coordination with the construction contractor. The procedure needs to be carefully thought through to achieve an efficient and safe testing program.
Water Supply Because of the large volume of water usually needed to fill the line, the source of water establishes the point from which scrapers are run. Appropriate arrangements must be made for acquisition of water supply. Booster pumps from a river or lake and a temporary line to the pipeline may have to be installed. Often, temporary scraper traps are needed to send and receive the construction completion test pigs. The pressure test pump will normally be located with the pump for the scraper run and line fill, but subsequently may need to be relocated down the line for sections that require higher test pressures. If the flow for scraper run and line fill should be the reverse of the direction of flow for normal operating, attention should be given to check valves that might stop the reverse flow or block the pigs. Water should be free from silt (screened with 200 mesh and filtered if necessary), and noncorrosive and non-scale-forming for the period of time before the line is dewatered and displaced with oil or gas. An oxygen scavenger is not usually warranted, since, once free oxygen in the fill water is consumed by a negligible amount of corrosion of the pipe wall, no further corrosion takes place. However, if water is to be left in the line for a long period, it should be treated with a biocide (such as glutaraldehyde) to prevent growth of anaerobic bacteria, which can produce H2S and cause sulfide cracking of the pipe steel. Biocides are often toxic and arrangements for their use and disposal should be made well in advance. You should consider refilling the line after hydrotesting and injecting the biocide into the second fill to avoid uncontrolled spills should pipe
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failure occur during hydrotesting. Application to environmental authorities for disposal of water containing biocide should be made early in the project. Neutralizing may be required, and testing and modelling may take four to six months before approval is granted. In cold climates, the hydrotest media is often a mixture of water and alcohol (methenol or glycol). The cost of alcohol is significant and sometimes the pipeline contractor or a local supplier will have a premixed supply on hand. Disposal of this mixture must be carefully arranged.
Preliminary Testing Preliminary testing of pipe strings before installation is recommended for sections of line that may not be accessible later, such as major river crossings. Similarly, it may be prudent to test short sections of line immediately after installation in cases where later pipe or weld replacement would be difficult (and much more costly) after the installation crew and equipment have left the site; for instance, at major highway and main line railroad crossings, main irrigation canal crossings, etc.
Contractors Construction contractors may perform testing operations with their own personnel and equipment, or may subcontract to testing specialist contractors. In some cases, the Company has conducted testing with assistance from contractor personnel.
Communications Radio communications should be available during testing, connecting all personnel with a central location, either directly or through relayed message links. A Company engineer who is well acquainted with the testing program and basic hydraulic calculations should be on duty or on call throughout the period of completion testing to initiate or approve modifications to the program and respond to line failures if they occur.
Records Clear and accurate records should be kept of all testing procedures and data. This is required for lines under governmental jurisdiction and also by ANSI/ASME Codes. See Section 830 for guidelines on inservice inspection and testing.
761 Completion Scraper Run The pigs run for the completion test serve to:
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Displace air in the line with water. A line “packed” with water, without air pockets, is needed for reliable hydrotesting.
•
Push construction debris ahead of them out of the line. The pigs will partially clean mill scale, weld spatter, and dirt from the line, as well as larger trash, rocks, etc., that were not removed by spread crews.
•
Check the internal cross-section of the line. A pig equipped with a gaging plate will confirm that the line does not have dents, buckles or excessive ovalling at
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bends. If any such are present, the pig will either be stopped by the deformed pipe, or will arrive at the incoming scraper trap with a severely bent gaging plate. Pumping equipment and water supply for a typical completion scraper run should have a flow capacity corresponding to a velocity of roughly two miles per hour in the pipeline, at a discharge pressure sufficient to overcome hydrostatic head and fluid friction loss plus at least 100 psi to move the pigs. If debris in the line is expected, higher pressure may be needed. A typical sequence of pumping and pigs might be as follows: •
Approximately one-half mile of “wash” water (since dry dirt, dust, and mill scale, even without larger trash, tends to pack and plug the scraper)
•
A three- or four-cup displacement pig
•
Approximately one-half mile of water, or at least 15 minutes’ pumping
•
A second three- or four-cup displacement pig
•
Again, approximately one-half mile of water, or at least 15 minutes’ pumping
•
A three- or four-cup pig with a gaging plate in front of the first cup or in the center of the pig
•
Water to fill the line, unless additional brush scrapers at intervals of at least 15 minutes are used to further clean pipe walls because of service requirements, or additional multicup pigs are considered necessary to displace air pockets in particularly rough (up-and-down) terrain
Gaging Plates The gaging plate diameter should be 93% of the minimum nominal internal diameter of pipe in the particular section of line being tested. The plate should be accurately machined, and the diameter, measured by micrometer calipers, should be stamped on the plate. Three-eighths inch minimum thickness is suggested for a steel plate (one-half inch if aluminum), so that it is not likely to be deformed by a restricted pipe cross-section. The leading edge of the plate should be chamfered. For large-diameter lines a steel reinforcing plate slightly smaller than the gaging plate may be advisable. If after running through the line, the gaging plate is deformed, nicked, or gouged, possible causes should be reviewed and judgment made on accepting the line as satisfactory. A gaging plate may catch on weld “icicles,” small pebbles, or other acceptable irregularities at line appurtenances, as well as unacceptable deformed pipe.
Monitoring Progress While running the pigs, it is strongly recommended that the water volume pumped into the line be metered and pressures at the pump continuously observed at convenient locations down the line. Meter and pressure data versus time should be recorded at a minimum of 15-minute intervals and whenever any sudden rise or
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drop in pressure occurs. A pressure recorder should also be used. These data can be used to analyze the location of the series of pigs should they hang up or plug. Slight, repeated pressure variations are normal, since the pigs often momentarily slow down until pressure builds up behind them, and then speed up. It is also strongly recommended to follow the scrapers, continuously if the terrain allows, or, otherwise, wherever the line is readily accessible. A scraping of the cups inside the pipe can be heard while walking along the line but is likely to be drowned out by vehicle engine noise. Sound-amplifying devices are very helpful, with detector probes set into the ground or directly on the pipe, where accessible, as at intermediate line block valves. A record should be kept of location versus time when following the pigs. The temperatures of the water pumped into the line and of the water that arrives with the pigs in the incoming scraper trap should be recorded; this information is not pertinent to the scraper run, but may be useful in analyzing hydrotest data. All this documentation may seem unnecessary after an uneventful, satisfactory scraper run, but can be vital when trying to analyze locations of suspected bad pipe or stuck pigs. Pigs equipped with sonic transmitters can be detected and precisely located from ground level. Because of cost and logistics they are not often used, but may be warranted in situations where exploratory excavations to locate bad pipe or stuck pigs would be very costly or impractical. On long downhill slopes where pigs with a relatively small amount of water behind them will run away from the line-fill water, an attempt should be made to hold a back-pressure at the incoming scraper trap equivalent to the elevation head behind the pigs.
Water Disposal Arrangements for disposal of water received with the pigs, and later the displaced line-fill water, should be carefully planned, particularly if environmental conditions control disposal into natural drainage. In any case the water received with the pigs should be run to a settling pond to catch mill scale and debris before it is released. When the first displacement pig arrives at the incoming scraper trap, pumping should be stopped until the pig and any debris are removed from the trap. Providing the trap barrel is long enough to hold them, several of the following pigs can be received without stopping flow, since there will be no large debris with them. Should a pig stop at plugged or deformed pipe and have to be cut out of the line, it is usually necessary to repeat that series of pigs from the outgoing scraper trap, unless the plug is near the end of the section tested and little water has been lost and little air has entered the line behind the pigs.
762 Completion Hydrotesting After displacing the air and filling the line with water during the completion scraper run, hydrostatic testing of the line (or section) can proceed. This involves pumping with suitable pressuring pumps to raise line pressure to a specified test pressure,
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blocking the line in to hold pressure, and observing line pressure for a period of time to determine if the line is tight.
Code Requirements Section 437.4 of ANSI/ASME Code B31.4 covers hydrotesting of liquid lines, and requires proof testing of every point in the system to not less than 1.25 times the internal design pressure at that point for not less than 4 hours, followed by a reduced pressure of not less than 1.1 times the internal design pressure for not less than 4 hours. In other words, where lines are designed for maximum design pressures stressing the pipe to 72% of specified minimum yield strength (SMYS), the test pressure produces stresses of 90% of SMYS. API RP 1110, Recommended Practice for Pressure Testing of Liquid Petroleum Pipelines, gives guidelines for hydrotesting procedures and equipment, and a test record and certification form. Section 841.3 of ANSI/ASME Code B31.8 covers testing of gas lines, and requires testing for at least 2 hours to the pressures tabulated in Code B31.8 Table 841.322 (e). Depending on the Location Class the test pressure ranges from 79% to 56% of SMYS if the maximum design pressure is based on design factors 0.72 to 0.40. See Section 443 of this manual. Code B31.8 allows testing with air or gas in Location Class 1 and air in Location Class 2, as well as with water. Code B31.8 has other provisions for special circumstances.
Company Practice Company practice is to test liquid lines to a pressure corresponding to 90% of SMYS regardless of maximum design operating pressure, unless limited to a lower pressure by valve or flange test pressure, and holding for a minimum of 24 hours or as long as needed to determine that there is no unaccounted-for line leakage. Stabilization of water temperature at ground temperatures and absorption of air remaining in the line into the water take some time, usually much longer than the 4-hour Code minimum, and affect the pressure in the line. After these effects have stabilized, pressure will hold constant in a tight line. Occasionally, very slight leakage at a flange, valve packing, or gage connection cannot be corrected, and this loss of water can be related to a continuing loss of line pressure. For gas lines Company practice is to test them hydrostatically with water to at least the Code minimum test pressures and usually higher—up to 90% of SMYS, depending on location, service, and cost of repairs in event of pipe or weld failure. The test period should be a minimum of 24 hours, or as long as needed to determine that there is no unaccounted-for line leakage. For station piping which is mostly aboveground, the shorter test periods allowed by the Codes are satisfactory.
Establishing Hydrotest Pressures The objective in establishing completion hydrotest pressures is to stress as much of the line as is feasible to 90% of SMYS, taking into account the effects of different pipe grades and wall thicknesses, and different ground elevations along the line, as well as expected operating pressures. Where the line is designed for a maximum allowable operating pressure (MAOP) of 72% of SMYS, the line hydrotest pressure
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is rarely limited by valve or flange test pressure (nominally 1.5 times maximum allowable operating pressure for the valve or flange), but this should be checked. For a short line having the same pipe grade and wall thickness for the entire length, in level terrain, the hydrotest pressure P (psi) is readily calculated as follows: P = 0.90 × SMYS × (2t/D) (Eq. 700-1)
where: t = wall thickness, in. D = outside diameter, in. This will be the hydrotest pressure at the pressuring pump discharge, unless limited by valve or flange test pressure. This situation is rarely found on long cross-country pipelines. Rather, pipe is likely to be of several wall thicknesses and, possibly, different grades. Also, ground elevation differentials will produce hydrostatic head differentials. The hydraulic profile can be used to represent hydrostatic pressures along the line at no-flow. The hydrostatic head at any point is the difference between a horizontal line (the test pressure for that section of line) and the ground elevation (see Figure 400-4 in Section 420). For a given pipe grade and wall thickness, the pipe will be most highly stressed at the lowest ground elevation, and less highly stressed at other points along the section. The hydrotest pressure should be the pressure that will stress the pipe at the lowest ground elevation to 90% of SMYS. In some cases, a test pressure higher than 90% of SMYS at the lowest ground elevation may be used, to more closely approach 90% at other locations. In such cases the risk of potential pipe failure (since mill hydrotests were probably to 90% of SMYS) and repair and delay costs should be evaluated by comparing the SMYS value against actual mill test yield strength for the pipe. It is recommended that in no case should 100% of SMYS be exceeded in hydrotesting. In establishing hydrotest pressures for different sections along a cross-country pipeline, it is helpful to include a line on the hydraulic profile representing the calculated head producing 90% of SMYS for each of the pipe grades and wall thicknesses along the line, as well as design hydraulic gradients and pipe MAOP based on 72% of SMYS. Keep in mind that all heads shown on the diagram are in feet of the design fluid, not water. (See Figure 700-17.) For the example in Figure 700-17:
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Section A-B. A is the point where the pipe is stressed to 90% SMYS. Hydrotest pressure is elevation A-B minus elevation PS, in feet of design fluid.
•
Section B-C. B is the point for 90% SMYS. Hydrotest head is elevation B-C minus ground elevation at B. If the section is pressured by a test pump at A, the test pressure at the pump is elevation B-C minus elevation PS, in feet of design fluid.
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Section C-D. The low point downstream of C is the point for 90% SMYS. Hydrotest pressure is elevation C-D minus the elevation at the low point, in feet of design fluid. With the test pump at A, the test pressure at the pump is elevation C-D minus elevation PS, in feet of design fluid.
Sections C-D, B-C, and A-B could be pressured in sequence at their respective hydrotest pressures. However, if the test pump were at a source of water at the low point near C, section C-D could be pressured but the test pump would then have to be moved first to C to test section B-C, then to B to test section A-B, with the test pressures at the pump taking into account the ground elevations at the pump when pressuring the section. The permissible maximum allowable operating pressure (MAOP) for the pipeline is established by the hydrostatic test. For pipelines in liquid service, the MAOP at each point along the line is 1/1.25—or 0.80—times the hydrotest pressure at that point, as indicated for location x on Figure 700-17. A more convenient calculation for the MAOP at location x in psi, established by hydrotest, is given by the following: MAOPat x = 0.80 (Ptest at A - 0.4328 × ∆ Elevation) (Eq. 700-2)
where: Ptest at A = test pressure at location A, psi ∆ Elevation = ground elevation at x minus ground elevation at A, ft Thus, although hydrotest head is represented on the diagram by a horizontal line, a line for the permissible MAOP will be above a horizontal line representing 0.80 times the hydrotest head at the low-point location where the pipe is stressed to 90% of SMYS. This can be significant in establishing maximum pump discharge pressures at station locations or suitability of “telescoped” pipe for pump shutoff conditions. Using the above calculation method, the MAOP established by hydrotest for the pipe may be plotted as shown in Figure 700-18. Taking into account on the coordinate scale for the conversion from feet to psi, the hydrotest pressure line on the diagram is the invert of the ground profile. The pipe MAOP is 0.80 times the value of the hydrotest pressure, and so does not parallel the hydrotest pressure line. Similar calculations and diagrams can be developed for gas pipelines, taking into account the Code design and test factors for the various location classes. Where an allowance has been provided in the pipe wall thickness for corrosion or erosion for pipelines in slurry service, the hydrotest pressure should be calculated to stress the pipe to the same stress as if it did not have the corrosion/erosion allowance. For a line tested at 1.25 times the design maximum allowable operating pressure, the hydrotest pressure would then be as follows: Ptest = 1.25 Pdesign × (tn/tmin) (Eq. 700-3)
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Fig. 700-18 MAOP Established by Hydrotest
where: tn = actual nominal wall thickness of the pipe, in. tmin = pressure design wall thickness, in. (equal to the nominal wall thickness less the corrosion/erosion allowance) This hydrotest pressure should be used as a basis in selecting valve and flange ratings. Valves and flanges having lower test pressure than the pipe hydrotest pressure must be isolated so they are not overpressured. Establishing hydrotest pressures for the line sections—and corresponding pressures for the test pump discharge and for different locations along the line—does not involve complex calculations. It does require a logical analysis of pressures calculated by the hoop stress equation, and a careful accounting for hydrostatic head differentials for the different ground elevations along the line.
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Equipment for Hydrotesting Typical equipment for hydrotesting includes the following: •
Pumping system. The pumping system comprises the following: – –
– •
The water supply system, with a high-volume pump used for the completion scraper run A low-volume, variable-speed, positive-displacement test pump, with known volume per stroke, and a stroke counter. The pump should have a relief valve to protect the pump from overpressuring and a check valve on the pump discharge piping A tank on the suction line to the test pump, suitable for measuring the volume pumped into the line
Instruments – – –
– – –
A Bourdon-tube pressure test gage, calibrated before the test, with a reading accuracy of 0.1% of full scale A deadweight pressure tester, capable of measuring increments of 1.5 psi, certified for accuracy and traceable to the National Bureau of Standards A 24-hour pressure recorder—checked using the deadweight tester immediately before and after use—with a supply of properly ranged chart paper (test pressure should be about 80% of maximum scale) Pressure gages, calibrated before the test, with reading accuracy of 1% of full scale for use at locations along the line where pressures are observed Thermometers for measuring water, ground and air temperatures A 24-hour temperature recorder, with the temperature detector in contact with the pipe at a point where it has normal cover
Typical Hydrotest Sequence With air purged from the line and the line filled with water after a successful completion scraper run, a typical hydrotest sequence is as follows:
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1.
Pressure the line with the high-volume pump used for the completion scraper run line-fill, to the pump shut-off head (but not exceeding about 75% of the test pressure).
2.
Verify that the line pressure recorder and underground pipe temperature recorder are in operation, set at real time.
3.
Pressure the line with the pressure test pump to 70% to 80% of the test pressure. If it is late in the day it is preferable to stop pressuring until the next morning to allow time for water temperatures to stabilize at ground temperatures and to use daylight for final pressuring. However, often the contractor and sometimes the Company want to proceed with testing without any interruption.
4.
Pressure the line gradually with the test pump in increments of about 2.5% of test pressure every ten minutes unless pump capacity is limiting. While pressuring observe and record, at five-minute intervals, (1) pressures, using the deadweight tester and the test gage, (2) volume of water pumped as measured
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in the tank, and (3) pump stroke counter reading. At about 20-minute intervals check the pressure recorder readings against the deadweight pressures to confirm that the recorder is functioning properly. If there should be a sudden drop in pressure, indicating a line break, record the pressure just before the drop and stop pumping. 5.
When the test pressure is reached, stop the test pump. Care must be taken not to exceed the maximum test pressure, particularly for short lines. If the pressure should drop below test pressure within a few minutes and then appear to stabilize, resume pumping to raise the pressure to test pressure again while continuing to observe and record data. Disconnect the pump from the line. Continue observing and recording deadweight pressures at 5-minute intervals for at least an hour, and 15 minutes thereafter until the end of the test.
6.
In the event warm ground temperatures cause the line pressure to increase above the maximum test pressure, water must be bled slowly and carefully from the line to lower the pressure to test pressure. The water should be drained to the tank so that the volume can be accurately measured, using the deadweight tester for pressure data while lowering the line pressure. If line pressure again rises to the maximum, this operation will need to be repeated.
7.
In many cases the line pressure drops after first reaching test pressure, either because the water has cooled to ground temperature or because of air absorption into the water at high pressure. If the drop is due to these effects, the rate of pressure drop will decrease and the pressure will eventually stabilize and hold. If pressure drops appreciably before finally stabilizing, the pressuring pump should be reconnected and the pressure raised to test pressure, again observing and recording data.
8.
If the pressure drop has stabilized and the pressure held steady for at least 4 hours, the test can be considered satisfactory after 24 hours, or after 4 hours of stabilized pressure if this takes longer than 24 hours.
9.
At the end of a satisfactory test in which there are line block valves at the ends of the section under test, the line is depressured until there is a positive pressure of, say, 50 psi at the high point of the section. If it is necessary to make a welded or flanged connection to the next section of line, then the line will have to be drained sufficiently to make the connection.
While pressuring the line and holding pressure, all connections and manifolds in the test section should be closely monitored for leakage and failure. Where feasible work should be done to correct any leakage.
763 Test Procedure and Program A detailed procedure for completion testing should be prepared. This procedure should be carefully reviewed and agreed to by Company field personnel and contractor supervisory personnel involved in the testing. The procedure should include the following elements:
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•
A ground profile for the section of line to be tested, with a diagram showing locations of scraper traps, block valves and check valves, pressure instruments, and temperature instruments
•
A diagram of the pumping and metering system for the scraper run and line fill, from water source to the pipeline connection, including pressuremeasuring instruments, and a list of equipment data. If filtering or treatment of the water is needed, the diagram should include this equipment
•
A list of pigs to be run, gage plate diameter, and volumes of water to be pumped ahead of and between pigs
•
A list of detection devices for following and locating pigs
•
A diagram for the pressure test pump system, from water source to the connection to the pipeline, including equipment for measuring volume of water pumped into the line, pressure-measuring instruments, provision for overpressure relief, and a list of equipment data
•
Maximum and minimum test pressures at the pump and the primary pressure instrumentation
•
Calculated test pressures at other locations along the line
•
Minimum period for holding the line at test pressure
•
Calculation methods for analyzing effects of water temperature change, air volume in the line, and water compression
•
Identification of connections and appurtenances on the line that must be blinded, plugged or disconnected. Mainline valves may be equipped with body relief valves that must be plugged or removed. Hydrotest pressure should not be applied to a closed valve if the pressure differential across the valve exceeds the valve test shutoff pressure
•
Precautions and measures required if ambient or night chill temperature is below freezing
•
Procedures required if daytime temperature and solar radiation effects on exposed pipe or test equipment are likely to cause pressures to increase above the maximum
•
Safety precautions
•
Communications units for Company and contractor
•
Test personnel organizations for Company and contractor
•
Notification of government agencies, where test witnessing is required
•
List of agencies to be notified in event of a water spill resulting from a line rupture
•
Arrangement for aerial inspection service in event of line rupture or leak
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The overall testing program should be described in outline form, with a tentative schedule for the scraper run and pressure testing. This should indicate personnel duties and work schedule for testing crews. Testing usually is done on a 24-hourper-day basis, possibly with a short interval between line fill and pressure testing. A definite hour-by-hour schedule for the program cannot be set, since the rate of pig travel and times to build up to pressure test and hold at test pressure can only be estimated. Allowances must be considered for maintenance of test equipment and possible pipe leaks and repairs.
Example Testing Program An example of a pipeline testing program is given in Figure 700-19. This is the same system for which the hydraulic profile, pipe wall thicknesses, and line appurtenances were shown in Section 430, Figure 400-9. A suitable water supply for scraper runs and line fill is available at two rivers. The pipe strings at these river crossings were hydrotested after installation, but not tied in at the upstream line block valves. A temporary launching scraper trap manifold has been fabricated, and will be reused for each of the four scraper runs. The line block valves at the river crossings will be used to isolate the temporary trap manifold from the line. The sequence of testing is as follows: 1.
Set up the fill and test pump facilities at the river crossing between the initial pump station and the intermediate pump station.
2.
Make the scraper run from the river to the initial pump station. Pack this section with the fill pump.
3.
a. Make the scraper run from the river to the intermediate pump station. Pack this section with the fill pump. b. Concurrently, pressure test line section A at hydrotest head A above the ground elevation at the river.
4.
Pressure test line section B at hydrotest head B (same as A).
5.
After satisfactory tests on sections A and B and depressuring to a head somewhat greater than the ground elevation difference between the river and the intermediate pump station, proceed as follows: a. Tie in the line at the river crossing. b. Move the fill and test pump facilities to the other river crossing, downhill from the ground high point. (“control point”)
6.
Make the scraper run from the river to the intermediate pump station, holding a backpressure on the line at the intermediate pump after the pigs pass the high point. Pack this section with the fill pump.
7.
a. Make the scraper run from the river to the terminal, holding backpressure at the terminal to keep the pigs from running away from the fill water. b. Concurrently, pressure test line section F at hydrotest head F above the ground elevation at the river.
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Fig. 700-19 Hydraulic Profile: Pipeline Testing Program
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8.
Pressure line sections E, D, and C in order to test section C at hydrotest head C above the ground elevation at the river, and close the line block valve between sections D and C.
9.
Pressure line sections E and D in order to test section D at hydrotest head D, and close the line block valve between sections E and D.
10. Pressure test line section E at hydrotest head E. 11. After satisfactory tests on sections C, D, E and F: a. Depressure sections E and F to a head sufficient to maintain a positive pressure at the high point of the route (“control point”). b. Depressure sections C and D to a head sufficient to maintain a positive pressure at all points in these sections. c. Tie in the line at the river crossing. 12. Demobilize and clean up all test sites.
Analysis of Hydrotest Data Several effects must be considered in analyzing data observed while pressure testing: • • • • •
Elastic strain in the pipe due to internal pressure Compressibility of water under pressure Expansion/contraction of steel due to temperature changes Changes in volume/density of water due to temperature changes Absorption of air into water under pressure, and remaining free air
For a pipeline filled with liquid under pressure at constant temperature (disregarding effects of air absorption or free air in the line) the pressure-volume relationship (considering elastic strain in the pipe and compressibility of the water) may be expressed as follows:
(Eq. 700-4)
where: dV = incremental volume in same units as V V = fill volume of the section under test dP = incremental pressure, psi D = outside diameter, in. t = wall thickness, in. E = modulus of elasticity of steel, psi
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= 30 x 106 psi ν = Poisson’s ratio = 0.3 C = Bulk compressibility factor of liquid, per psi (the reciprocal of the bulk modulus). See Figure 700-20. The above equation thus becomes:
(Eq. 700-5)
Approximate values of C for water are shown in Figure 700-20. Fig. 700-20 Compressibility Factor of Water
Temperature changes will cause pressure changes in a tight line. The effect of the thermal expansion (or contraction) of water, offset by the thermal circumferential expansion (or contraction) of the pipe, yields a volume-temperature relationship (for a restrained line) as follows:
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(Eq. 700-6)
where: β = volumetric coefficient of expansion of liquid/°F. See Figure 700-21. α = linear coefficient of expansion of the pipe per °F = 6.5 x 10-6 per °F for steel dT = temperature change, °F From Equations 700-5 and 700-6, a pressure-temperature equation for a tight line is as follows:
(Eq. 700-7)
Values of β for water are given in Figure 700-21. For a long buried pipeline it is not feasible to measure the pipe/water temperatures for the length of the line, and difficult to predict the effect daily ambient temperature variations may have on pipe and water temperature. It is important to allow sufficient time after line fill for water temperatures to equalize with ground temperatures. The time for equalizing will be a function of the differential between the source water temperature and ground temperatures, as well as of the pipe diameter. For a relatively long section of line, the temperature of the fill water reaching the end of the section with the initial scraper run pigs will probably be close to the ground temperature. Thus, an approximate temperature differential between water entering the line and the ground can be estimated and used in judging the time needed for water temperatures to equalize with ground temperatures. Any air remaining in the test section will complicate an analysis of the pressurevolume data obtained in hydrotesting. With increasing pressure, air is absorbed into the water at an indeterminate rate—probably fairly quickly—until the saturation point is reached. Once absorbed the air has no further effect, but any remaining free air behaves as a compressed gas. The volume of this air can be calculated by comparing the actual pressure-volume relationship from the hydrotest data at the test pressure range with the theoretical pressure-volume relationship, as follows. Using test data:
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Fig. 700-21 Volumetric Coefficient of Expansion for Water
∆V = actual volume of water into line between P1 and P2 Then the difference between actual volume change and theoretical volume change is:
(Eq. 700-8)
A calculation for the percentage volume of free air in the test section then is:
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(Eq. 700-9)
where P1 and P2 are absolute pressures, psia. If there is some doubt whether sufficient time has been allowed for air absorption and water-ground temperature equalization, allow some time, then bleed a measured volume of water from the line, record the corresponding drop in pressure, and use these data to calculate the percentage volume of free air. Temperature changes and air in a test section cannot be calculated with great precision, but the calculations given can indicate the range of their effects for purposes of analyzing a very slow drop in pressure. Additional temperature measurements along the line may be warranted. Compressed free air hides the size of a slow leak, and so should not be overlooked if its volume is more than a few percent.
764 Line Rupture and Leakage When the line hydrotest indicates a pipe rupture, (a sudden large drop in pressure) or leakage (a continuing gradual decrease in pressure) prompt action should be taken to locate and repair the failure. In nearly all cases, the failure will be due to defective or damaged pipe rather than a girth weld. Flange or valve packing leakage may also be a cause. Since the line pipe is usually furnished by the Company, costs for the contractor’s crew and equipment to stand by and make repairs due to defective pipe will be charged to the Company’s account, and the Company field organization should act to minimize these costs.
Pipe Rupture In the case of pipe rupture, pressures at the test pump and at available locations along the section under test should be reported as soon as possible. Analysis of hydrostatic heads will pinpoint the location of the rupture, or narrow the length of line in which the rupture must have occurred. For example (referring to Figure 700-19) the location of a pipe rupture that has occurred while testing section B, where the observed hydrostatic head at the test pump at the river crossing corresponds to the ground elevation differential between the river and the future pump station, would be in the vicinity of the future pump station. However, if the terrain is nearly level, line pressures will be essentially zero, and visual inspection along the entire length under test will be necessary to locate the rupture. Unless underwater, a pipe rupture is often easily spotted, as a wet area where the water has drained out and usually by a pit washed out by the sudden release of water.
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Leak Location In the case of gradual loss of pressure, indicating a leak, the line should be repressured to the hydrotest pressure. If there are line block valves within the section under test, they should be closed to isolate shorter sections of line, and pressures observed to determine the section with the leak. Finding a leak (see Figure 700-22) may be difficult and time consuming. The leak may or may not show as a wet spot on the ground, depending on the amount of leakage and nature of the soil. The rate of leakage (volume) should be correlated with the rate of pressure drop. This will give an indication of the amount of water that has leaked out, the rate of leakage as time goes on, and the likelihood of observing it. Sonic detection devices may be helpful in locating the leak (see Section 840). Leaks from small defects in the pipe or weld usually increase with time as the hole is enlarged by the “wire drawing” action of the water at high pressure. On short lines it may be feasible to displace the water with air to which a mercaptan odorizer has been added, and locate the leak by odor. In wet areas or swamp, if a preliminary hydrotest has not been performed on the pipe strings, addition of a biologically acceptable red or yellow dye to the line-fill water may be warranted to help locate a leak. Fig. 700-22 Leak Detection Alternatives Leak Masked By
Detection Method
Frozen ground
Mercaptan (skunk gas)
Open water or swamp
Biodegradable Dye Gas Bubbles Mercaptan
Vegetation
Drive/Walk Line
Any condition
Measure Input Volumes Acoustic Detector Sectionalize, Excavate, Test
Aerial Observation Aerial inspection of the route under test is a good way to quickly search for the location of a rupture or leak. Arrangements for aerial inspection and radio communications between plane and ground should be made in advance of the test so that no time is lost if a rupture or leak occurs.
770 Dewatering and Drying After satisfactory hydrotesting, the pipeline should remain full of water until it is put into operation unless service conditions require displacement, drying or dehydrating before operation. The water fill minimizes corrosion during the period before the line goes into service and facilitates effective and controlled displace-
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ment of the water. However, gas lines may require displacement with nitrogen or drying to prevent hydrate formation. Dehydrating may be necessary to prevent corrosion, as for CO2 service.
771 Dewatering The basic dewatering procedure involves running a series of displacement pigs or spheres propelled by the normal stock in the line, putting the pipeline system into operating readiness. Some important factors to consider are as follows: Disposal of the Displaced Water. Disposal of the displaced volume or water at the intended flow rate should be planned carefully and must be acceptable to environmental authorities. If the volume of water presents a problem at the pipeline terminal, it may be feasible to release some of the water at intermediate points. If treatment chemicals have been added to the water, environmental consequences must be considered, particularly if biocides have been added to the fill water. See Section 760. For Liquid Lines. An adequate inventory of stock should be available to displace the line or sections of line that can be isolated by block valves until another supply of stock can be accumulated and dewatering resumed. While displacing water with oil, the hydraulic profile for a two-stock system should be recognized (see Section 420). For Heated Oil Lines. A procedure must be developed for raising ground temperatures sufficiently to avoid cooling heavy or waxy oil to temperatures that would cause plugging when initially introducing it into the system. This may involve startup with heated light oil or diluted heavy oil, or circulation of hot water. See Section 810 for precautions involving initial warmup of hot lines. For Gas Lines. To displace the water in hilly or mountainous terrain, sufficient pressure must be available to overcome the hydrostatic head of the water. If there are appreciable elevation differences along the line, control of pressure, rate of gas flow into the line, and rate of water released should be carefully planned, with consideration of the expansion of gas when it overcomes hydrostatic head at high points and as fluid friction of the water decreases. If gas pressure is not sufficient to overcome the hydrostatic head, the line must be drained to the extent practical and nitrogen used for further dewatering to avoid explosive gas-air mixtures. In calculating the required pressure and resultant volume of nitrogen needed for displacement, the cumulative effect of the water remaining in undrained low spots along the line must be taken into account. Gas lines operating at pressures at which hydrate formation occurs must be dried or have methanol injected to prevent hydrate formation. See Section 820.
772 Drying and Dehydrating For certain services, removal of remaining quantities or traces of water is required to:
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•
Avoid formation of gas hydrates
•
Minimize corrosive action where the presence of water is the contributing factor
•
Maintain purity of stock, e.g., ethylene, propylene, ammonia
The degree and method of water removal required depend on the particular situation. The usual methods of drying to remove traces of liquid are: •
Purging with available unsaturated gas at pressures below that at which hydrate formation occurs
•
Purging with unsaturated nitrogen or unsaturated air
•
Drying by evacuating air or gas from the line to a high vacuum
Dehydrating reduces the water content in the gas, nitrogen or air considerably below the saturation point—to a few parts per million—so that the gas, nitrogen or air left in the line prior to startup is at the specified level of dehydration. Trailermounted units employing a molecular sieve or chilling process are generally used for dehydration, and a large number of foam displacement pigs are run, using large compressors to propel them through the line over a number of line displacements. Vacuum drying may be suitable for relatively short lines with minimal trapped water. Pipeline Dehydrators, Houston, Texas, and Coulter Services, Houston, Texas, are specialist contractors capable of performing pipeline dehydrating and dewatering.
773 Gelled-Fluid Pigs New technology for using cohesive, highly viscous fluids as pigs (gelled-fluid pigs) has been developed by Dowell Schlumberger, Houston, Texas. These gelled pigs can be used alone or in conjunction with mechanical pigs for cleaning, dewatering, and drying with methanol and nitrogen, as well as for batch separation. A gelled pig was used on the Ninian tie-in in the North Sea, and the industry has used the technology in a number of applications for liquid and gas pipelines.
780 Typical Field Inspection Organization 781 Objectives Although its primary function is to monitor and enforce the technical provisions of the construction specifications, the Company field inspection organization, as part of the construction supervision team, is responsible for achieving the overall project objectives outlined in Section 670. Because construction operations for crosscountry pipelines extend over a considerable distance, individual inspectors and field engineers must act as Company representatives in dealing with landowners, tenants, governmental agencies and the public, in addition to inspecting craft workmanship. They also have a very important role in enforcing Contractor compliance with safe work practices (see Section 810).
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Consistent high-quality workmanship, uniformly monitored by Company inspectors and engineers, is critical on a cross-country pipeline project for the following reasons: •
Once in the ground the line is truly buried—today’s work must be inspected today, not tomorrow
•
Pipeline design provides an adequate, but not generous, safety factor under operating conditions—flaws cannot be tolerated
•
The pipeline is not on Company property—future maintenance access and damages to facilities of others will be costly
•
Consequences of line failures and resultant spills are serious and costly— extent of injury, fire or property damage may be high
•
Governmental and other agencies closely examine construction methods and operation performance, and records—post-construction review of documentation that reveals unacceptable work or faulty records can require immensely expensive corrective work; (e.g., radiographs showing welding defects that were not repaired)
782 Selection of Field Inspection Personnel Selection of the field inspection personnel should be based on the following strengths: •
Technical proficiency
•
Reliability and motivation
•
Confidence in making well-founded decisions
•
Ability to work well with the Company field supervision team, the Contractor’s supervisory personnel, and the public
Pipeline construction inspectors should be fully qualified in the craft they inspect. Where technical competence is required, they should be completely familiar with construction techniques and code requirements, and preferably certified by national technical organizations. For example, welding and tie-in inspectors should hold current American Welding Society (AWS) CW-1 certification to API Standard 1104 or to ANSI/ASME Codes; the backfill inspector should be knowledgeable in soil compaction techniques and testing. High motivation and a proprietary attitude toward the project and the Company are important qualities, but are no substitute for formal training and experience. Because of the linear nature of pipeline construction every task is on the critical path. A pipeline construction job is not the place to provide training for inspection skills for a craft in which a man is not qualified.
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783 Inspection Functions and Staffing Inspection functions for pipeline construction are outlined in Appendix E, Field Inspection Guidelines, which were prepared for a 1987-89 Chevron Pipe Line Company project. Normally, an individual inspector or field engineer would be responsible for the combined functions of several of the separate “inspector” procedures in Appendix E. The circumstances for a particular pipeline construction project will naturally influence the makeup of the field supervision staff and inspection organization and thus determine the appropriate number of inspectors and field engineers. The following should be considered: •
Number of construction spreads for the project
•
Length of line, or segment for each spread, and expected length from front-end to cleanup-end activities for each spread
•
Extent of developed areas and surface or underground congestion along the route
•
Expected rate of construction progress for each spread
•
Unusual aspects of construction: materials, terrain, climate, remote location
•
Conditions of permit and right-of-way requirements that affect construction methods and reporting
•
Experience and known capabilities of candidates for inspectors and field engineers
For a short line on properties with few natural obstructions or special permit/rightof-way conditions, construction inspection can well be covered by one field engineer and one inspector, one of whom should have welding inspection expertise. For a section of line in a very congested area, requiring a compact spread and close contacts with agencies and owners, the inspection organization might consist of one field engineer and three inspectors, at least one with welding inspection expertise. A front-end inspector would cover excavation activities, particularly at crossings of roads, streets and existing buried lines, and stringing and bending. A pipeline inspector would cover line-up, welding, coating, and lowering-in. A tie-in and cleanup inspector would cover back-end work. The field engineer would probably devote his attention to contacts with agencies and owners, with less time for inspection. For a cross-country spread in open country, agricultural lands, and intermediatedensity developed areas, a typical inspection organization might be:
Chevron Corporation
•
A front-end field engineer, covering general activities of the first half of the spread, including survey, receipt and storage stockpiling of pipe, and doublejointing yard and/or field coating yard if set up
•
A front-end inspector, covering temporary fencing, clearing and grading, excavation, padding, and stringing
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•
A line-up and welding inspector, with welding inspection expertise, covering bending, line-up and welding
•
A coating and lowering-in inspector, covering coating, lowering-in, shading, and backfill
•
A tie-in inspector, with welding inspection expertise, covering tie-ins, cathodic protection test stations, and crossings
•
A back-end field engineer, covering general activities of the last half of the spread, including crossings, grade restoration, cleanup and revegetation
•
If a double-jointing yard is set up, a double-jointing inspector, with welding inspection expertise, supported by full radiographic inspection services. If a field coating yard is setup, a coating inspector. If both double-jointing and field coating yards are set up and are at the same location, one qualified inspector may be able to cover both
As mentioned in the discussion on the field supervision organization in Section 670, the Company field inspection organization outlined in the above paragraph would be supported by a construction manager or spread engineer, a permit/right-of-way agent, and the construction office or home office accounting and clerical staff. Inspectors would have vehicles suitable for the terrain and twoway radios. The work schedule for the field inspectors and engineers must correspond to the contractor’s working hours. This nearly always requires an extended work day and work week schedule, with occasional 7-day weeks for a portion of the inspection group. Usually, completion testing is done after most spread activity is complete, so the inspection group can be assigned to cover the round-the-clock monitoring of completion testing. However, if full-spread work is proceeding while completed line sections are being tested, arrangements should be made to supplement the inspection team with additional personnel to provide Company coverage of completion testing without affecting spread inspection. Resources for staffing the inspection organization are Company-wide maintenance and inspection organizations, and inspection services contractors; see the discussion of construction and construction service contracts in Section 680.
784 Inspection Reports A number of typical inspection audit report forms are included in Appendix E, Field Inspection Guidelines. Clear and concise reporting of technical and progress data is important. Also, factual accounts of working conditions, industrial injuries, discussions with contractor personnel, landowners of crossed facilities, etc., should be kept in diary form by each member of the field engineering inspection team. Diaries should be in a bound notebook with numbered pages, in ink, and dates and line station locations should be accurately noted.
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790 References Note
Consult the latest edition of each reference for information.
General 1.
Welding Inspection, American Welding Society. New York.
2.
Guide for the Nondestructive Inspection of Welds, American Welding Society, AWS B1.10. New York.
3.
API Recommended Practice 5L8 for Field Inspection of New Line Pipe.
Visual Inspection 4.
ANSI/ASME Boiler and Pressure Vessel Code, Section V, Article 9. New York.
5.
ANSI/ASME B31.4., Liquid Petroleum Transportation Piping Systems, New York.
6.
ANSI/ASME B31.8., Gas Transmission and Distribution Piping, New York.
7.
API STD. 1104, Standard for Welding Pipelines and Related Facilities, Washington, D.C.
Magnetic Particle Inspection Annual Book of ASTM Standards, Volume 03.03 - Nondestructive Testing (Reference No. 8 and No. 9): 8.
ASTM E-709, Standard Guide for Magnetic Particle Inspection.
9.
ASTM E-1316; Standard Terminology for Nondestructive Examinations, Section G: Magnetic Particle Examination.
10. ANSI/ASME Boiler and Pressure Vessel Code, Section V, Article 7. New York. 11. ANSI/ASME B31.4, Liquid Petroleum Transportation Piping Systems, New York. 12. ANSI/ASME B31.8, Gas Transmission and Distribution Piping, New York.
Radiographic Inspection Annual Book of ASTM Standards, Volume 03.03 - Nondestructive Testing (Reference No. 13 - 17): 13. ASTM E-94, Standard Guide for Radiographic Testing. 14. ASTM E-142, Standard Method for Controlling Quality of Radiographic Testing. 15. ASTM E-390, Standard Reference Radiographs for Steel Fusion Welds. 16. ASTM E-1316, Standard Terminology for Nondestructive Examinations, Section D, Gamma- and X-Radiology.
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17. ASTM E-242, Standard Reference Radiographs for Appearances of Radiographic Images as Certain Parameters are Changed. 18. ANSI/ASME Boiler and Pressure Vessel Code, Section V, Article 2. New York. 19. See reference 5. 20. See reference 7.
Ultrasonic Inspection Annual Book of ASTM Standards, Volume 03.03 - Nondestructive Testing (Reference No. 21 - 24): 21. ASTM E-164, Standard Practice for Ultrasonic Contact Examination of Weldments. 22. ASTM E-1316, Standard Terminology for Nondestructive Examinations, Section I, Ultrasonic Examination. 23. ASTM E-213, Standard Practice for Ultrasonic Examination of Metal Pipe and Tubing. 24. ASTM E-587, Standard Practice for Ultrasonic Angle-Beam Examination by the Contact Method. 25. ANSI/ASME Boiler and Pressure Vessel Code, Section V, Articles 4 and 5. New York.
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800 Operations and Maintenance Abstract This section discusses several topics related to pipeline operations and maintenance. It is not a comprehensive description of the organization and procedures for operating and maintaining a pipeline system.
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Contents
Page
810
Safety
800-2
811
Regulations and Codes
812
Spill Contingency Plan
813
Damage to the Line
814
Hot Lines
820
Gas Hydrates
821
Hydrate Prediction
822
Hydrate Prevention
823
Hydrate Removal
824
Hydrates Bibliography
830
In-Service Inspection and Testing
831
Electronic Inspection Pigs
832
Corrosion Coupons
833
Hydrostatic Testing
834
Coating Quality
840
Leak Detection by Physical Methods
800-11
850
Hot Tapping
800-12
860
Repairs, Welding Sleeves
800-13
870
Maintenance Program in Areas of Unstable Soils or Earthquakes 800-19
880
In-Service Line Lowering
800-20
890
References
800-21
800-4
800-1
800-9
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810 Safety 811 Regulations and Codes Title 49, Code of Federal Regulations (CFR) Parts 191, 192, and 195 and ANSI/ASME Codes B31.4 and B31.8 have subparts or chapters devoted to pipeline operating and maintenance procedures and records. Broadly, these require: written plans for normal and emergency procedures, periodic updating of procedures, operation in compliance with procedures, records, training of personnel, and education of authorities and the public regarding hazards and emergency action programs. State regulations may have further requirements. These are generally described and are minimum standards. Examples of written plans for normal and emergency pipeline procedures can be obtained from the Operations Section of Chevron Pipe Line Company. Appendix D includes: •
Pipeline Operating Procedures—Abnormal and Emergency Situations, Standard No. 4.2 of Chevron Pipe Line Company, New Orleans Division; 7-24-87.
•
Table of Contents and general section of Operation and Maintenance Plan— Guidelines for DOT-regulated Gas Pipelines, CUSA Eastern Region; 11-85.
812 Spill Contingency Plan Governmental regulations and permit conditions require preparation of written plans and procedures for dealing with accidental spills from liquid pipelines. A comprehensive spill contingency plan must be included with the pipeline operating and maintenance procedures. The contingency plan and procedures should comply with 33 CFR 153, Navigable Waters, and 40 CFR 112, Protection of the Environment. A spill contingency plan needs to consider a wide variety of factors: •
Geographical elements—topography, surface conditions, soil type, drainage pattern, accessibility, etc.
•
Environmental conditions—weather, hydrology, rare and endangered species, developed areas
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Pipeline system elements—pumping rates and controls, line draindown volumes, block valve locations, and closing response times
The response procedures for each major surface drainage pattern area incorporated in the plan need to cover:
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Organization of the spill response team—Company personnel plus local officials and contractors as appropriate
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Procedure to locate and assess the spill and initiate control and cleanup procedures
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Notification of government and local authorities and public relations information
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Procedure to control or limit the amount spilled, evaluating threats to public safety and sensitive areas
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Procedure to clean up contaminated ground, shorelines, and water surfaces, and restoration
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Availability and location of equipment, materials, and labor crews needed for all response actions
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Documentation of the spill incident, response, cleanup, and restoration
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Training plan and safety coordination
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Procedure for handling damage claims
For consultation on preparation of spill contingency plans, contact Chevron Pipe Line Company or a Company Health, Environment, and Loss Prevention representative.
813 Damage to the Line Risk of damage to a pipeline by activities of others can be minimized by: •
Surface markers, identifying the location of the line and giving information regarding the proper Company contact to notify before proceeding with work
•
Frequent surveillance of the route, on the ground and by air, to observe activities by others and changes in ground conditions—new construction, maintenance work, agricultural cultivation and grading, canal maintenance, erosion, land slips and slides, etc.—over or near the pipeline or progressing toward the line from another area
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Participation with Underground Service Alert Center or equivalent agency established to coordinate notifications regarding work on underground facilities
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Regular contacts with owners, authorities and contractors regularly working in the vicinity of the line to learn about planned and forthcoming construction that might jeopardize the pipeline
814 Hot Lines Lines that carry hot fluids and are designed as restrained lines to limit expansion movements should be closely monitored at bends along the route to detect unexpected expansion problems. This is particularly critical at the initial warm-up of a new pipeline in hot service, whether from a wellhead, compressor station, or heatedoil heating station, because pipe-soil friction values may not have developed to values used in design calculations. Also, warm-up and cool-down cycles over a period of time may result in progressive movement of the buried line toward the surface of the ground, reducing the effect of cover over the pipe. All overbends,
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tight sidebends, sidebends with large angles of deflections, and buried-to-aboveground transitions should be inspected. Temperatures of fluids entering the pipeline should not exceed the design maximum, in order to avoid risk of severe consequences of coating damage, pipe buckling in compression, and "popping" out of the ground due to insufficient restraint by the soil.
820 Gas Hydrates Gas hydrates are very complex, solid crystalline compounds formed when hydrocarbon gases containing water are cooled. Hydrates can form at temperatures well above the freezing point of water. Hydrate formation is a function of gas composition, water content, temperature, and pressure. In general, higher water content, higher pressure, and lower temperature promote hydrate formation. Gas hydrates appear like ice or closely packed snow. The crystals will accumulate on the walls of pipe, especially at elbows and orifices and other restrictions. Hydrate plugs are as strong as ice plugs and more difficult to remove since they require higher temperatures to melt.
821 Hydrate Prediction The engineer must be able to predict hydrate formation. Hydrates must be considered whenever one is handling hydrocarbon gases containing water. Hydrates may be a problem in the following situations. • • •
High-pressure gas lines where the gas is cooled in transit Valves or other throttling devices that cool gas by expansion High-pressure process lines
In these and many other instances, it is important that the engineer be able to predict the hydrate formation temperature in order to: •
Determine whether special precautions are necessary to prevent hydrates
•
Determine whether installation of a gas dehydrator or gas heater, insulation of lines and equipment, or other plant modifications represent the economical way of preventing hydrates
•
Prepare specifications for heaters, dehydrators, and other special equipment required
Charts are available that allow the prediction of hydrate formation based on gas composition, pressure, temperature and water content. The reader should refer to the references at the end of this section or to the Engineering Data Book, Volume 2, Gas Processors Suppliers Association (GPSA), for more complete information and charts. The solubility of water in various hydrocarbon liquids varies substantially, and the effects of composition increase with pressure. High gravity gases are less linear in
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their solubility behavior. When the gas contains more than about 5% CO2 and/or H2S, one should correct for the acid gas components, especially above 700 psia. Figure 800-1 shows one correlation for lean, sweet natural gases containing more than 70% methane and small amounts of heavy ends. This figure has been widely used for gas dehydrator design and is adequate for most first approximations. In the figure, hydrates will probably form for conditions below and to the left of the hydrate formation line. For systems that are more complicated, a more rigorous treatment should be performed. The methods in the GPSA Data Book offer correction factors for most deviations from normal. However, for best results, a gas compositional modelling computer program, such as PPROP (available on the VM System), should be used. Hydrates most commonly form when wet gas is expanded. Figures 800-2 to 800-7 correlate gas gravity with permissible gas expansion without forming hydrates. Like Figure 800-1 they are first approximations only.
822 Hydrate Prevention Because water is necessary to form hydrates, prevention of hydrates is most effectively accomplished by removing the free water. This may be done in two ways: • •
dehydration inhibition
Dehydration is generally preferable because it removes the water from the gas stream. The higher capital cost must be weighed against the continuous cost of inhibition chemicals. Inhibition is usually accomplished by injection of methanol or a glycol into the gas stream to preferentially absorb the water. Methanol is expensive but effective and preferred at cryogenic conditions. Ethylene glycol is less expensive and more easily recoverable, except at low temperatures where its viscosity is very high. It is also less soluble in the liquid hydrocarbons that tend to occur in producing field gas systems. Diethylene and triethylene glycol can also be used. The glycols can be recovered and regenerated for reuse. Inhibitors are injected into gas lines easily with low cost equipment. However to be effective the inhibitor must be present at every point where the gas is cooled to its hydrate temperature. The minimum inhibitor concentration necessary to prevent freezing in the free water phase is given by the Hammerschmidt equation:
(Eq. 800-1)
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Fig. 800-1
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Water Content of Hydrocarbon Gas
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Fig. 800-2
Pressure-Temperature Curves for Predicting Hydrate Formation
Fig. 800-3
Permissible Expansion of a 0.6 Gravity Natural Gas without Hydrate Formation
Fig. 800-4
Permissible Expansion of a 0.7 Gravity Natural Gas without Hydrate Formation
Fig. 800-5
Permissible Expansion of a 0.8 Gravity Natural Gas without Hydrate Formation
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Fig. 800-6
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Permissible Expansion of a 0.9 Gravity Natural Gas without Hydrate Formation
Fig. 800-7
Permissible Expansion of a 0.1 Gravity Natural Gas without Hydrate Formation
where: d = difference between gas hydrate temperature and system temperature, °F KH = 4000 for glycols = 2335 for methanol I = inhibitor ratio, lbm/MMSCF MW = molecular weight of inhibitor The total quantity of inhibitor injected must also be sufficient to inhibit the vapor phase and provide for the solubility of the inhibitor in any liquid hydrocarbons. Significant quantities of methanol will vaporize while glycol will not. The total quantity of inhibitor needed in the vapor phase may be three times that needed for the water phase.
823 Hydrate Removal Once formed, hydrates are often very difficult to remove. Hydrates in above ground piping usually can be heated easily. Torches are quick and effective but cannot be used in hazardous areas. Steam, glycol, or electric tracing are slower but safe, if available. Directly applied steam may be available. Even an induction heating coil may be desirable.
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Hydrates that form in pipelines must be treated carefully. Because pressure helps form hydrates, depressuring the pipeline will often let the hydrate sublime. This is the simplest method for lines that can be taken out of service. When service must be maintained, large amounts of inhibitor (methanol is preferred for this) may be injected. Sometimes the application of increased pressure will loosen and blow out the hydrates. One must be careful not to exceed the maximum allowable operating pressure (MAOP) of the pipeline. For problem blockages in short gathering lines, try depressuring and circulation with hot oil to heat the hydrate and the pipe. Pressure is often applied in conjunction with the hot oil. Again, be careful not to exceed the MAOP or maximum temperature of the pipeline or its coating. In extreme cases, the only solution is to sectionalize the pipeline by hot-tapping to locate and remove the hydrate plug.
824 Hydrates Bibliography The following published reports are available on the subject of hydrates: 1.
Gas Hydrates and Their Relation to the Operation of Natural-Gas Pipe Lines— United States Department of Interior, Bureau of Mines, Monograph 8.
2.
Natural Gas Hydrates—Technical Data Book, Hydrocarbon Research, Inc., Curves E-16.300 to E-16.304, inclusive.
3.
Donald L. Katz, Prediction of Conditions for Hydrate Formation in Natural Gases, (Technical Publication No. 1748 of the American Institute of Mining and Metallurgical Engineers). Petroleum Technology. June 1944.
4.
Pryor, Arthur W. Memorandum on the subject Study of Possible Hydrate Formation at McDonald Island Pipe Line No. 2 Control Station. November 8, 1949.
5.
Ingersoll, W. L. Memorandum on the subject Use of Alcohol to Prevent Hydrate Formation. March 9, 1950. Memorandum.
830 In-Service Inspection and Testing In-service inspection and testing are prudent measures to verify the integrity of an operating pipeline system over the years. These include: • • • • •
Wall thickness inspection by electronic inspection pigs Corrosion coupons inspections Hydrostatic testing Coating quality inspection Cathodic protection surveys
The Department of Transportation requires that the operator of a pipeline system prepare an operations and maintenance plan (see 49 CFR 195.402 and 192.605),
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but specific inspection and testing measures and frequency are not defined. Each pipeline operating organization should therefore develop a program suitable for its particular facility. Other than where federal or state regulations mandate specific inspection and testing intervals, the program must be tailored to the individual pipeline system. Consultation with Chevron Pipe Line Company is suggested for guidelines on in-service inspection and testing.
831 Electronic Inspection Pigs Provision for running electronic inspection pigs should be incorporated in the design for the line (see Section 453 of this manual). The Linalog Tool of Tuboscope, Houston, TX, and the Vetcolog pig of Vetco Services, Houston, TX, are widely used; both employ the magnetic flux principle. Others are available (see Section 453 of this manual). If the line design did not originally consider running an inspection pig, the data specified in Section 453 should be sent to the inspection service company to evaluate the suitability or limitations in running the inspection pig. Satisfactory functioning of the inspection pig is also influenced by line operating temperatures, speed of travel, and internal condition of the pipeline section being inspected. The duration of exposure to high temperatures may be critical. A means of determining the location of the pig along the line is important; magnetic markers or electromagnetic coil transmitters may be needed. Normally, a dummy inspection pig is first run to assure satisfactory passage of the instrumented pig through the line.
832 Corrosion Coupons For corrosive fluids, for which a specific corrosion allowance has been provided in determining the pipe wall thickness, it may be advisable to install corrosion coupons at points in the system representative of flow conditions and where they can be isolated and removed. These would normally be in the station or terminal piping or on flowing branch lines, rather than on the main pipeline. Where the piping must be kept in operation while removing or replacing coupons, a valved bypass can be provided. If necessary to install a coupon in the main line, devices are available for withdrawing and re-inserting the coupon with the line in service. The Materials and Engineering Analysis Division of the Engineering Technology Department can be consulted regarding the need and type of coupon and method for placing it in the flowing stream. Also see the Corrosion Manual for a description of devices for installing corrosion coupons.
833 Hydrostatic Testing Two types of pressure testing of operating liquid lines are: •
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Testing after displacing lines with water at hydrotest pressures at 1.25 times the maximum allowable operating pressure.
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Line pack or standup testing with the fluid normally handled after isolating the section, at a pressure not exceeding the maximum operating pressure
The maximum allowable operating pressure should be determined taking into consideration actual normal and abnormal operating pressures, limitations by design codes for pipe grades and wall thickness, and limitations by valves, flanges or other line appurtenances. Operating demands usually limit the time available for testing. Therefore, the test procedure must be well planned, giving consideration to all aspects and contingencies. All needed facilities, including communications, should be ready, as well as materials and construction equipment in event of a leak or a break. When testing in wet weather or wet areas, consideration of using a water-soluble dye in the test water may be warranted for identifying leak locations. Disposal of displacement water must be arranged to comply with environmental restrictions. Lines that have been idle for over 3 months and up to a year should have a satisfactory standup test before returning to service. A line that has been idle for a year or more should be hydrostatically tested with water to 1.25 times the maximum operating pressure before returning to service. Guidelines for testing operating pipelines are available from Chevron Pipe Line Company. These guidelines recommend that lines tested periodically be held at test pressure for at least 4 hours. Also see Section 770 for discussion of completion testing of new pipelines.
834 Coating Quality Overall quality of pipe coating to effectively protect the pipe from corrosion is indicated by cathodic protection surveys at frequent intervals and by monitoring the current from rectifiers needed to maintain cathodic protection on the pipeline. If areas of severe coating failures and defects are suspected, coating holidays can be located with equipment such as the Pearson null-method detector manufactured by Tinker & Rasor, San Gabriel, CA, providing the pipe is buried in relatively moist soil conditions. The Pipe-CAMP PCS-2000 equipment recently developed and used in Australia is claimed to have greater sensitivity and ability to detect defects in dry and rocky soil and under pavement; it is available through US agents, such as Farwest Corrosion Control, Gardena, CA.
840 Leak Detection by Physical Methods SCADA leak detection systems will trigger the need for corrective action or repairs and may indicate the general area of the suspected leak. To precisely locate a pipeline leak, however, on-the-ground detection methods must be used. These include:
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Visual observation by air or on the ground for evidence of line stock or effect on vegetation
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Combustible gas detectors
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Injection of odorants into gas and odor detectors
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Sonic instrumentation
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Pressure-wavefront instrumentation
Heath Consultants, Stoughton, MA; Goldak, Glendale, CA, and Metrotech, Mountain View, CA, offer instruments and equipment for leak detection. Information on leak detection for gas lines is presented in ANSI/ASME Code B31.8, Appendix M, Gas Leakage Control Criteria. Appendix M relates to gas distribution piping, not transmission pipe lines, so that judgment should be used in considering the action criteria outlined in Section 5 of Appendix M.
850 Hot Tapping Hot tapping of pipelines is similar to both hot tapping of process piping and pipeline sleeve repair welding. For more details on hot tapping equipment and procedures see Section 500 of the Piping Manual. The Piping Manual includes a checklist of the questions to be asked and preparations to make before preforming a hot tap.
Wall Thickness Pipelines with a wall thickness of 0.188 inch and above can be hot tapped with low hydrogen electrodes without risk of burn through. Thinner wall thicknesses require special procedures. See Section 500 of the Piping Manual. Wall thickness at the point of hot tap should be checked by ultrasonic testing.
Welding Procedure Low Hydrogen Electrodes. Only welding procedures and welders qualified with low hydrogen electrodes (vertical up) should be used for hot taps and repair welds on live pipelines. Low hydrogen electrodes have both a lower risk of burning through and of weld cracking. Welding Electrode Selection. For high strength pipe, the electrode strength must be selected to match the pipe strength.
Pipe Grade Special welding considerations are not required for the high strength X grades (X56 and above). These grades of steel have chemistries that are designed to be very weldable. A weld rod with sufficient strength should be selected for these grades.
Inspection Preweld Inspection. Prior to hot tapping, the wall thickness at the proposed hot tap location should be checked with an ultrasonic thickness gauge. Postweld Inspection. Following completion of the hot tap welding, a visual inspection and magnetic particle inspection of the attachment welds should be done.
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Inspection methods and procedures are explained in Section 700 of this manual.
860 Repairs, Welding Sleeves Special Repair Fittings The various Plidco fittings described in Section 365 are useful in maintenance repairs to damaged or corroded pipe, particularly Plidco Weld & Ends couplings. A pair of these fittings with a length of replacement line pipe can be used to quickly repair a leak or install a prefabricated line valve or branch assembly, without requiring any "hot work" until the line is back in service. The section of pipe containing the leak, or at the location of the new prefabricated assembly, is removed by "cold-cutting," taking proper action to control drainage from the line. Before making a cut, the bonding cable should be clamped to the line to electrically bond across the gap. A Weld & Ends coupling is then slipped over each exposed end of the line; the replacement pipe section is positioned to fill the gap; the couplings are then centered on the joints and the clamping and thrust screws tightened to seal the connections. See Figure 800-8. Fig. 800-8
Repair with Weld and Ends
Also useful are Stopple fittings, used with sandwich valves and Stopple plugging machines, such as furnished by T. D. Williamson, Tulsa, Oklahoma. These are installed before cutting out a sectional pipe and will plug the line to avoid draining the line. T. D. Williamson’s Lock-O-Ring flanges can be provided on the Stopple fittings and for flanges on hot-tapped tees for temporary by-pass lines so that LockO-Ring plugs can be inserted after line modifications are made, so that it is not necessary to leave branch valves on the line. Refer to T. D. Williamson catalog for details of use and installation.
Split Welding Sleeves Many of the considerations applicable to hot tapping discussed in Section 850 also apply to pipeline repairs that are made using full encirclement sleeves. When pipeline repairs are required because of corrosion, defects, or damage to the pipe, the Company preference is to replace the section of pipe requiring repair. This generally entails cutting out the affected section and installing a new piece of pipe (pup). The circumferential welds to install the pup piece are straightforward pipeline welds that can be inspected by standard radiographic practices and the pipeline can
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be returned to service in good condition. This practice requires shutting down the pipeline; when schedule considerations make this impractical, other repair methods have to be employed, such as Plidco sleeves or full encirclement welded sleeves. Full encirclement sleeves are recommended for repairs because, when properly installed, they are load bearing, and Type B sleeves (fillet welded ends—see Figure 800-9) are pressure retaining for through-wall defects. The practice of using partial sleeves (half soles) is restricted by the codes to lower strength, older materials and has generally been discontinued because of the stress intensification along the longitudinal fillet welds and the greater risk of failure if a surface defect such as undercut or toe crack has been left. Fig. 800-9
Type of Sleeves Evaluated
Another application of full encirclement sleeves has been for the attachment of anode leads when greater than a No. 15 Cadweld charge is required because of the risk of copper contamination and cracking on the surface of the pipe. Direct attachment of the anode leads to the pipe has been permitted for Cadwelds using a No. 15 or smaller charge. Because full encirclement sleeves are generally used to repair pipelines that cannot be taken out of service, their use must be given the same considerations as required for hot tapping. These are:
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Stability of the product in the pipeline during welding and risk of explosive reaction (e.g., spontaneous decomposition of ethylene)
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Minimum thickness to avoid burnthrough (0.188 inch)
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Reducing the operating pressure (generally to two-thirds or less) during repair for personnel safety and to allow the sleeve to share hoop stress at operating pressure. This is frequently not possible with liquids that convert into a vapor at lower pressures (e.g., liquid petroleum gas and carbon dioxide)
•
Risk of hydrogen cracking in the heat-affected zone for sour service operating conditions
Welding Procedures API RP 1107 covers Recommended Pipe Line Maintenance Welding Practices for qualification of welding procedures and welders for full encirclement sleeves. Welding procedures qualified to API RP 1107 are valid within the range of essential variables of their qualification. The test assembly for procedure qualification is shown in Figure 800-10. Changes in essential variables requiring requalification are: Fig. 800-10 Procedure Qualification Test Assembly for Position 6G
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Change in welding process
•
Change in pipe, fitting, and repair materials. Materials are grouped into three categories: a.
SMYS of 42 ksi or less
b.
SMYS of more than 42 ksi but less than 65 ksi
c.
SMYS of more than 65 ksi (each grade requires separate qualification)
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Change in joint design
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Change in position, except qualification in the 6G positions (45 degrees from horizontal) qualifies for all positions
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Change in material thickness group: a.
Less than 3/16 inch
b.
3/16 inch to 3/4 inch inclusive
c.
Over 3/4 inch
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Change in filler metal or shielding (change from cellulosic to low hydrogen or more than one electrode size)
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Change in direction of welding (vertical uphill versus vertical downhill)
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Change in travel speed range or time lapse between passes
Welder Qualification Welder qualification requirements for pipeline welding are discussed in Section 750. The multiple qualification test does not qualify for sleeve welding performed with low hydrogen (E7018) electrodes as recommended later on in this section. The use of low hydrogen electrodes requires a separate welder qualification test (a separate welding procedure qualification test is also required) which consists of welding with the pipe and sleeve positioned 45 degrees from the horizontal (see Figure 800-11). Essential variables requiring requalification are: •
Change in process
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Change in direction of welding (vertical uphill versus vertical downhill)
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Change from cellulosic to low hydrogen electrodes
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Change in diameter group except qualification on NPS 12 pipe qualifies for all pipe diameters
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Change in nominal wall thickness group (same as procedure)
Sleeve Design Several options exist regarding the design of full encirclement sleeves. Choices exist for the welding of the ends of the sleeves and the joint design of the longitudinal seams (see Types A and B sleeves in Figure 800-9)[1]. Sleeves with the
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Fig. 800-11 Welder Qualification Test Assembly
ends not welded are referred to as Type A sleeves. Type B sleeves have welded ends. Longitudinal seams are either butt welded or lap welded using a butt strap. The Company practice is to weld the ends (Type B sleeve) in order to retain pressure and prevent corrosion in the crevice between the sleeve and the pipe. The use of lap-welded joints is not recommended because tests [1] have shown them to be inferior to butt-welded sleeves. The joint preparation for the butt welds in the sleeve should be beveled and have a gap sufficient to be able to obtain a full penetration weld. Full penetration sleeve welds will penetrate into the carrier pipe. In cases where local wall thinning causes the wall thickness under the sleeve welds to be less than 0.188 inch, a thin mild steel backing strip (1/16 inch) should be used to help prevent burnthrough. These should be slipped underneath the sleeve as shown in Figure 800-12. Backing strip material should be weldable and compatible with the pipeline material. Materials other than mild steel should not be used. In all cases, a sleeve should be fit as tightly as possible against the pipe in order to provide structural strength. Sleeve thickness should provide sufficient strength to at least match the line pipe strength or system flange rating pressure, whichever is limiting. Where line pipe is limiting, sleeve thickness can be calculated as follows:
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Fig. 800-12 Longitudinal Sleeve Weld with Backup Strip
(Eq. 800-2)
where: Ts = minimum sleeve thickness, in. Tp = nominal pipe thickness, in. Sp = SMYS for pipe, psi Ss = SMYS for sleeve, psi D = pipe outside diameter, in. If flange rating pressure Pf is limiting,
(Eq. 800-3)
In either case, the sleeve thickness should not be less than the pipe wall thickness.
Welding From the section on hot tapping, it can be noted that welding sleeves on pipelines containing fluids can produce faster quench rates in the welds and heat-affected zones. Depending upon the grade and carbon equivalent (C.E.) of the pipe, C.E. = C + Mn/6 + (Cr + Mo + V)/5 + (Cu + Ni)/15 (Eq. 800-4)
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heat-affected zone hardness can rise above the threshold where cracking can occur if hydrogen is present from the weld metal. This is called hydrogen-assisted cracking and is generally thought to require a microhardness above about 350 Vickers (Rc 35) in the heat-affected zone, high tensile stress, and a source of hydrogen for it to occur. Heat-affected zone hardness is difficult to control because more frequently than not, pipeline materials, thicknesses, and fluids being carried will combine to produce fast cooling rates and high hardness. Residual stresses are inherent to the welding process and also difficult to reduce. Of the three variables, only hydrogen can be controlled to reduce the risk of cracking. This can be done through the use of a welding procedure using low hydrogen electrodes (E7018). An additional feature of using low hydrogen electrodes is their characteristic of less penetration than obtained with cellulosic electrodes (e.g., E6010 and E7010) conventionally used for pipeline welding. This provides an additional margin of safety to avoid burnthrough when welding on thinner materials.
Dents When full encirclement sleeves are used to repair dents, the space between the dent and the sleeve should be filled with a hardenable material like an epoxy resin so there is good contact between the pipe and the sleeve. One method is to apply the epoxy resin to the dent with a trowel and then contour it to the original pipe circumference before the sleeve is installed and welded in place. Care should be taken to assure that the void between the sleeve and the pipe is completely filled.
Inspection The fillet welds at the ends of full encirclement sleeves have been the site of underbead cracking which was the cause of at least one recent pipeline failure [2]. While the use of cellulosic electrodes and higher strength pipe (X52) were separated out as the main causes of cracking, it was brought out that inspection of these welds should be routinely done even with low hydrogen electrodes. Inspection should be by visual examination and magnetic particle inspection. Particular attention should be given to looking for cracks along the toe of the fillet on the pipeline side.
870 Maintenance Program in Areas of Unstable Soils or Earthquakes Nearly all pipeline systems are required to have normal operating and emergency contingency plans. These plans specify immediate operating action in event of landslide, subsidence, or earthquake. In addition to normal maintenance surveillance, the following measures are suggested for areas of unstable soils and seismic risk:
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As-built documentation should be on hand so that any changes from design or design assumptions are recognized, documented, and evaluated for their effect on pipeline integrity
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The inspection plan should include a recognition of the key components of design, to ensure the integrity of the line, and a program for monitoring these components
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Measurement surveys should be conducted periodically to detect changes in field conditions and in the line
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A contingency repair plan should be prepared for corrective actions for situations of varying degrees of severity. It should identify (1) recurring problems requiring routine periodic correction, (2) problems that may arise for which standard procedures can be implemented without engineering involvement, and (3) critical problems requiring engineering investigation and resolution. Necessary materials and construction equipment to make repairs on an urgent basis should be available near the areas of risk
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A postevent monitoring plan with checklist for reporting as soon as possible whether damage is severe or relatively minor. The initial inspection checklist should identify specific system components and ground conditions that are good indicators of damage. Ground condition indicators include: ground cracks; misalignment of roads, trees, fences, pole lines, railroad tracks, etc.; ground sags, sinkholes, or uplifts; signs of damage to other nearby utility lines. As soon as possible after strong events, a thorough investigation should be made by responsible operations and technical personnel to determine the condition of the pipeline, safety of resuming operations, and necessary corrective repairs or replacement
In making repairs to a line damaged by ground displacement, precautions should be taken in cutting the pipe to avoid fire or injury in view of likely sudden release of high strain energy stored in the line. Also precautions should be taken for possible hydrocarbon spills in the soil and for unstable ground conditions.
880 In-Service Line Lowering When land surface grading is to be done over an existing pipeline, such as for a new highway or other new land use, that will expose the pipeline either to mechanical damage and/or excessive stresses from wheel loads, measures must be taken to protect the pipeline, preferably without removing the line from service. One method consists of lowering the pipeline into a deeper trench so that it will be positioned farther below the new graded surface. The rationale for lowering is that in its new, deeper position the pipeline will experience stresses from wheel loads that are acceptably small and that the pipeline will be safe from mechanical damage during the grading and excavation. Guidelines for safely lowering pipelines without taking them out of service were established by a Batelle Columbus Laboratories study published in 1985, undertaken jointly by the Office of Pipeline Safety Regulation of the U.S. Department of Transportation, ASME, and API; see Reference 3, Section 890. The study presents detailed guidelines for conducting a pipeline lowering operation, equations for predicting the lowering induced stresses; it establishes reasonable limits on the lowering-induced stresses, so that the pipeline will not be damaged or ruptured due to lowering operations. The study is not an endorsement of lowering as a method of addressing the safety of an existing pipeline, but provides guidance to pipeline operators or contractors who choose lowering as their preferred alternative. Elements to be considered in lowering a line are:
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Factors that affect lowering—the pipe, the pipeline and its condition, terrain, soil, and stress
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Safety—pressure reduction, excavation safety, response to emergencies, protection of personnel and the public
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Stresses—existing stress in the pipeline, lowering induced stresses, measuring and calculating stresses, support spacing, safe limits on stresses
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Failure modes—ruptures, leaks, or buckles from improper lowering operations
•
Procedures—Initial review, trench types and profiles, lowering alternatives, measuring stresses, minimizing temporary stresses, inspection
The following computer programs are available from Chevron Pipeline Co., San Francisco. PDROP. Calculates trench length, maximum pipeline stress, and added stress for free deflection of a pipeline TRENCHZ. Calculates trench length and profile during lowering while keeping below a given stress limit SUPPORT. Calculates the range of distance between pipeline supports required to minimize the stress in the pipeline during lowering PLIFT. Calculates the lift-off lengths, maximum stress, and force required to lift the center of the pipeline to the specified height. (This program can be used to determine initial pipeline stress) These programs have been validated. However, the TRENCHZ program may not produce exact results in every situation, especially with small diameter pipelines, due to the inaccuracy of the PC FORTRAN in calculating soil/pipeline interaction stresses. The accuracy level is adequate for most pipeline applications.
890 References
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1.
Kiefner, J. F., Repair of Line Pipe Defects by Full Encirclement Sleeves, Welding Journal, June 1977.
2.
U.S. Department of Transportation, Office of Pipeline Safety. Alert Notice. March 13, 1987.
3.
Kiefner, J. F., T. A. Wall, N. D. Ghadiali, K. Prabhat, and E. C. Rodabaugh, Guidelines for Lowering Pipelines While in Service, Batelle Columbus Laboratories, February 25, 1985.
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900 Offshore Abstract This section discusses worldwide offshore pipeline design and construction practices. These practices are similar in many respects to onshore practices. This section focuses on the U.S. regulations for design techniques, construction methods, and specialized components required for offshore pipelines. It also discusses subsea pipeline repairs. The position taken by this Offshore section of the manual is that a minimum the Company will use U.S. Standards and Codes, worldwide, but not necessarily U.S. regulations in foreign locations. Where there are no regulations, Company Pipeline specifications govern. Regulations on a worldwide basis, are not covered since they are quite different in some countries.
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Contents
Page
910
Regulations, Pipeline Permits, Recommended Practice, and Certification
900-3
911
Regulatory Jurisdictions/Codes
912
Pipeline Permits
913
Recommended Practices
914
Certification
920
Route Selection and Surveying
921
Route Selection
922
Surveying
923
Environmental Data
930
Design
931
General Design Considerations
932
Subsea Line Sizing
933
Pressure Design
934
Pipeline Collapse and Buckling
935
On-Bottom Stability
936
Pipeline Laying Analysis Using the “SEAPIPE” Computer Program
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Protection of Appurtenances
938
Submarine Pipeline Cost Estimating Guide/Computer Program — “SUBPIPE”
939
Pipeline Design Calculations
940
Detailed Design/Analysis
941
Design Analysis Programs
942
Contractor’s Stress Analysis
950
Component Selection
951
Subsea Pipeline Valves and Actuators
952
Subsea Pipeline Mechanical Connections
953
Concrete Weight Coating
954
Corrosion Coatings
955
Insulation
956
Flexible Pipe
957
Cathodic Protection—Anode Systems
958
Safety Requirements and Component Selection
959
Coiled Steel Tubing Flowlines
960
Construction and Installation
961
Pipelay Methods
962
Pipelay Personnel and Equipment
963
Construction Operations
964
Pipe Joining Methods
965
Pipeline Tie-in Methods
966
Inspection During Installation
967
Shore Crossings
968
Pipeline Burial or Trenching
969
Pipeline Crossings
970
Operations
971
Submarine Pipeline Repairs
972
Pipeline Inspection
973
Abandonment
980
Ultra-Deepwater Pipelaying
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990
References
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991
Jurisdiction of Outer Continental Shelf (OCS) Facilities
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910 Regulations, Pipeline Permits, Recommended Practice, and Certification This section discusses the types of regulations, regulating authorities, codes, pipeline permits, recommended practices, and certifications to be considered when planning an offshore pipeline project. For the purpose of this section offshore pipelines are considered to be in the United States Outer Continental Shelf (OCS) outside of state waters. Due to frequent changes in regulations and standards, project areas should be investigated prior to undertaking a design and construction project to ensure current information is used.
911 Regulatory Jurisdictions/Codes The U.S. Code of Federal Regulations (CFR) - Title 49 Parts 192 and 195 and Title 30 Part 250 consists of the following (also see Section 410):
DOT Pipelines •
Part 192—Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards
•
Part 195—Transportation of Hazardous Liquids by Pipeline
DOI Pipelines •
Part 250—Oil and Gas and Sulfur Operations in the Outer Continental Shelf
The two governing Departments concerned with pipeline-related matters are the Department of the Interior (DOI) and the Department of Transportation (DOT). Per their Memorandum of Understanding, the DOI’s area of responsibility includes those pipeline facilities beginning where hydrocarbons are first produced and continuing to the outlet flange at each facility where the produced hydrocarbons are first separated, dehydrated, or otherwise processed. The DOT’s area of responsibility extends from this outlet flange shoreward. See Section 991. The major source of regulations pertaining to both DOT onshore and offshore liquid pipeline design is 49 CFR 195, which contains a complete list of industry standards, codes, and specifications (see Part 195.3) that are incorporated. The most valuable is ANSI/ASME B31.4 which contains design requirements in Chapter 2. Corrosion allowance, internal pressure, and external pressure are discussed, as well as the presentation of equations (also see Section 410). Similarly, the major source of regulations pertaining to both DOT onshore and offshore gas pipelines is 49 CFR 192. Appendix A of Part 192 contains a list of industry standards, codes, and specifications that are incorporated. This includes ANSI/ASME B31.8. Multiphase pipelines shall be designed in accordance with ANSI/ASME B31.8. Annual reports and incident reports for DOT pipelines are covered by 49 CFR 191. DOI offshore pipelines are regulated by 30 CFR 250. This document is a “must” for offshore liquid and gas pipelines. Documents incorporated by reference are given in
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Part 250.1. Subpart J contains requirements for “Pipelines and Pipeline Rights-ofWay.”
912 Pipeline Permits All pipeline designs and proposed routes must be submitted to and approved by the appropriate governmental agencies. The scope of the following discussion is limited to those pipelines that originate, traverse, and terminate in the OCS, i.e., Federal waters. The Minerals Management Service (MMS) approves pipeline routing and construction in OCS waters. Pipelines are classified as either lease term, or right-of-way pipelines: Lease Term. Pipelines that are wholly contained within the boundaries of a single lease, the boundaries of unitized leases, or the boundaries of contiguous (not cornering) leases which are of the same owner or operator are lease term pipelines if installed by a leaseholder. Right-of-Way. Right-of-way pipelines include: (a) those installed by nonleaseholders within the above limits, (b) those which traverse across lease boundaries, outside the above limits, or across unleased blocks, (c) those within the boundaries of contiguous (not cornering) leases which do not have a common lessee or operator, and (d) those within the boundaries of contiguous (not cornering) leases which have a common lessee or operator but are not owned and operated by that common lessee or operator. MMS conducts a technical review for each proposed pipeline to assure compliance with 30 CFR 250, pertinent adopted Standards of the National Association of Corrosion Engineers (NACE), API Publications (as referenced in 30 CFR 250), and 49 CFR Parts 191, 192, and 195, where applicable. The basis is the application submitted by an operator which details the design and routing. The purpose of the MMS Gulf of Mexico (GOM) Regional Supervisor’s letter of April 18, 1991, reference MS 5232 is to provide clarification, description, and interpretation of the requirements contained in 30 CFR 250.150 through 30 CFR 250.164 which pertain to the approval, installation, operation, maintenance, and abandonment of lease term and right-of-way pipelines and to the granting, modification, and reliquishment of pipeline ROW’s in the GOM Outer Continental Shelf. Most of Chevron’s U.S. offshore pipelines are located in this area. Similar documents should be obtained, if available, for other areas. When preparing to construct a pipeline that will traverse state regulated waters or wetlands, permits from other federal (such as the U. S. Army Corps of Engineers, are also needed in the Gulf of Mexico), state and local agencies must be obtained. The previous discussion may or may not be applicable to such a case, so further investigation into the matter will be necessary. A Revised Edition of API RP 1111, Second Edition, November 1993 is available from API, Tel. No.: 202-682-8375. This recommended practice sets out criteria for the design, construction, testing, operation, and maintenance of offshore pipelines engaged in the transportation of hydrocarbons from the outlet flange of a production facility where hydrocarbons
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are first processed. The criteria also apply to any transportation piping facilities located on a production platform after separation and treatment, including meter facilities, gas compression facilities, liquid pumps, and associated piping and appurtenances. Each overseas location may have similar requirements to obtain approval of pipeline permits.
913 Recommended Practices This subsection briefly discusses American Petroleum Institute Recommended Practices (API RP’s). API RP 1111 - Recommended Practice for Design Construction, Operation and Maintenance of Offshore Hydrocarbon Pipelines It is intended for application in all climatic regions. The design, construction, inspection, and testing provisions of API RP 1111 are not intended to be applied to offshore hydrocarbon pipeline systems designed or installed before its issuance (March, 1976). The operation and maintenance provisions of this RP are generally suitable for application to existing and new facilities. (Incorporation by reference of API RP 1111 in 30 CFR 250.152(a) for DOI pipelines has been deleted.) API RP 14E - Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems - Risers Risers and piping on production platforms are covered by API RP 14E. The design and installation of platform (not pipelines) piping should conform to ANSI/ASME B31.3, as modified in API RP 14E. Risers (for which B31.3 is not applicable), should be designed and installed in accordance with API RP 14E, Section 1.2. (Comment: ANSI/ASME B31.4 and 31.8 should govern designs for pipelinespecific facilities on a platform which can include headers and pig barrels.) For DOI pipelines, 30 CFR 250.152(a) has been modified to incorporate B31.8 by reference. In determining the transition between risers and the platform piping to which API RP 14E applies, the first incoming and last outgoing valve which blocks pipeline flow is the limit of application. Per API RP 14E, Section 5.11, risers should be designed for maximum wave loading, internal pressure, marine traffic (may require bumpers), and other environmental conditions. Per Section 6.5.a, risers should be protected in the splash zone from corrosion. (For DOI pipelines, incorporation by reference of API RP 14E in Part 250.152(b) has been deleted.) API RP 17A - Recommended Practice for Design and Operation of Subsea Production Systems - Pipelines and End Connections
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Some key sections of API RP 17A are the following: Section 3 of API RP 17A presents guidelines intended for the design, construction, testing, and installation of subsea pipelines and end connectors used in a subsea production system. The guidelines cover the unique factors of subsea systems which are high pressure, multi-phase flow, multiple lines, subsea connections, and Through Flowline (TFL) systems. Engineering considerations commonly encountered in subsea pipelines and end connectors are discussed. API RP 17A does not replace API RP 1111. API RP 1111 should also be used for subsea pipelines intended for the transportation of hydrocarbons to other destinations. Section 6 of API RP 17A addresses the structural analysis procedures, design guidelines, component selection criteria, and typical designs for production risers operated in conjunction with subsea production systems and Floating Production Platforms. Section 7.3.5 of API RP 17A discusses transportation, installation, testing and operation of pipelines/umbilicals. Similarly, Section 7.3.6 discusses risers. API RP 17B - Recommended Practice for Flexible Pipe API RP 17B provides guidelines for the design, analysis, quality assurance, storage, handling, transportation and installation of flexible pipe systems. The application of flexible pipe to production risers is covered in API RP 17A.
914 Certification Following completion of pipeline construction, in the U.S., a completion report must be filed with the permitting agency (for DOI pipelines, see 30 CFR Part 250.158). Information to be included in the completion report includes an “as-built” plat showing coordinates of key pipeline locations, a complete set of all hydrostatic test data, and the results of the hydrostatic test. The permitting agency reviews this information and, if everything is in order, issues a letter of certification. The letter of certification must be maintained on record for the life of the pipeline.
920 Route Selection and Surveying This section discusses route selection and surveying for offshore pipelines. It notes items that should be considered in selecting a route and typical surveys needed to provide design information and/or required by regulation.
921 Route Selection The most direct route is generally preferred for an offshore pipeline, and this can usually be accommodated more easily than for onshore pipelines. However, a number of factors must be considered when finalizing the alignment. Their influence will vary with the site-specific application. It is important that routing decisions be made carefully and address all of the factors. This ensures that adequate
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survey coverage is arranged for and provides appropriate descriptions for right-ofway applications. Route selection progresses in stages. Initially, based on available seabed information and general routing requirements, a possible corridor is identified. As sitespecific information from surveys and pipeline design becomes available, the alignment is firmed. In certain instances, optional alignments may be carried, until an installation technique is selected. The following factors should be addressed during the route selection process. (Items 3 through 10 are design considerations.) 1.
End points. At a platform, the location of risers or J-tubes will suggest routing. The location of a riser on a particular face of a platform can lead in many cases to lines having significant curvature. The minimum curvature is determined based on the nominal tension and soil friction, see Section 936. This is not normally necessary for thermal expansion or other stress considerations. A pipeline end manifold (PLEM) will also have a preferred approach. A shore crossing point will fix the termination and influence the associated alignment.
2.
Intermediate points. Current or future plans may include additional tie-ins from other facilities. It may be advantageous to run the first line close to these other locations and thus minimize the expense of connecting the other pipelines. Should tap valves be installed on the line as it is laid, it is preferred that they be in a straight run to minimize the rolling tendency.
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3.
Thermal expansion. An allowance may be necessary for thermal expansion. An offset (or “Z” bend) is typically provided in these cases.
4.
Access by others. In congested areas, for example around platforms, the ability to install all anticipated facilities (pipelines, cables, mooring systems) should be provided for. A clear area should be left for a Jack-up drilling rig (or Tender drilling rig mooring) for applicable water depths/platforms.
5.
Line crossings. Crossings are undesirable because they are expensive and may require future inspection and maintenance. They should be avoided if it is possible to reroute the pipeline at lesser expense, see Section 969.
6.
Tie-in methods. Flanges, mechanical connectors, or welding are typically used. The need for flexibility using spools, deflect-to-connect methods, etc., will suggest different pipeline routing.
7.
Installation method. The ability to spot the pipeline in a location is important. Towing techniques usually require a straighter alignment than surface deployment from lay or reel barges. Whether the pipeline is laid to or from an end point will likely influence the local route. For multiple lines, the ability to maintain separation is critical. The installation method, pipeline, and seabed characteristics will determine the allowable curvature (or minimum radius) in the alignment (see Section 936).
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As an example, adjacent pipelines offshore Cabinda, Angola require a minimum separation distance of 50 feet, except when the pipelines approach a platform. 8.
Marine activity. Fishing activity should be considered. In the Gulf of Mexico, pipelines are buried out to 200-foot water depths. This avoids most heavily fished areas. If the sea floor soil is very soft, sometimes the pipeline undergoes self burial (see Section 968). Normally a trawl board will go over a small-diameter unburied pipeline, but there is high risk of damage. Therefore, small diameter lines in the North Sea are typically buried or rock covered or otherwise protected. On the other hand, large lines (greater than 16-inch O.D. in U.K. waters) are robust enough to withstand trawl impacts and are typically left unburied. Trawl gear will also ride over these lines although spans may allow gear to snag. For unburied lines offshore California or in the North Sea, appurentances will likely require shrouding or placement below the mudline to minimize snagging. Anchoring of construction equipment during construction and for maintenance is important. Agencies are concerned about anchor placements on hard bottom features. With an adequate hazard survey and careful anchor placement, most hard bottom features can be missed during construction. Large areas of hardbottom features may determine what pipeline construction technique is used, presumably one that minimizes anchoring. However, personnel and construction equipment safety are primary considerations. Anchoring during construction should be considered and the alignment adjusted to allow safe mooring (see Section 963).
9.
Seabed profile. Gradual gradients are preferred. Where slopes must be traversed, for example, a shore approach, it is usually desirable to run pipelines perpendicular to the contours. This will minimize loading on the pipeline should a slope failure occur.
10. Seabed characteristics. Outcrops, hard bottoms, unstable ground, and manmade obstructions should be avoided. In these situations, undesirable pipe spans may occur requiring expensive intermediate supports (sand-cement bags, anchors, etc.). Soil properties may suggest a preferred route. Pipeline lateral and vertical stability and burial requirements may be optimized by routing through the most favorable soils. In mudslide areas the pipeline should be aligned closely to the known mudslide flow direction. In the Gulf of Mexico, breakaway connectors should be considered for protection of a platform or other pipeline. For oil service the connector should include a check valve to minimize oil spillage. When routing lines in shallow water which are parallel to the shore, ensure that the route considers minimum draft requirements for the type of installation equipment to be used. If the line is routed in water too shallow for available equipment, special installation methods must be devised: a longer route that
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provides adequate water depth for common lay barges may prove to be a less expensive option than a direct route through shallow water. Minimum water depths for pipeline routing should consider the effect of tidal variations and ground swells in addition to the minimum draft requirements of the lay vessel. For instance, in Nigeria, swells in excess of 8 ft were recorded during the installation of the Inda pipeline; this made installation of the pipeline in water depths less than 20 ft along the shore approach difficult and more dangerous than installation in deeper waters.
922 Surveying Once the area of possible construction is defined, surveys are contracted to obtain site-specific information supporting design and/or agency requirements. This includes bathymetry, seabed characteristics, soil properties, stratigraphy, hazards, cultural resources, biological activity, and environmental data. Survey data acquisition should be appropriately scheduled as there can be time constraints on the acceptability of the data by agencies. A good understanding of the regional shallow geology often helps in anticipating geohazards and planning the scope of the surveys. In the Gulf of Mexico, one can expect complex seafloor conditions on the continental slope and relatively uniform conditions on the shelf. To avoid expensive remobilizations, a firm understanding of the coverage and field data requirements should be in hand before initiating the survey process. While the offshore work can be done relatively quickly, it is relatively expensive. Be sure that adequate data is collected to satisfy the regulatory agencies and the contractors bidding on the project, and to allow for possible modifications to the proposed route. Data reduction is time consuming. The data use and the consequences of variances should be well understood. This will permit making decisions on data acquisition alternates. For example, if jetting into the seabed is planned, obtaining a soil boring may be attractive to ensure that contractors are working with confirmed, and not inferred, data. This is not necessary in mature areas, such as the Gulf of Mexico, if the Company has confirmed data for the block/area. Agencies will typically have requirements for conducting pre- and postconstruction surveys. The type of survey, tie-line spacing, report format, and raw data to be collected should be identified. (Note: Federal and State requirements are usually different in some respects. Discussion of the proposed program with the involved agencies is recommended prior to bidding and data acquisition.) Surveys are generally conducted simultaneously from a surface vessel on a predetermined survey grid. Today, satellite positioning is the primary system for conducting offshore surveys and locating construction vessels. Alternatively, a radio positioning system from shore or fixed platforms could be established to locate the vessel while conducting the surveys. There are a few radio positioning systems still in use but are considered secondary systems in most cases. Navigational positioning system accuracy can be plus or minus 20 feet, depending on the system. Current MMS requirements specify a minimum accuracy of five meters or less.
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Surveys may include bathymetry, side-scan sonar, magnetometers, acoustic subbottom reflection profiles, measurement of depth of cover over pipelines, sampling, remotely operated vehicles (ROV’s), submersibles, and divers.
Bathymetry Echo sounders are run continuously over the area; and the trace, after calibrating for the effects of salinity and temperature, provides raw depth readings. These must be further adjusted for tides and transducer location to develop depths related to a datum (e.g., mean-lower low water, MLLW). The data are contoured and an isobath map produced. Analog profiles of the bathometry are used to detect gas rising to the surface from the sea floor.
Side-Scan Sonar A tool is towed behind the boat at a constant height above the seafloor along a predetermined grid that will provide a 100 percent coverage of the area of interest. Sonic pulses are emitted toward the seabed, reflected, and received by the tool and recorded on the boat. The shadows and shading on the record are interpreted for seabed materials and objects on the sea floor. Obstructions, outcrops, anchor scars, pipelines, etc., can be identified and mapped. A mosaic of the side scan records can be assembled showing the seabed configuration, but is not required by the MMS as a part of the preconstruction survey documentation. The MMS only requires a paper copy of the side scan data. A short baseline acoustic tracking system may be used to rovide more accurate positioning of the sonar tool. However, such a tracking system does not improve the quality of the side-scan data. Side-scan sonar data is also used to identify gas rising to the surface from the sea floor. Use of side-scan sonar can be limited in locations close to platforms and structures because of difficulties towing the tool close to the platform and signal reflection from structural members can cause distorted images. Radial scan sonars (i.e. those tools that provide a full 360° coverage around a point) are widely available. These are designed to be deployed from platforms. Divers are often used to supplement side scan-conar near platforms and structures.
Magnetometers A tool is towed behind the boat on the surface, continuously recording the magnetic field. Magnetometers are commonly used to locate pipelines and metallic objects. Changes are correlated with ferrous metal objects, and large changes may be identified on the side-scan sonar records. Magnetic anomalies are one means of establishing cultural resources, but because of the limited data collected on the survey, significant features may be missed. This is particularly true of data from a surfacetowed tool in deep water. MMS standards are normally 1 gamma sensitivity with a noise level not exceeding 3 gammas peak-to-peak (i.e., plus or minus 1.5 gammas). Gradiometers, which consist of an array of magnetometer sensors, are often used for similar applications.
Acoustic Subbottom Reflection Profiles A tool is towed behind the survey boat to collect data from the seafloor and subbottom reflections (the MMS standards for resolution are better than 1 to 2
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meters within the upper 15 meters of sediment.) The energy source is typically piezo-electric or electromechanical. De-coupling and/or active compensation for wave heave is used in seastates greater than Beaufort Force 2 to achieve clearly interpretable recordings. In deep water, near-bottom towing or narrow-beam sound sources are usually necessary to achieve cleaner horizontal resolution. The signals are reflected when they reach different material interfaces and are recorded. The traces sometimes allow interpretation of the seabed material and stratigraphy when referenced to available samples. Faults, gas sands, mudslides, dip of subsurface strata, sediment thickness, etc., can be mapped. Medium depth acoustic profilers known as “sparkers” or “boomers”, that are often used in seismic surveys, can be used to profile the subbottom to a depth of 300 meters. The MMS standards do not waive the use of medium depth acoustic profiles for shallow hazards survey.
Pipeline Depth of Burial Measurements Depth of burial measurements for offshore pipelines may be required as part of the as-built surveys. In the North Sea, all pipelines less than 16-inch nominal must be trenched to provide cover over the pipeline regardless of water depth. In the Gulf of Mexico, pipelines larger than 4-inch nominal constructed in water depths less than 200 ft must be trenched with a minimum of 3 feet of cover. Typically, the Company buries pipelines at a platform in water depths to 300 ft, with a depth of cover of 3-ft in the Gulf of Mexico or 30-inches offshore Cabinda or Nigeria for a length of 200 ft from the base of the riser, then tapering to the seafloor for an overall length of 300 ft. Recent legislation, in the Gulf of Mexico (PL101-599) has required surveys of existing offshore pipelines in water depths less than 15 feet, MSWL to measure depth of cover over the pipelines. Several methods are available which can be used to determine pipeline depth of cover. The most commonly used methods are: Chirp Sonar is a sub-bottom profiler system that utilizes a frequency-modulated acoustic pulse to profile the seabed. Pipelines can be identified and their depth of burial measured from the profile plot. Innovatum is a pipe tracking system which utilizes a gradiometer array to measure the strength of a pipeline’s magnetic field at various positions while crossing the pipeline, and then calculates the depth of cover over the pipeline. TSS 340 is a pipe tracking system that operates by inducing a pulse of electromagnetic energy to set up an energy-magnetic field in the pipeline. It measures the rate the induced field decays and calculates the depth of burial. These methods are usually deployed in a towed tool, by a Remotely Operated Vehicle (ROV), or on a sled which is pulled along the seabed by a survey vessel. Other methods are available to measure the depth of cover over pipelines, but have not gained wide acceptance or use. Divers are often used in shore crossing areas to measure burial depth using “tee-bar” probes that are manually pushed into the seabed to detect a pipeline.
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Precision Gas Pipeline Location - A Technology Study (PRC/AGA/SRI International [49] This study was undertaken to survey and evaluate the technology available to determine accurately the position of submerged or buried gas transmission pipelines, and to assess the applicability of some of the emerging technologies. The objectives are to increase accuracy and reliability while reducing the cost of the surveys. This report is organized to provide an overview of the elements applicable to the problem of pipe detection, identification, and location. These elements include basic sensors and pipe-location systems made up of sensors, computers, peripherals, and data links. The report includes a qualitative comparison of both sensors and systems using a number of performance criteria. A brief description of relevant technologies that have been developed for uses other than pipeline location, as well as new emerging technologies, is also included.
Sampling Drop cores, grab samples, borings, and vibra cores are means for obtaining seabed samples. The first two are relatively easy and inexpensive to deploy. However, they may not obtain the required penetration. Grab samples may not always be representative, and later testing of soil engineering properties may be impossible or not meaningful. Borings and vibra cores may be necessary in these circumstances. Samples are preserved in a near-natural state and then analyzed in a laboratory to determine the engineering properties needed for pipeline design.
In Situ Testing Seafloor deployed cone penetrometer and field vane tests, when used in conjunction with sampling at key locations can be an effective alternative to sampling alone. These in-situ tests cause less disturbance to soil than drop cores and grab sampling. They are also easier to set up than soil borings.
Remotely Operated Vehicles (ROV’s) ROV’s may be used for pipeline inspection. They are used to perform visual inspections and to take cathodic protection system potential readings. These devices are deployed from a surface vessel and may have video cameras, still cameras, and manipulators. They have a positioning system that is referenced to the boat. The ROV’s thrusters are controlled from the surface vessel, and video tapes record what is being observed. ROV’s are useful in biological surveys for monitoring populations and to obtain samples for subsequent identification. They may also be used to view the seabed, outcrops, or other features and confirm other remotely gathered data. The use of ROVs is limited in areas and depths with low visibility.
The Technology of Submersible Remotely Operated Vehicles ((PRC/AGA) [50] The PRC/AGA has sponsored this development project with the purposes: 1) to provide a description of Remotely Operated Vehicles (ROV’s) and the tools and support systems they employ to support underwater pipeline operations; 2) to describe the ROV work accomplished and the techniques employed in support of pipeline tasks, from route surveys to repair; 3) to provide an assessment of the work
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accomplished in terms of the strengths and weaknesses of the ROV’s and the tools and techniques employed and 4) to identify research and development now underway that will eliminate current ROV deficiencies in support of underwater pipeline operations. The main type of ROV used in support of offshore pipeline operations are tethered, free-swimming vehicles. Best results using ROV’s can be achieved by employing experienced operators and marine crew. In this regard, it is not wise to contract on the basis of the lowest bidder, but based on previous experience/cost. Subsea instrumentation for ROV pipeline support can include: cameras, pipe trackers, cathodic protection, side scan or scanning sonar, sub-bottom profiler, altitude/depth sensors, bottom profilers, monitors, ultrasonic thickness measurement and dredges. Potential application of this technology includes: route surveys, underwater inspection, maintenance and repair of offshore pipelines using various types of ROV’s, manned submersibles, etc.
Submersibles Manned vehicles can also be deployed. They serve the same function as ROV’s, but put personnel in closer proximity.
Divers In shallow water areas, for example at shore crossings, divers may be used to gather seabed data. Video, still pictures, and samples can be obtained. One difficulty is locating the diver during the survey. A staff protruding above the water and surveyed from shore has been used effectively. Hand or jet probes have been used to identify the thickness of loose sediments (15-foot maximum).
923 Environmental Data To calculate on-bottom stability, information on the local wave and current environment is needed. These criteria are generally provided in terms of the n-th year storm, where “n” is usually 1, 5 or 100. Historically, on-bottom stability has been calculated by combining the nth-year wave and nth-year current. Research over the past decade has shown that this leads to excessively conservative design since the probability of both the n-th-year wave and nth-year current occurring simultaneously is low. To eliminate some of this conservatism, it is best to use the nth-year wave (current) with the “associated” or expected value of the current (wave). The nth-year parameter will be the one that causes the largest portion of the force and this will depend on the site. In general, the wave will dominate the force in water depths less than 300 ft. Consequently the nth-year wave and “associated” current should be used. Conversely, on the continental slope or in rivers, the current will dominate the force, and the associated wave should be used, although it will usually be negligible. Criteria is usually developed through a combination of measurements and hindcasts using numerical computer models. Measurements and hindcast results are available
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for heavily developed regions in the Gulf of Mexico shelf. In some frontier regions, measurements and hindcasts may be needed. CPTC’s Facilities Engineering Department - Offshore Systems Division (Contact: Cort Cooper, CTN 842-9119) can provide environmental criteria using a combination of their extensive data base and numerical models. Offshore pipeline environmental criteria is slightly different than that required for platform design. Environmental data is required for on-bottom stability design/analysis (see Section 935 for procedures). For shallow water depths, i.e. less than about 65 ft offshore West Africa, it is important to consider directionality in the wave and current. The maximum wave height and current values may not be the most critical if they are parallel to the pipeline. Lower values perpendicular to the line may result in higher loads. CPTC should be given the pipeline route details so that directionality can be considered in determining the worst case wave and current values.
930 Design This section presents methods that permit determination of important pipeline criteria necessary for preliminary selection of pipeline parameters. Figures 900-1 and 900-2, provided by Brown and Root, show all the steps required for preliminary and detailed engineering design. Section 930 does not cover all of these. Also see API RP 1111.
931 General Design Considerations External Loads External loads can significantly affect pipeline design. Some of the causes of external loads include thermal expansion and contraction, impact, vibration, vortex shedding, and soil movement (i.e., mud flows, scour). Generally, most of these external loads would not be a factor. Accordingly, this manual does not deal with design considerations for such cases but serves to make the engineer aware of problems that may exist in individual areas. API RP 1111 and ANSI/ASME B31.4 and B31.8 should be consulted for further information regarding these subjects.
Pipeline Design/Analysis Considerations In many cases, such as laying a large diameter pipeline in deep water, the most critical stresses are induced by the laying operation, rather than by the working pressure of the pipeline. Laying stresses are due to the “S-Curve” configuration of the pipe and tensile load as it passes over the stinger aft of the lay barge and drops to the sea floor (See Figure 900-3). It is necessary to maintain adequate tension on the pipe to prevent buckling in the sagbend, or as it goes over the end of the stinger. We advise consulting CPTC’s Facilities Engineering Department - Offshore Systems Division (OS) in San Ramon, CA to review conditions, such as environment, water depth, size and weight of pipe to be laid, horizontal alignment and Contractor’s calculations. Most Contractors and OS have the necessary stress analysis computer programs.
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Preliminary Engineering Flowchart (Courtesy of Brown and Root)
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Fig. 900-1
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Fig. 900-2
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Fig. 900-3
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Notations for a Suspended Pipe and Curved Stinger, Conventional S-Curve Lay Barge
Another design consideration is that of the pipeline’s specific gravity (see Section 935). Understandably, it is not desirable to have a pipeline that has a positive buoyancy, as the pipeline would float. Specific gravity is generally a problem when dealing with large diameter lines and is solved by the addition of weight coating (see Section 953).
Minimum Yield Strength Historically lower grade pipe (Grade B) has been used for small diameter pipes in shallow water areas and higher grade pipe used for larger diameters and/or deep water. (For small diameter, short pipelines in water depths less than 300 feet, consideration should be given to using Grade B, extra strong pipe because it may be available from Company stock, and surplus pipe can be stored for later use. Also see Section 442.) Suggested values, to begin a design, for minimum yield strength are shown in Figure 900-4.
Type Of Pipe Seamless and submerged arc welded pipe have been used exclusively for offshore pipelines by the Company, until recently. For diameters up to NPS 16 seamless has been used, while for diameters from 18 to 36 inches NPS double submerged arc weld pipe (DSAW) has been used. Electric welded pipe (ERW) has been avoided because of its past reputation for poor quality. However, pipe produced today in
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Fig. 900-4
Suggested Values for Minimum Yields Strengths (ksi) for Pipe
Pipe Diameter, OD, In.
Water Depth, Ft. 0-300
300-600
600-900
+900
6.625
35
42
52
60
8.625
35
42
52
65
10.750
35
42
60
65
12.750
35
42
65
65
14
42
42
65
65
16
42
52
65
65
18
52
60
65
65
20
52
60
65
65
24
52
60
65
65
30
60
65
65
65
36
60
65
65
65
modern mills with high quality material should be considered for offshore applications. ERW is available in sizes up to 24 inch NPS and is usually less in cost compared to seamless above about 10 inches and with DSAW from 16 to 24 inches. Savings of 20 to 25 % have been seen in bids on recent projects. See Section 300 of this manual for an ERW selection decision tree which gives guidance on specifications, inspection and mill sources for ERW pipe. Whenever the costs are comparable between ERW and seamless or between ERW and DSAW , seamless pipe is the preferred product. Electric welded pipe, including ERW can now be made with quality manufacture and lower cost and should be considered for use in non-critical services. For example, $4/ft (1992 dollars) can be saved as compared with seamless for a 12.75inch O.D., 0.500-inch wall thickness pipe having a length of 25 miles. COPI/Chevron Nigeria plan to use ERW pipe for the Inda, Idama, Opuekeba and Okan II projects where cost effective. A project specification was developed for the Okan II Bid Package for seamless, DSAW or electric welded. (For future and current projects, please contact CRTC’s Materials and Equipment Engineering Unit, Richmond, CA for a list of qualified pipe manufacturers and preparation/review of line pipe specifications.)
Minimum Handling Thicknesses Sections 432 and 441 provide criteria for minimum handling thicknesses. These are dependent upon the method of transportation. The reader should be aware that pipe of high D/t ratio, if stacked too high in the hold of a ship could be damaged beyond repair.
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Corrosion Allowance Carbon steel pipelines have been commonly designed without corrosion allowances. In services were corrosion is anticipated a corrosion allowance should be considered to extend the life of the pipeline. Corrosion allowance for a water injection line may be taken as 0.125-inches. For conceptual design cost estimates assume 0.0625-inches. For corrosive products such as high CO2/H2S/H2O gas, etc please contact the CRTC Materials and Equipment Engineering Group in Richmond, CA for a recommendation on corrosion allowance. (See also Section 315 of this manual and API 1111.)
932 Subsea Line Sizing Subsea line sizing is essentially the same as land line sizing (see Section 430 and the Fluid Flow Manual). Nevertheless, there are two issues worth noting. The first concerns the flow regime on two-phase (gas and liquid) flow. The twophase flow regime can be different in the horizontal seabed line than it is in the risers from the seabed to the platform deck. Therefore, the flow regime needs to be checked independently for the two sections when doing hand calculations. A twophase program (like PIPEFLOW-2) will perform the calculations if the geometry of the sections is described properly in the input data. The second issue concerns the enhanced effect that seawater has on the temperature of the pipeline fluid. This effect expresses itself through the external heat transfer coefficient (HTC) defined for the system. (See Section 1000 of the Fluid Flow Manual). Details that go into the external HTC are bottom ambient temperature, coating type, and water current velocity (if required), and the level to which the pipe sinks into the bottom mud or silt (see Section 941). Sea bed temperatures, currents, and mud conditions are seldom known precisely. Therefore, calculated HTC’s will only be approximate. External HTC’s of from 0.5 to 1.0 agree with some offshore Cabinda (Angola) field data where the calculated value was 0.9 (Btu/hr ft2 °F) [1]. For the Point Arguello pipeline the overall design calculated HTC’s ranged from 0.16 to 3.06 (Btu/hr ft2°F). When sizing subsea lines, one should also consider the flow conditions, throughout the field life, i.e., a 5000 BOPD production rate at 800 psi initial condition could become a 1500 BOPD rate with 8000 BWPD at 300 psi condition.
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933 Pressure Design Pressure design procedures are contained in 30 CFR 250, Section 250.152 and API RP 1111 which references ANSI/ASME B31.4 and B31.8. (Also see Section 442 of this manual and Section 192.111(d) of 49 CFR 192 for DOT gas pipelines.) Per API RP 1111, the minimum wall thickness of steel pipe for any given internal design pressure should be calculated by the following equations: PD D t = -------- for ---- > 10 2S t or, PD D t = ------------------------ for ---- ≤ 10 2S + 0.8P t (Eq. 900-1)
where: P = Internal design pressure, psig (the differential pressure between the maximum internal pressure and the minimum external pressure at any point in the pipeline system during normal flow or static conditions) D = Nominal outside diameter of the pipe, in. S = Applicable allowable hoop stress value as provided below, psig t = Nominal wall thickness, in. From API RP 1111, the allowable hoop stress value(s) to be used for the above design calculations for new pipe of known specification is: S = F × E × SMYS × T (Eq. 900-2)
where: S = Allowable hoop stress value, psig, except when further limited as follows: when pipe that has been cold worked for the purpose of meeting the SMYS is heated to 316°C (600°F) or higher (welding excepted), the allowable hoop stress (S) is limited to 75 percent of F × E × SMYS. (Comment: the S value shown in ANSI/ASME B31.4, Table 402.3.1a is based on F = 0.72. When other design factors are used, the value of S should be adjusted accordingly.) F = Construction factor, dimensionless The design factor, F, should be equal to 0.72 for submarine gas and liquid hydrocarbon pipelines; 0.60 for liquid risers; and 0.50 for gas risers.
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Note Per ANSI/ASME B31.4 and B31.8, factors differ based on loading: 0.72 for normal pressure; 0.9 for pipeline flooded during hydrotesting; 0.96 for combined loading including operation and environment. Per API RP 14E, Section 1.2 the design stress should be no greater than 0.6 times SMYS for production platform risers. However, the 0.6 design factor does not meet the minimum requirement for DOT gas lines. 49 CFR 192.111(d) requires a design factor of 0.50 or less for risers on gas pipelines and must be used for gas pipeline risers on production platforms in the U.S. E = Weld joint factor (Refer to ANSI/ASME B31.4, Table 402.4.3 or ANSI/ASME B31.8, Table 841.1B.) Note that E is equal to 1.00 for all pipe manufactured to API Specification 5L. SMYS = Specified minimum yield strength, provided in the pipe manufacturing specifications, according to API 5L or B31.4 or B31.8. T = Temperature derating factor, normally 1.0 (see B31.4 or B31.8 for high temperatures). For the U.K. Sector of the North Sea , please refer to British Standard BS 8010, Part 3 for the hoop stress and wall thickness formulae.
934 Pipeline Collapse and Buckling The objectives of this section are to define pipeline mechanical design criteria and limitations and to provide a procedure for determining the required wall thickness and material grade as a function of pipe diameter, water depth, and installation method. Pipeline design considerations include collapse, buckle initiation, buckle propagation, and the combined effects of external pressure and bending during installation. In addition, two PC programs, “PLDESIGN” and “DEEPD” are briefly described. The minimum wall thickness required to resist external hydrostatic pressure is determined based on current industry practice such that the risk of collapse, buckle initiation, and buckle propagation are reduced to reasonable proportions.
Buckle Propagation Experiments on pipe buckling conducted by Battelle Columbus Laboratories in the early 1970’s revealed a buckle phenomena referred to as a “propagating buckle.” This describes the situation where a transverse dent (that may have been caused by excessive bending during installation, dragging anchors, trawl board damage or by any other cause) changes its configuration into a longitudinal buckle and propagates along the pipe, possibly causing collapse along the entire pipeline length. The driving energy that causes a buckle to propagate is the hydrostatic pressure. The nature of a propagating buckle is that a greater pressure level is required to initiate a propagating buckle (called the buckle initiation pressure, Pi) than the pressure required to maintain propagation of the buckle (called the buckle propagation pressure, Pp). As a consequence of this, a buckle initiated in an offshore pipeline propagates and collapses the line until the external pressure becomes equal to or
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less than the propagation pressure. This assumes that the pipe properties (wall thickness and yield strength) remain the same. Theoretical and experimental equations have been developed to predict the propagation pressure. A summary of the different equations that have been proposed to predict buckle propagation pressure is presented as follows: Source
Pp , Propagation Pressure
Palmer
π σy (t/D)2
(Eq. 900-3)
Battelle
34 σy (t/D)2.5
(Eq. 900-4)
DnV
1.15 π σy [t/(D-t)]2
(Eq. 900-5)
Kyriakides
14.5 σy (t/D)2.25
(Eq. 900-6)
Shell
24 σy (t/D)2.4
(Eq. 900-7)
Of the above equations, the theoretical one by Palmer (Equation 900-3) is the most conservative.
Buckle Propagation Design — Minimum Wall Thickness The minimum required wall thickness of a steel pipeline to prevent buckle propagation for any given water depth should be calculated using the above Shell equation, Equation 900-7, presented as follows: K p ⋅ W d 0.4167 t = D ------------------- 54σy (Eq. 900-8)
where: t = Minimum wall thickness to prevent buckle propagation, in. D = Outside diameter of the pipe, in. Kp = Safety factor of 1.20 Wd = Water depth, ft σy = Specified minimum yield strength (SMYS), psi
Buckle Initiation The pipeline D/t ratio may be sized so that it falls between the buckle initiation pressure and the propagation pressure. This means that the hydrostatic water pressure may or may not be high enough to transform a local buckle into a propagating buckle. The uncertainty lies in the actual shape of the local buckle. If the pipeline were designed to resist a propagating buckle, a local buckle would not be able to propagate. This would be the only case where buckle arrestors would not be required. (Note that the exact values where the initiation and propagation pressures occur are subject to debate. There have been several different experimental programs performed over the years to define these values and each has come up with slightly different results.)
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The initiation pressure depends on the geometry and, particularly, on the initial size of the buckle. Pi may be significantly higher than Pp for minor damage, but may approach Pp for a severely damaged pipe. If the local damage is a buckle developed by pure bending, then Pi = 1.5 Pp. The two different experimental equations that have been proposed to predict buckle initiation pressure are as follows. Theoretical
Pi, Initiation Pressure
Battelle
6.055 × 105 (t/D)2.064
Shell
36 σy (t/D)2.4
(Eq. 900-9) (Eq. 900-10)
Timoshenko Collapse Pressure The Timoshenko formula for the critical, elastic, buckling collapse pressure of pipe is:
2E 1 P c = --------------2- -------------------------21 – υ D D ---- ---- – 1 tt (Eq. 900-11)
where: Pc = Critical collapse pressure for the pipe, psi E = Elastic modulus, psi υ = Poisson’s ratio = 0.3 D = Pipe outside diameter, in. t = Pipe wall thickness, in. The critical elastic buckling pressure is valid for pipe with a very high D/t ratio (greater than 75). In practice, residual ovalization is usually present, and significant deformation of the pipe surface may occur prior to collapse. Hence, the hydrostatic collapse pressure is also a function of the yield properties.
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An expression for determining the critical buckling pressure of perfectly round pipe, which accounts for the pipe yield stress, has been included in the Det Norske Veritas (DnV) rules: t 2 P c = 2σ e ⋅ ---- for σ e ≤ --- σ y D 3 (Eq. 900-12)
or, t 1 2σ y P c = 2σ y ⋅ ---- 1 – --- --------- D 3 3σ e
2
2 for σ e > --- σ y 3 where: t 2 σ e = E ------------ D – t (Eq. 900-13)
Collapse Design - Minimum Wall Thickness Figure 900-5 shows the collapse pressure, Pc, for pipe with an ovality of 1.5 percent for D/t’s from 10 to 50 and pipe grades from Grade B to X70. (Combined bending and collapse is discussed in a subsequent section.) This table should be used for pipe laid using the “S-Curve” method, “J-Lay” method, or pull methods. (The pipe as manufactured should have an out-of-roundness of less than 1 percent.) For pipe laid using a reel lay vessel, Figure 900-6 should be used. (Reeling is expected to produce an out-of-roundness of less than 2 percent.) Reeling will produce an out-ofroundness which is a function of the diameter of the reel, the pipe D/t and of the applied tension. The effect of tension on collapse is usually small and is neglected. This can be modeled using currently available tools as part of the detailed design by the Contractor, if high tensions are of concern. When necessary, CPTC’s OS Division can provide technical assistance to assess this effect.)" The following procedure should be used for collapse design: •
Calculate the collapse pressure, Pc, produced by the seawater at depth, including a safety factor and seawater gravity of 1.03: P c = K c W d /2.25 (Eq. 900-14)
where: Kc = Safety factor to prevent collapse = 1.33 Wd = Water depth, ft
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•
Use either Figure 900-5 or 900-6, based on the above discussion of the pipelay method. Reading down the column for the chosen pipe grade (i.e., minimum yield strength), let Pc = P and interpolate to obtain D/t.
•
Knowing the outside diameter of the pipe D; calculate the required minimum wall thickness, t, to prevent collapse.
Alternatively, the “PLDESIGN” PC program or Shell’s equations for Pc may be used. (See the PC program description provided below or Combined Bending and Collapse, Eq. 900-16).
Design Criteria Pipelines can be designed to meet propagation pressure criteria or collapse criteria. For shallow water pipelines, the pipe should be designed to meet propagation criteria (discussed earlier in this section). For larger diameter pipelines or in water depths greater than about 1200 feet, selecting a pipe wall thickness adequate to resist a propagating buckle can make the pipe expensive, too heavy to install by conventional means, or, in the event of a flooded pipeline during construction, the suspended pipe weight may become excessive. Therefore, the less conservative collapse criterion discussed above should be applied, and the use of buckle arrestors is necessary (see the discussion below). The cost of materials continues to increase with increasing water depths beyond 1200 feet and is limited because of this change in the controlling wall thickness criterion. For installation methods that require minimal submerged weight, the collapse design criterion is preferred. In addition, tow methods induce minimal bending stress in the pipe; therefore, the risk of inducing collapse is low. Pipe collapse criteria, rather than buckle propagation, are preferred for all pipe diameters using installation by towing methods. (If your application possibly falls in the last two categories, we recommend that you contact the OS Division of CPTC for assistance.)
Combined Bending and Collapse (Shell Formulas) Wall thickness may be based on the equations given in Section 21-1 of the Deepwater Pipeline Feasibility Study by Shell Development Company. The equations in the Shell Study are actually collapse equations that are modified to account for outof-roundness and an allowable bending strain. Equation 900-15 is the failure function that provides a criterion for predicting failure of the pipe in the sagbend under the combined effects of external pressure and bending: P/Pc + ε/εc
≤ 1, safe > 1 , unsafe (Eq. 900-15)
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Fig. 900-5
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Collapse Pressure PC (psi) for Pipe with Ovality ∆D/D = 1.5%. No Bending Applied.
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Fig. 900-6
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Collapse Pressure PC (psi) for Pipe with Ovality ∆D/D = 2.5%. No Bending Applied
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where: P = External pressure differential, psi Pc = Critical external pressure for pure collapse, considering ovality of the pipe, psi ε = D/2ρ = Critical bending strain at the maximum bending moment ρ = Pipe centerline radius of curvature at maximum bending moment, inch. εc = Critical bending strain for pure bending, including ovality of the pipe If either the bending strain or the external pressure differential is zero, the equation reduces to pure collapse or pure bending. As shown in Figure 900-7, this equation represents a straight line. The particular location of the failure function with respect to this failure boundary is controlled by the values of σo, Po, and the out-of-roundness function g, which are in turn controlled by the values of D/t, grade (yield strength, σy), and ovality (∆D/D) of the pipe, as described in the equations below: Pc = g Po = g [2 σ o / (D/t)] (Eq. 900-16)
εc = g ε o = g [D / (2 ρo)] (Eq. 900-17)
where: Po = Critical external pressure for pure collapse of round pipe, psig εo = t/(2D) = Critical bending strain for pure bending of round pipe, inch/inch ρo = Critical pipe radius of curvature for pure bending of round pipe, inch σo = σy σE / (σy2 + σE2)1/2 = Critical hoop stress for pure collapse of round pipe, psi σE = 23.55 × 106/((D/t)-1)2, for steel pipe = Critical hoop stress for elastic collapse, psi σy = Pipe yield strength, psi g = Out-of-roundness function = 1 for perfectly round pipe
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∆D = Out-of-roundness prior to loading, in. = (Dmax – Dmin)/2
Fig. 900-7
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Equation 900-15 may be solved using graphical/tabular methods or by trial and error, as follows. We define: σo P o = 2t ⋅ -----D ∆D d = -------t f( d ) = ( 1 + d2 )1 / 2 – d σy r = ------σE f ( d ) ( 1 + r 2 ) 0.5 g ( r, d ) = -----------------------------------------( 1 + r 2 [ f ( d ) ] 2 ) 0.5 1 D2 ε ----- = ----- ⋅ -------bo p t εo (Eq. 900-18)
We assume: bo = 1 We substitute to obtain:
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As a simplification, if we assume elastic behavior, then the allowable bending strain is conservatively limited by the allowable bending stress as follows: ε = σ ab /E, and σ ab D ε ----- = ---- ---------------------------6t 14.75 ⋅ 10 εo (Eq. 900-19)
where: σab = Allowable bending stress (for shallow water, use 0.8 σy; for ultradeep water sy may be used) E = Modulus of Elasticity of pipe (In ultra-deep water it may be necessary to allow plastic behavior for economic reasons and/or maximum tension limitations on the available equipment. However, this calculation is beyond the scope of this manual.) Figure 900-8 gives the out-of-roundness function g for a pipe ovality of 1.5 percent, for D/t’s from 10 to 50 and pipe grades from Grade B to X70. Figure 900-9 is for an ovality of 2.5 percent. We can then substitute the expressions in Equations 900-18 and Equation 900-19 into Equation 900-20 and solve for D/t by trial and error. ε P ----- + ------ = g εo Po (Eq. 900-20)
Equation 900-20 can also be solved using Figures 900-5 through 900-8 if rewritten as follows from Equation 900-16. ε gP ----- + ------ = g εo Pc (Eq. 900-21)
A PC program is also available for the solution of these equations as described below.
Pipeline Design Using the “PLDESIGN” Computer Program The PLDESIGN PC computer program, developed by APTECH for the Company circa 1989, is for the design and analysis of offshore pipelines. The program is
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Fig. 900-8
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Out-of-Roundness Function g for Ovality (∆D/D = 1.5%)
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Fig. 900-9
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Out-of-Roundness Function g for Ovality (∆D/D = 2.5%)
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intended for use by engineers and designers during pipeline initial design, or for verifying contractor’s analysis and data [19]. It is used to determine: 1.
Pipe grade (See Section 931).
2.
Minimum wall thickness for internal pressure design. (The default value for corrosion allowance is 0.0625 inches.)
3.
Minimum wall thickness for buckle propagation design.
4.
Minimum wall thickness for critical collapse.
5.
Minimum wall thickness for critical collapse with bending.
6.
Basic buckle arrestor design parameters, when needed.
7.
Cathodic protection system calculations for sacrificial zinc anodes.
The program also determines general recommended minimum wall thickness and the feasibility of laying the pipeline using the pipe reel installation method. This program is available through the OS Division of CPTC and is free-of-charge for Chevron OPCO’s.
Deepwater Pipeline Design Using the “DEEPD” Computer Program Tera, Inc., has developed for the Company an IBM PC computer program, DEEPD, for designing deepwater pipelines. The program is based on procedures developed in Shell’s JIP, “Deepwater Pipeline Feasibility Study - Phase I,” Chapter 21-4. DEEPD is intended for use in economic feasibility studies where the number of cases under consideration make manual calculation impractical. The program is limited to deep water only (for bare pipe “deepwater” is approximately 180-foot water depth for NPS 6, 295-foot depth for NPS 12, 400- to 500-foot depth for NPS 24, and 525- to 777-foot depth for NPS 48 pipe). The program assumes that the critical condition for pipe failure is buckling due to combined bending and pressure in the sagbend portion of the suspended pipe span. The program was written for the purpose of selecting acceptable combinations of pipe properties, lay vessel tension capacity and stinger lift-off angle for laying deepwater pipelines. Pipe yield strengths and wall thicknesses which satisfy the sagbend buckling conditions are selected for a range of lay vessel tensions. This program is available through the OS Division of CPTC and is free-of-charge for Chevron OPCO’s.
Buckle Arrestors Buckle arrestors should be considered for use in all water depths where the pipe’s buckle propagation pressure is less than or equal to the external hydrostatic pressure (See the discussion on buckle propagation design above). A buckle arrestor is a device, such as a thick pipe section or steel ring, which is welded to or otherwise firmly attached to the pipeline. A properly designed system of buckle arrestors can confine any propagating buckle to a relatively short span which can be repaired at a tolerable cost. Sizes and strengths of buckle arrestors can be determined from the design equations presented later in this section.
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The spacing between arrestors is a discretionary choice between the increased cost of installing arrestors at shorter intervals and the risk of failure of longer lengths of pipeline, which would be expensive to repair. When designing a system of buckle arrestors, it generally is better to err on the conservative side, using arrestors that are “hell for stout” and installing plenty of them. The spacing between buckle arrestors should be limited to the maximum convenient repair length, which is about the length of a barge or ship used to assist in the repair, i.e., in the range of 200 to 500 feet.
Types of Buckle Arrestors Figure 900-10 illustrates several types of possible buckle arrestors. Free-ring. A free-ring buckle arrestor is a thick-wall ring or sleeve that is clamped, grouted, press-fitted, or otherwise fitted snugly to (but not welded to) the exterior or interior surface of the pipe. The maximum crossover pressure for a very thick-wall, snug fitting, free-ring buckle arrestor usually will be considerably below the pipe collapse pressure, particularly for deepwater pipeline applications where D/t ≤ 40. For this reason, external free-ring buckle arrestors are suitable only for relatively shallow water pipeline applications where D/t > 40. Welded-Ring. A welded-ring buckle arrestor is similar to the free-ring arrestor except that it is fillet welded at both ends to the pipeline. The end welds must be of good size and penetration in order to develop the full effectiveness of a welded-ring arrestor. Observations from experimental tests have indicated that welded-ring buckle arrestors are roughly twice as effective as free-ring buckle arrestors. An internally mounted ring generally is a more effective buckle arrestor than one mounted externally on the pipe. The improved performance occurs because an internal ring generally will be deformed more than an external ring for a given deformation of the pipe. Also an internal ring minimizes problems associated with external coatings. A disadvantage of an internal ring is that it introduces an obstruction to the passage of pigs and scrapers. If the obstruction is sufficiently small, it can have a taper and allow for passage of a pig. Integral-Ring. An integral-ring buckle arrestor is a thick-wall ring, or pipe section that is formed into or welded in series directly into the pipeline. This type of buckle arrestor is the most effective because the least amount of added material (steel) is required to stop a propagating buckle failure on a given pipe. Thickened sections formed or welded onto the ends of each pipe joint for the purpose of making up the pipeline via mechanical joints (either screwed or friction-held joints) could serve effectively as buckle arrestors. Any thickened section that is an integral part of a pipe joint could also provide a strong point for gripping and applying tension to a pipeline. If heavy-wall pipe joints are used, the I.D.’s of the pipe and arrestor can be specified to be equal, thus facilitating sphering or pigging operations. This type of arrestor is preferred for deepwater applications.
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Fig. 900-10 Types of Buckle Arrestors
Design Equations for Buckle Arrestors The following equations are recommended for the design of ring-type buckle arrestors. While the equations below are probably the best available for predicting the crossover pressures of ring-type buckle arrestors, they should be used with caution.
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The propagation pressure of a long buckle arrestor (L/D >4) if exposed by itself to external pressure can be expressed by analogy with Shell’s formula for Pp from Equation 900-7 as: h 2.4 P a = 24σ a ------ D a
(Eq. 900-22)
where: Pa = Propagation pressure of arrestor, psi σa = Yield strength of the arrestor, psi h = Arrestor wall thickness, in. Da = Outside diameter of the arrestor, in. The maximum pressure for a buckle to propagate past the buckle arrestor depends on the dimensions and mechanical properties of the pipe and the buckle arrestor and is called the crossover pressure, Px. A buckle arrestor will be effective in stopping and containing the propagating buckle provided the crossover pressure, Px, is greater than the local hydrostatic pressure, P, plus a dynamic overpressure that is generated during the deceleration of the propagating buckle. The following expressions are for the crossover pressures, Px, of the various types of buckle arrestors, in which the arrestor length, L, is a variable. Integral-ring buckle arrestor: L P x – P p = ( P a – P p ) 1 – exp – 60t ------2- D (Eq. 900-23)
External welded-ring or internal ring arrestor: L P x – P p = P a 1 – exp – 60t ------2- D (Eq. 900-24)
External free-ring buckle arrestor:
(Eq. 900-25)
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where: F(c/D) = 0 if c/D >1/4 = 1 - 4c/D if c/D <1/4 L = Arrestor length, in. D = Outside diameter of pipe Px = Crossover pressure of arrestor, psi Pp = Propagation pressure of pipe, psi c = Clearance between arrestor and pipe, in. t = Pipe wall thickness, in. and, P x = Kx P where: Kx = Safety factor of 1.5 for buckle arrestor P = Hydrostatic pressure, psi The term F(c/D) gives the reduction in the crossover pressure due to an initial clearance, c, between the pipe O.D. and the arrestor I.D. The function “min” should be interpreted to mean: compute the two factors and then choose the smaller value. These two factors correspond to the two deformation modes that a pipe can assume in attempting to crossover past an external free-ring buckle arrestor. The pipe cross section will assume either the typical dogbone shape or a crescent shape, depending on the relative stiffness of the pipe wall and the buckle arrestor wall. This change of mode shape does not occur for welded-ring, internal-ring, or integral-ring buckle arrestors.
Safety Factor for Buckle Arrestors For design purposes the crossover pressure, Px should exceed the hydrostatic pressure, P, by a safety factor of 1.5.
Design Equations for Long Buckle Arrestors For long buckle arrestors (L/D>4) the previous equations can be simplified. Integral-ring buckle arrestor: h 2.4 P x = P a = 24σ a ------ Da (Eq. 900-26)
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External welded-ring or internal ring arrestor: Px = Pp + Pa t 2.4 h 2.4 24σ y ---- + 24 σ a ------ Da D (Eq. 900-27)
External free-ring buckle arrestor: for a snug fit, F(c/D) = 1
(Eq. 900-28)
935 On-Bottom Stability This section presents a simplified procedure for determining the minimum submerged weight necessary for an offshore pipeline to resist hydrodynamic forces (wave and current). See also Section 941. The simplified procedure does not account for soil liquefaction, pipeline scouring, unsupported pipeline spans, or allowable pipeline movement, but produces a conservative answer. These effects lie beyond the scope of this design procedure. For conceptual pipeline design/cost studies, in water depths less than 300 feet, the specific gravities for typical line sizes listed in Figure 900-11 will satisfy most on-bottom stability requirements. (Use a minimum specific gravity of 1.2 in sea water, for water depths less than 600 feet and 1.09 for water depths greater than 600 feet.) The Facilities Engineering Department– Offshore Systems Division (OS) of CPTC in San Ramon, CA should be contacted for pipelines requiring detailed on-bottom pipeline stability analyses. The OS team is also available to check the contractor’s calculations. The minimum submerged pipe weight required for on-bottom stability is determined from a static force balance between the hydrodynamic drag/lift force and pipeline soil friction force/submerged weight (see Figure 900-12 and Equation 900-29). These forces are determined from site-specific storm parameters and sea floor characteristics (see Section 923). For on-bottom stability, the minimum water depth, not the maximum, will govern design. To check the stability of a given pipeline, the actual submerged weight is compared to a calculated minimum submerged pipe weight. The minimum submerged pipe weight can be determined from Equation 900-29. The actual submerged pipe weight per foot is the sum of the steel, corrosion coating, concrete coating, any oil or gas, per foot of pipe—less the buoyancy force per foot of pipe. (Typical concrete densities are 140 or 190 pcf. Also the minimum concrete thickness is 1 inch and is
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Fig. 900-11 Conceptual Pipeline Size Estimates for Water Depths Less Than 300 Feet
Fig. 900-12 On-Bottom Stability Schematic
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typically specified in 1/8 inch increments). If the actual submerged pipe weight per foot is greater than the calculated minimum (required on-bottom stability) submerged pipe weight, then additional weight is not required. Concrete coating, anchoring, or rock dumping is required if the actual submerged pipe weight is less than the calculated minimum (required on-bottom stability) submerged pipe weight. (Selection of weight and corrosion coating are addressed in Sections 953 and 954.) Water absorption should be considered when calculating the submerged weight of concrete pipe. Typical values are 3 to 5 percent of the concrete weight in air. The stability analysis should be performed for two conditions: • •
5-year storm, pipeline empty (laying) 100-year storm, pipeline filled with product (operational)
Note
The 100-year storm case is only applicable if the pipe line is not trenched.
Further iterations are required for those cases in which the outer diameter is significantly increased (1 in.) by the concrete jacket. A pipeline design with a route that covers large water depth variations will involve more than one design wave height/wave theory, which in turn will result in more than one minimum required pipe weight. Therefore, an optimum design may consist of several concrete coating thicknesses over the length of a pipeline.
Minimum Pipe Submerged Weight The minimum pipe submerged weight (Wm) required to prevent pipeline movement is determined from the following equation: Wm = Fl + (SF/u) (Fd + Fi) (Eq. 900-29)
where: Wm = Minimum submerged pipe weight, lb/ft F1 = Hydrodynamic lift force, lb/ft Fd = Hydrodynamic drag force, lb/ft Fi = Hydrodynamic inertial force, lb/ft u = Soil friction coefficient SF = Safety factor (use 1.1)
Hydrodynamic Forces Hydrodynamic forces, created by wave and current, are classified as drag, lift, and inertial.
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The hydrodynamic drag force (Fd)can be determined from the following equation: Fd = (1/2) ρ Cd D U2 (Eq. 900-30)
= Drag force, lb/ft where: Cd = Drag coefficient ρ = Fluid density (sea water) = W/g = 64.0/32.17 = 1.99 slug/ft3 W = Weight (sea water) = 64.0 lbf/ft3 g = Acceleration of gravity = 32.17 ft/sec2 D = Pipe outer diameter, ft U = Uw + Uc , ft/sec Uw = Horizontal wave particle velocity, ft/sec Uc = Bottom current, ft/sec The horizontal wave particle velocity (Uw) should be evaluated at the center of the pipeline. The combined horizontal velocities are based on site-specific environmental data (see “Environmental Parameters” below). A drag coefficient (Cd) of 1.0, which is based on full-scale test data should be used in the above equation. The hydrodynamic lift force (Fl) is determined by: Fl = (1/2) ρ Cl D U2 = Lift force, lb/ft (Eq. 900-31)
A lift force coefficient (Cl) of 1.0, which is also based on full–scale test data, should be used in Equation 900-31. (The remaining parameters in the equation have been previously defined.) The hydrodynamic inertial force (Fi) is determined by: Fi = (1/4) π ρ Cm D2 U′ (Eq. 900-32)
= Hydrodynamic inertial force, lb/ft U′ = Horizontal particle acceleration, ft/sec2 (Note: Evaluate at the center of the pipeline)
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The inertial force coefficient (Cm) should be set equal to 2.5 (see Equations 900-33 through 900-35 below for determining U′).
Environmental Parameters For any particular location in the world, site-specific bottom currents, design wave heights, design wave periods for a 5-year (laying operation) and 100-year (inservice) storm return period can be obtained from the OS Division of CPTC in San Ramon, CA. A design wave height (significant wave height, Hs) will vary with depth (shoaling) and with the angle between the wave crest and underwater contours (refraction should be accounted for in determining a shallow water design wave height. In shallow water, the design wave height may be limited to the “breaking wave height.” Wave refraction, shoaling, and breaking effects are design details that should be obtained from OS Division in San Ramon, CA. The design period (significant period, Ts) is not affected by variations
Horizontal Particle Velocity and Acceleration Once the environmental design parameters have been established, the horizontal particle velocity and acceleration can be calculated with the appropriate wave theory. The selection of a valid wave theory is based on the wave steepness (Hs /g Ts2) and Ursell parameter (d /gTs2), where g is the gravitational constant (32.2 ft/sec2). This selection is made by entering Figure 900-13 with the Ursell parameter (x-coordinate) and wave steepness (y-coordinate). The horizontal particle velocity and acceleration equations for Stream Function (Fourier) theory are complicated and lie beyond the scope of this design procedure. The following horizontal particle velocity and acceleration equations for linear wave theory can be used as an approximation to the higher order Stream Function wave theory. 2πZ cosh ---------- T g H L 1 S S U = --- ----------------- --------------------------- cos θ L 2 2πd cosh ---------- L (Eq. 900-33)
2πZ- gπH S cosh --------L U′ = -------------- --------------------------- sin θ L 2πd cosh ---------- L (Eq. 900-34)
where: U = Horizontal particle velocity, ft/sec U′ = Horizontal particle acceleration, ft/sec2
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L = [(g Ts2) /(2 π)] [tanh (2 π d/L) ] (Eq. 900-35)
= Wave length, ft (must be solved iteratively) Z = Height of pipeline center above sea floor, ft Ts =
Significant wave period, sec
Hs = Significant wave height, ft g = Gravitational constant (32.2 ft/sec2) d = Water depth, ft θ = Wave phase angle (0° under wave crest, 180° under trough) To simplify the analysis, a wave phase angle of 0 degrees should be used to calculate the approximate maximum force on the pipeline. Fig. 900-13 Regions of Validity for Wave Theories (See the Shore Protection Manual)
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Soil Friction Coefficient The soil friction coefficient for the pipeline/soil interface is also site specific. The friction coefficient in the minimum pipe submerged weight equation (Figure 900-29) should be based on the mudline soil classification and selected from the following values. (Note: the following values account for settling of the pipeline.) Clay (cohesive)
=
0.50
Sand (cohesionless) =
0.80
Hard rock
1.00
=
Soil friction coefficients for clay/sand mixtures (sandy clay, clayey sand) should be classified as either clay or sand depending on the higher concentration. A minimum safety factor (SF) of 1.1 is recommended, but special circumstances (poor data, regions of soil instability, sloping sea floor, etc.) may warrant a higher value and more detailed analysis. 0.5 is typical of a stiff clay. A soft clay (like in Nigeria and much of the Gulf of Mexico) can have a much higher friction factor when settling of the pipe is considered. For this case, the use of 0.5 may lead to overly conservative designs. If soil boring data is available, including an estimate of the Soils Cohesive Shear Strength, if mostly clay or the Relative Density, if mostly sand, then the AGA’s Level 2 procedure, described in Section 941 and [26], and the Company’s PC program PLS may be used to calculate pipeline sinkage and on-bottom stability.
Feasible Concrete Coating Thicknesses Based on Foundation Stability Excessive pipeline weights may result in settlement depending on the soil density and undrained shear strength. The following equation has been adopted to determine the maximum allowable specific gravity to avoid settlement. This equation is based on an “Experimental Investigation of Pipeline Stability in Soft Clay” [21]. Example values (*) are given below for offshore Zaire [27]. SG max = SG soil + 2 (c) / [ (p) (D)] (Eq. 900-36)
where: SG max = Maximum allowable pipeline SG SG soil = Soil specific gravity (0.48*) c = Undrained shear strength, psf (62.5*) p = Fluid density, pcf (64.0*) D = Outside diameter of the pipe, ft A PC program is also available for the solution of the equations for on-bottom stability as described below.
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On-Bottom Stability Design Using the “PLS” Computer Program The PLS-PC program, developed by APTECH for the Company circa 1991, is for the design and analysis of offshore pipelines for on-bottom stability. The program is intended for use by Company engineers and designers during pipeline initial, preliminary or final design, or for verifying the Contractor’s analysis. PLS-PC is based on the AGA’s on-bottom stability, Level 1, analysis procedure [26]. The PC program has default values for the Company’s recommended values for hydrodynamic and soil coefficients and uses the theory discussed previously in this Section. The objective of the PLS-PC program is to provide a “user friendly” procedure and software for analysis or design of offshore pipelines. The basis of the AGA’s Level 2 procedure is described in Section 941 and [26]. Analysis using Level 1 assumes a soil friction coefficient as input data and thus one can not determine the pipe sinkage. Analysis using Level 2 requires that near bottom soil data (for clay, the shear strength in psf) be measured and used as an input to the analysis for the determination of pipe sinkage. On lines requiring concrete, having the proper near bottom soil data and being able to do a Level 2 design may result in a significant savings, $MM’s in cost, particularly if the line is large and long. The program determines the minimum required concrete thickness for pipe hydrodynamic stability for a given current and wave data. The corresponding specific gravity and submerged weight are also determined. The program has “User Friendly” formats for both input and output. It prompts the user for all input, and default values are incorporated into all appropriate parameters, such as hydrodynamic and soil friction coefficients, corrosion thickness, length of the concrete cut back, wave angle, etc. The user can accept these defaults or enter desired values. An important feature is included in the program, where an alternate solution is provided for the case, where the concrete thickness is less than 1-inch. In this instance, the program increases the wall thickness, and the hydrodynamic analysis is done to determine the minimum required steel pipe wall thickness for stability with no concrete weight coating. PLS-PC is available through the OS Division of CPTC in San Ramon, CA and is free-of-charge for Chevron OPCO’s.
Development of Pipeline Stability Design Guidelines for Liquefaction and Scour American Gas Association (AGA) Report [46] This report undertakes a detailed overview of current practice in analyzing the effects on pipeline stability for liquefaction and scour. Guidelines are developed to establish stability and safety for submarine pipelines in areas prone to these occurrences. Scour problems have occurred on pipelines offshore Australia, in the North Sea and at river crossings. Liquefaction may also occur in earthquake areas. The primary emphasis of this study is to document and evaluate state-of-the-art technology in assessing pipeline stability for both liquefaction and scour conditions. These practices are summarized and practical engineering methods established for the analysis of pipeline stability under liquefaction and scour conditions.
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In addition to the written report, two interactive, PC-based computer programs were developed to provide a means for rapid assessment of pipeline stability conditions. Guidelines for these programs are provided in the report. The report is useful in the assessment of liquefaction and scour for the design of pipelines and an assessment of the Contractor’s proposed design.
Pipeline Spanning and On-Bottom Stability Spanning will affect the pipeline both positively and negatively. From a structural point of view, unsupported spans may cause the pipe to be over stressed. However, as far as stability is concerned, pipeline spans can reduce hydrodynamic forces. Both vertical lift and horizontal drag forces are reduced as a pipeline moves away from a boundary (See the 1981 Det Norske Veritas, DNV Rules for Submarine Pipeline Systems and Section 969). Also, where the pipeline touches down, it will embed further into the soil, thus developing larger passive lateral soil resistance than a pipeline not embedded into the soil. (This is mostly true in granular material. In cohesive soil, under certain situations the lateral resistance may be less.) This is because the entire weight of the pipe is still supported by the soil; however, there will likely be less lift force to reduce the vertical load on the soil. If movements of the pipeline due to hydrodynamic forces are excessive and are not alleviated within a reasonable time, the structural integrity of the weight coating may deteriorate and the pipeline may experience some loss of coating, and ultimately become unstable. Vortex shedding vibrations may also cause fatigue damage to the line.
Sediment Transport Scour, erosion, natural backfilling, and other sediment transport phenomena also affect pipeline stability. This will mainly depend on the soil type, bottom current and the height of the pipe above the seafloor. Any embedment or elevation above the seabed will reduce lift, drag, and inertial forces. Soil resistance forces will increase significantly when sediment transport phenomena (i.e., sand waves, natural backfilling, etc.) partially bury a pipeline, also see the comments above on spanning. However, scour can increase a pipeline span and thus lead to vortex shedding problems.
Det Norske Veritas On-Bottom Stability Code The Company does not advocate the of use codes and standards which lead to high cost pipelines such as DNV’s code for on-bottom stability, which is overly conservative and if applied, costs the Company millions of dollars for no apparent benefit.
936 Pipeline Laying Analysis Using the “SEAPIPE” Computer Program The Company’s SEAPIPE-PC computer program can be used for the analysis of offshore pipeline installations [2]. However, this analysis is only a two dimensional, “simplified,” static one and thus neglects the hydrodynamic effects of current and waves and the dynamics of pipelaying. These simplified calculations are usually
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sufficient for conceptual/preliminary design studies; however, more detailed calculations using finite element techniques should be done (by the contractor or the Company) prior to actual pipelaying as part of the detailed design (see Section 940). Both the conventional S-Curve and vertical J-Lay installations can be analyzed by this program. (See Figure 900-14.) The analysis is valid for pipe in tension in shallow and deepwater applications. Large deflection applications, which typically require highly nonlinear analysis with the aid of large computers, are included. Fig. 900-14 SEAPIPE Flow Chart: Two-dimensional
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SEAPIPE-PC can be run on a hand-held Hewlett-Packard HP-41C, HP-41CV, or HP-41CX computer. An IBM PC version has been developed by Applied Offshore Technology Co. for the Company. One of our objectives in developing “SEAPIPEPC” is to have a conventional pipelay analysis program that is easy to use. The PC program permits multiple runs, rapid analyses, and file retention. This program is available through the OS Division of CPTC, in English or metric versions and is free–of–charge. SEAPIPE-PC is intended for use by the Company’s design and construction or offshore pipeline engineers at different stages of an offshore pipeline project to perform an in-house design or to check the contractor’s calculations: • • • • • •
To determine the feasibility of laying a specific pipe in a given water depth(s) To determine the ability of a pipelay vessel to lay a specified pipeline To evaluate the capability of a bidder’s equipment to lay a specified pipeline To set the barge and stinger for a given pipe installation To monitor pipe stress conditions during pipe laying To determine the minimum route radius for laying curved pipelines.
The program also determines the location of the pipe touchdown point on the seabed, an aid for simultaneous pipe laying and trenching operations.
Pipelay Analysis: S-Curve The conventional pipelaying method, the “S-Curve” method, is illustrated in Figure 900-15. Input parameters to SEAPIPE-PC are divided into the following groups: • • •
Pipe parameters Vessel parameters Water depth and tension
Some of the more important output is: • • • • • • •
Maximum sagbend stress Bottom tension in the pipe Minimum required stinger length Pipe departure angle at the tip of the stinger Horizontal distance of the suspended pipe Average overbend strain Stinger tip depth
Pipelay Analysis: J-Lay The J-Lay vertical pipelaying method is considered mainly for deepwater applications. Figure 900-16 illustrates the method with a semisubmersible vessel. This method can also be accomplished using a ship (see Section 980). The SEAPIPE-PC input parameters and output are the same as for conventional pipelaying analysis (see Figure 900-14).
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Fig. 900-15 Conventional S-Curve Pipelay Illustration
Fig. 900-16 Vertical J-Lay Pipelay Illustration
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Discussion of Results During conventional pipelaying by the S-Curve method, the pipeline extends from the tensioner, along the barge ramp, over a stinger and down to the seabed. Two regions are typically defined along the pipe string. These are the overbend and the sagbend regions (see Figure 900-3). The overbend region includes the pipe string from the tensioner to the departure (lift-off) point from the stinger or barge ramp. The sagbend region represents the pipe from the inflection point, where the bending moment in the pipe is zero, to the seabed. In the overbend region, the barge ramp rollers and stinger are adjusted such that the pipe bends gently downward toward the seabed. Often these rollers are set up at a general radius of curvature, selected based on the pipe yield strength, σy, and a Company design factor (typically 0.80 for shallow water). Even when the rollers are not adjusted to a given radius of curvature, bending of the pipe is accomplished in a “controlled” manner and the pipe is restrained from further bending by the rollers. The design factor of 80 percent of the yield strength is usually selected to allow for localized increases in the moment at the rollers. In practice this is acceptable, unless the rollers are spaced at large intervals and the pipe weight is very heavy. In any case the pipe is subjected to controlled bending, and overstressing usually occurs either in the sagbend due to insufficient tension or at the stinger tip due to insufficient stinger length. Since bending is controlled in the overbend, in exceptional cases it is possible to allow 95 to 100 percent of the yield strength for the combined maximum pipe stresses on the stinger, assuming that three dimensional, finite element, static and dynamic calculations are performed, including the environmental conditions, barge movement, etc. However, this should not be typical design practice. SEAPIPE-PC is designed to provide accurate analysis and results for both the sagbend stresses and minimum stinger requirements. The required stinger length calculated and provided as a result of the overall pipelaying analysis ensures a smooth transition of pipe from overbend to sagbend. The program calculates the minimum required stinger length for the given pipe and barge parameters and tension. The stinger must be at least this long (but may be longer). The calculated overbend stress is a result of pipe bending to the average overbend radius and tension in the pipe. The sagbend stress is the combined stress due to bending and tension and is calculated based on a two dimensional static analysis. This accounts for tension in the pipe and includes large deflections where nonlinear bending equations apply. In analyzing a particular problem, the user is advised to make several runs varying tension from a minimum likely value to a maximum likely value. Plots of the maximum sagbend stress vs tension, required stinger length vs tension, and others may then be developed (see Figure 900-17 and Reference [3]). The 180 ft length limit criteria shown in Figure 900-17 is the actual length of the existing stinger.
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Fig. 900-17 Pipelay Tension and Stinger Requirements
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Nominal Vessel Tension A nominal or optimum vessel tension can then be selected from the plots and remaining SEAPIPE-PC output (overbend stress and bottom pipe tension). The nominal tension is that tension at the lay vessel tensioner(s) that satisfies the pipeline stress, pipeline route, and barge limitations. The primary governing parameters for selecting a nominal tension are the maximum pipeline sagbend and overbend stresses. A selection procedure is given in [2]. Also see Section 942. The final nominal lay vessel tension (plus or minus the “dead band”) should satisfy all those requirements mentioned and be less than the maximum available tension. The tensioner dead band is required so that interruptions in the laying process (welding, inspection, etc.) are kept to a minimum (i.e., the pipe does not move relative to the barge.) Contact the OS Division of CPTC for pipeline lay analyses.
Minimum Route Radius For Laying Curved Pipelines The minimum pipeline route radius, Rs, to prevent slippage of a curved pipeline on the sea floor while laying can be calculated either according to the following formula or by SEAPIPE-PC: Rs = T/(wf) (Eq. 900-37)
where: Rs = Minimum slippage radius, ft T = “Nominal” bottom tension, lb (or that obtained from SEAPIPEPC analyses) w = Pipe submerged weight, lb/ft f = Pipe lateral friction coefficient in installation condition (typically use the same as for on-bottom stability, see Section 935). The expansion and longitudinal stresses due to pipe bending and design operating pressure should be considered for the minimum route radius (see ANSI/ASME B31.4, Section 402.3.2 (D) and B31.8a-1990). The minimum radius due to expansion and longitudinal stresses for the line as laid, Ra, is calculated as follows: Ra = ED/(24 σy Fd) (Eq. 900-38)
where: Ra = Minimum radius due to expansion and longitudinal stresses, ft E = Modulus of elasticity of the pipe, psi D = Pipe outside diameter, in. σy = Pipe minimum yield strength, psi Fd = 0.72 × 0.75 = 0.54
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The larger of the two calculated radii, Rs or Ra, is the minimum radius permitted along the pipeline route.
937 Protection of Appurtenances Applications Offshore pipelines may include appurtenances such as lateral tie-ins, valves, subsea pig receivers/launchers, anchors, or supports. These facilities are discontinuities in the normal smooth profile of the pipeline itself. In the Gulf of Mexico, these facilities must either be buried with a minimum of 3 feet of cover as for pipelines to the 200 ft water depth contour or protected with some device/grout bags/shroud at water depths over 200 ft to ensure that the facilities are not damaged and are compatible with other users of the area, such as fishermen.
Design Considerations The following items should be considered. Expected Interaction. Dropped objects, fishing gear, anchors, and mudslides are the major potential hazards for a pipeline and appurtenances. Based on the assumed interaction, design forces can be developed. The design consideration should adequately address impact and static pull forces generated by: •
Dropped objects that can vary in size and shape
•
Fishing gear contacts. Studies have been done in the North Sea to quantify trawling equipment/pipeline interaction; these data should be modified, as required, to treat the fishing type, size, and methods in the area of concern; impact forces and static pull forces are a function of these data.
•
Small anchors can usually be designed in accordance with other design considerations.
•
Large anchor interaction is unlikely in some areas and control within the pipeline corridor may be possible. Because of the size of large anchors and the seabed penetration, complete protection is not usually possible.
•
Mudslides may require the use of a section of flexible pipe for pipeline/riser connections and safety joints (shear connectors).
Access. The need to use, operate, and maintain the appurtenances will affect protection design. In this regard, tie-ins have an ongoing need, while supports or anchors do not. Installation. Protection devices for small appurtenances may be laid with the line; however, line rotation is possible. This method is the most cost effective. Separate structures installed after laying the pipeline are expensive and involve risk of pipeline damage. Smooth Profile. Fishing compatibility requirements in most codes and permits require pipelines to have a smooth profile. The intent is that fishing gear ride over
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the facility without hanging up. In some instances, demonstrating the interaction with tests is required.
Protection Options A number of approaches are listed below. The method(s) selected should satisfy the design criteria established in the preceding section and be cost effective. Burial. In the Gulf of Mexico, tap valves have typically been buried to provide protection. This requires hand jetting in the vicinity of the tap to ensure it is not damaged. Access is restricted with burial. Possible shifting of seabed materials that may expose the component should be considered. Rock Cover. Placing gravel or larger rock over the appurtenance may provide the required protection. Placement methods must ensure that the component will not be damaged. Access is limited. Additional rock may be necessary if seabed currents or interaction is a problem. Mats. Enclosures in various shapes and sizes are available that can be placed over an appurtenance, then filled with grout. Other mat designs involve concrete beams tied together with threaded cables that provide some flexibility to conform to an irregular shape. Care should be exercised in the design to ensure that the mats will not become an obstruction. Artificial Seaweed. Mats with buoyant artificial fibers are available to be placed in the vicinity of an appurtenance. The fibers reduce the current velocity, allowing sediments to deposit. In active seabed areas, buildup of material is quite rapid. Protection is then obtained by the appurtenance becoming buried. Shrouds. For small items concrete, steel, plastic, or fiberglass can be used. These shrouds can have a smooth profile and may be deployed while laying. Large components have been protected with concrete, steel, or fiberglass shrouds installed after the pipeline is in position. These devices can become very large when sloped sides are provided to ensure fishing gear will not be obstructed and clearances are sufficient to accommodate all equipment and access requirements. Building a shroud by stacking sand-cement bags in a pyramid shape is frequently used. Placing a template with the desired final configuration has been used as a guide for the diver. Interlocking or stacking the exposed bags may be necessary so they will not dislodge and cause a hazard to fishermen.
938 Submarine Pipeline Cost Estimating Guide/Computer Program — “SUBPIPE” The objective of the Company’s Submarine Pipeline Cost Estimating Guide and its accompanying IBM PC cost estimating program, SUBPIPE, is to provide an expedient method for preparing preliminary cost estimates for offshore pipelines in the Gulf of Mexico and other regions throughout the world [4]. With an understanding of the guide and some familiarity with the location, order-of-magnitude cost estimates can be obtained. The guide is meant for field development screening studies (lease sales, acquisition, conceptual design, etc.), comparative estimates, and for
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preliminary OPCO economics. (Estimates for appropriations and firm budgets should be made in greater detail and should recognize current local market conditions.) SUBPIPE-PC, Version 4.0 applies to the following offshore locations: 1) Gulf of Mexico, 2) Atlantic - Canada, 3) Atlantic - USA, 4) California Coast - North, 5) California Coast - South, 6) Lower Cook Inlet, 7) Bering Sea, 8) Arabian Gulf, 9) North Sea - North, 10) North Sea - South, 11) Mediterranean Sea, 12) South America, 13) Nigeria, 14) Cabinda/Zaire, 15) Southeast Asia, 16) South China Sea and 17) Western Australia. The cost estimating computer program serves the same function as the cost estimating guide with its accompanying figures and tables. The computer program utilizes a Lotus 123 spreadsheet format and incorporates tables of materials and installation cost data for use in estimating submarine pipeline costs. Cost estimating parameters include: 1) Material Costs, including: line pipe, corrosion coating, concrete coating, zinc anodes and buckle arrestors, 2) Mob/Demob, 3) Pipelaying, vessels including: shallow-water, conventional, third generation, J-lay and reeling, 4) Trenching, 5) Shore Crossings, 6) Risers, 7) Lateral Tie-ins, 8) Pipeline Crossings, 9) Testing, 10) Surveying, 11) Contractor Design, etc, 12) Company Support, 13) Modifications, 14) Onshore Pipe Make-up for Reeling and 15) Insurance. The SUBPIPE-PC program 1992 enhancements include: 1) insulated, and/or 2) towed and/or pulled pipelines. Insulated pipeline materials include: 1) Thermal Insulation Materials, 2) Protective Jacket Materials, 3) Bulkheads, 4) Water Stops and 5) Centralizers. Pipe Towing cost estimating installation methods include: 1) Bottom, 2) Off-bottom, 3) Controlled Depth and Near-surface Tow. SUBPIPE-PC, Version 4.0 Guide/program diskette enhancements include: 1) Updated 1990 Guide cost curves/PC program to reflect 1993 costs, 2) Revised locations and reviewed area factors, 3) Identified the cost data used and specific cases used to verify the program, 4) Adjusted the default wall thickness values, and 5) Prepared a separate algorithm for enhancing material transportation costs. Figure 900-18 shows first quarter, 1988 cost estimates for short pipelines in the Gulf of Mexico. The figure was developed using the program. Copies of the Guide and computer program may be obtained free-of-charge for Chevron OPCO’s from CPTC’s OS Division in San Ramon, California.
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Fig. 900-18 Cost Estimates for Short Pipelines in the Gulf of Mexico
939 Pipeline Design Calculations The following example detailed pipeline design calculations are for an offshore pipeline with a route in water depth ranges from 200 to 250 feet in the Gulf of Mexico. The line is required to handle a maximum flow rate of 40,000 barrels of 40 degree API oil and a maximum operating pressure of 1,000 psi. The friction pressure drop, surge pressure, pipeline flow, and fluid properties are covered in the Fluid Flow Manual in Sections 400, 800, 900, and 1000, respectively. The example pipeline assumes a 22-psi pressure drop over a 2-mile length. The line sizing involves preliminary pipe selections, economic considerations, comparing system alternatives (annual throughput rates, pipeline and pumping facilities, pumping energy) and finally a detailed design. (Refer to Section 430 and Figure 400-6 for Line Sizing). The route area has the following environmental conditions. Return Period
Chevron Corporation
5 year
100 year
Significant wave height, ft
25
35
Significant wave period, sec.
14
16
Bottom current, ft/sec
0.5
0.5
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Sizing for Flow The Darcy-Weisbach equation in the Fluid Flow Manual is used to determine the pipeline diameter. P = [ (f L W2)/ (D5ρ (7.4 × 1010))] (Eq. 900-39)
where: P = Pressure drop, psi f = Darcy friction factor L = Length of pipeline, ft W = Mass flow rate, lbm/hr D = Pipe inside diameter, ft ρ = Fluid density, lbm/ft3 Specific gravity = 141.5/ (131.5 + °API) = 141.5/ (131.5 + 40) = 0.825 ρ = 62.4 (0.825) = 51.5 lbm/ft3 W = 40,000 bopd (day/24 hr)(5.62 ft3/bbl)(51.5 lbm/ft3) = 4.82 × 105 lbm/hr Assume: f = 0.04 L = 10,560 ft(2 mi) Solving Equation 900-39 for the pipe inside diameter: D5 = (f L W2)/ (P ρ 7.4 × 1010) D5 = (0.04)(10,560)(4.82 × 105)2 /(22)(51.5)(7.4 × 1010) D = 1.03 ft or 12.36 in. Therefore, assume the outer diameter is 14 inches (API Specification 5L, X 42) for the remaining calculations. Because the outer diameter has been established, a wall thickness may be determined based on the maximum operating pressure, buckle propagation, collapse, combined bending and collapse, and on-bottom stability.
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Pressure Design Determine the hoop pressure at the required depth: External pressure = (depth)(ρ salt water)/144 in2 / ft2 = (200 ft)(62.4 lb/ft3)(1.03) / (144 in2/ft2) = 89 psi Internal pressure = 1000 psi P = 1000 - 89 = 911 psi Determine the allowable hoop stress from Equation 900-2 with: E =
1.0
F = 0.72 and SMYS =
42,000 psi:
S = F ⋅ E ⋅ SMYS From (Eq. 900-2)
= (0.72) (1.0) (42,000) = 30,240 psi Determine the required wall thickness from Equation 900-1: t = PD / 2S = (911)(14)/(2)(30,240) = 0.21 in. (minimum for pressure design) Therefore, since D/t = 67, it is valid to use the equation: t = PD/2S (Refer to Section 933 for applicable pressure design equation.)
Buckle Propagation Design Determine the minimum wall thickness to prevent buckle propagation from Equation 900-8: t = D [ Kp Wd / (54) (SMYS)]0.417 From (Eq. 900-8)
= 14 [ (1.2) (250)/(54) (42,000)]0.417 = 0.34 in. (minimum for buckle propagation design)
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Collapse Design Determine the collapse pressure from Equation 900-14: Pc = Kc Wd/2.25 From (Eq. 900-14)
= (1.33) (250)/2.25 = 148 psi Using Figure 900-5, with Pc = 148 psi and grade X 42, determine the minimum pipeline thickness. The D/t ratio is off the chart, but if we use a maximum D/t value of 50, then the corresponding thickness would be t = 14/50 = 0.28 inches, which is less than the buckle propagation criteria of t = 0.34 in.
Combined Bending and Collapse Design A wall thickness may be assumed in order to perform the combined bending and collapse design. The largest thickness obtained from calculations for pressure, buckle propagation, and collapse design should be used. These are: Pressure = 0.21 in. Buckle propagation = 0.34 in. Collapse = 0.28 in. Therefore, use the value for thickness obtained from the calculation for buckle propagation, 0.34 in. Determine the critical hoop stress for elastic collapse from Equation 900-17: σE = 23.55 × 106 /[(D/t) – 1]2 = (23.55 × 106) /(14/0.34 – 1)2 psi = 14,590 psi Determine the critical hoop stress for pure collapse of round pipe: σo = SMYS ⋅ σE / (SMYS2 + σE2)1/2 (Eq. 900-40)
= (42,000) (14,590)/[(42,000)2 + (14,590)2]1/2 = 13,782 psi Determine the critical external pressure for pure collapse of round pipe, from Equation 900-18: Po = 2t σo/D = 2 (0.34) (13,782)/14 = 669 psi
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Determine the out-of-roundness function from Figure 900-8: D/t = 14/0.34 = 41 g = 0.898 Determine the critical external pressure for pure collapse, considering ovality of the pipe, from Equation 900-16: Pc = g Po = (0.898) (669) = 601 psi Determine the critical bending strain for pure bending of round pipe from Equation 900-17: εo = t/2D = 0.34/[2(14)] = 0.012 Determine the critical bending strain for pure bending, including ovality of the pipe from Equation 900-17: εc = g ε o From (Eq. 900-17)
= (0.898) (0.012) = 0.011 Determine the critical bending strain at the maximum bending moment by using Equation 900-19: ε = 0.8 × SMYS/E where: E = Modulus of Elasticity of steel ε = 0.8 × SMYS/E = 42,000 / 29.5 × 106 = 0.00113 Determine the following ratios and enter Figure 900-7 to determine if the assumed thickness is safe or unsafe, from Equation 900-15: P/Pc + ε/εc
≤ 1, safe > 1 , unsafe From (Eq. 900-15)
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P / Pc = 148/601 = 0.25 ε/εc = 0.00113/0.011 = 0.10 0.25 + 0.10 = 0.35 < 1 Therefore, the combined bending strain and collapse pressure = safe. If the figure had indicated that it was unsafe, then an iteration process involving increasing wall thicknesses would be required.
Pipeline Size A standard pipeline thickness of 0.344 inches will be used for the on-bottom stability and lay stress analyses. This standard wall thickness satisfies the governing design criteria, which is the buckle propagation.
On-bottom Stability Design—5-year Storm The submerged weight of the empty pipeline is equal to the pipe weight in air less the buoyancy force. The submerged weight for the empty NPS 14 pipe with a wall thickness of 0.344 inches is -18.2 lb/ft, meaning it would be buoyant. Therefore, the initial on-bottom stability calculations will be made for a NPS 14 pipeline with 1 inch of 140 lb/ft3 concrete. Submerged Weight = 9 lb/ft (includes 5 percent water absorption in concrete). Determine the valid wave theory for the 5-year storm conditions using Figure 900-13: H/(gT2) = 25/(32.2) (14)2 = 0.004 d/(gT2) = 200/(32.2) (14)2 = 0.032 Therefore, the valid wave theory is the Stream Function. Determine the horizontal particle velocity at the center of the pipeline from Equation 900-33: Uw = 2.96 ft/sec Then from the definitions for Equation 900-17: U = Uw + Uc = 2.96 + 0.50 = 3.46 ft/sec Determine the hydrodynamic drag force from Equation 900-30:
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Fd = (0.5) ρ Cd D U2 = (0.5) (1.99) (1.0) (1.33) (3.46)2 = 15.8 lb/ft Determine the hydrodynamic lift force from Equation 900-31: Fl = 1/2 ρ Cl D U2 = 15.8 lb/ft where: Fl = hydrodynamic lift force, lb/ft Fd = hydrodynamic drag force, lb/ft D = pipe diameter, ft Cd = drag force coefficient Cl = lift force coefficient ρ = fluid density, slugs Determine the on-bottom stability safety factor from Equation 900-29 when the soil friction for sand = 0.8 and the hydrodynamic inertial force is zero: Wm = Fl + (SF/u) (Fd + Fi) From (Eq. 900-29)
9 lb/ft = 15.8 + (SF/0.8) (15.8 + 0.0) Therefore: SF = NEGATIVE Therefore, the empty pipeline is very unstable for a 5-year storm return period, because the safety factor is much less than 1.1. The concrete density should be increased to 190 lb/ft3 and the pipeline safety factor recalculated. Several iterations are required, with the concrete thickness increasing by 1/8-inch each time until the safety factor is greater than 1.1: 1.
Concrete thickness
= 1 inch
Concrete density
= 190 lb/ft3
Submerged weight
= 25.4 lb/ft
∴Safety Factor
= 0.40
Make Concrete Density = 190 lb/ft 3 2.
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Concrete thickness
= 1.125 in.
Submerged weight
= 32.2 lb/ft
∴Safety Factory
= 0.80
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3.
4.
Concrete thickness
= 1.25 in.
Submerged weight
= 38.3 lb/ft
∴Safety Factor
= 1.07
Concrete thickness
= 1.375 in.
Submerged Weight
= 44.5 lb/ft
∴ Safety Factor
= 1.33
The safety factor is calculated in the following manner. Using Equation 900-30 the Drag Force is: Fd = (0.5) (1.99) (1.0) (1.40) (3.46)2 = 16.67 lb/ft The Lift Force from Equation 900-31 is: F = 15.8 lb/ft On-bottom stability safety factor (Equation 900-29), Wm = Fl + (SF/u) (Fd + Fi) 44.5 = 15.8 + SF/0.8 (16.67 + 0) ∴SF = 1.38 Therefore, the empty pipeline is stable for a 5-year storm return period provided that the pipeline has 1.375 inches of concrete coating, having a density of 190 lb/ft3.
On-bottom Stability Design—100-year Storm The Submerged Weight with the pipe full of 40° API oil is, Wm = 91.1 lb/ft Determine the valid wave theory for the 100-year storm conditions using Figure 900-13: H/gT2 = (35)/(32.2) (16)2 = 0.0042 d/gT2 = (200)/(32.2) (16)2 = 0.024 Thus, use Stream Function wave theory. Determine the horizontal particle velocity at the center of the pipeline from: Uw = 4.9 ft/sec U = Uw + Uc = 4.9 + 0.5 = 5.4 ft/sec
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Determine the hydrodynamic drag force: Fd = (0.5) (1.99) (1.0) (1.40) (5.4)2 = 40.6 lb/ft Determine the hydrodynamic lift force: Fl = 40.6 lb/ft Determine the on-bottom stability safety factor: Wm = Fl + (SF/u) (Fd + Fi) 91.1 = 40.6 + (SF/0.8) (40.6 + 0.0) ∴SF = 1.00 Therefore, the pipeline (full of 40° API oil) will be slightly unstable for a 100-year storm because the safety factor is less than 1.1. The concrete coating thickness should be increased another 0.125 inches: Concrete thickness = 1.5 in. Submerged weight = 97.2 lb/ft Safety Factor= = 1.09 The pipeline is still unstable. A concrete coating thickness of 1.625 inches is necessary to satisfy the on-bottom stability requirement.
Lay Stress Analysis A lay stress analysis was performed with the Company’s PC program, SEAPIPE, on the example pipeline. (Note: The lay vessel parameters should be obtained from the project-specific pipelaying contractor.) The lay stresses in the sagbend region are above the 80 percent of SMYS criterion for vessel tensions less than or equal to 40,000 pounds. Therefore, the nominal tension must be greater than 40,000 pounds. If the lay vessel is capable of pulling more than 40,000 pounds plus or minus the allowable percentage for the dead band, then no alterations to the wall thickness will be necessary. The nominal lay vessel tension is selected by comparing the required stinger length to the available stinger length.
940 Detailed Design/Analysis 941 Design Analysis Programs The design of pipelines was covered in Section 930. Contractors are normally responsible for detailed finite element analyses using their own programs. However, in most cases it is beneficial to verify these calculations in-house. The Company
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has obtained several computer programs through joint industry projects (JIP’s) since 1978: 1.
APJTUB - Analysis of J-Tube Riser Pull-Ins APJTUB-PC was developed at our request by Applied Offshore Technology (APTECH) of Houston, TX. It performs a detailed analysis of a steel pipeline pull-in through a J-Tube riser. The analysis is based on a finite beam element formulation. Nonlinear moment curvature properties are considered which account for plastic pipe deformation and unloading and for ovalization of the pipe during bending. The collapse condition is also examined during the pull to ensure that the pipe does not buckle. The program calculates the pull load, maximum strains and stresses, contact loads and locations, and pipe free span parameters during pipe initiation into the J-Tube and for each pull step thereafter. The purpose of the J-Tube Riser Design Manual is to guide designers of Jtubes and J-tube riser pipe installations, including the use of APJTUB-PC [5, 36]. The Manual considers the principal variables which affect pull loads and pipe stresses, including entrance orientation and configuration, bend radius, exit configuration, pipe size vs J-tube size, pipe coatings and material properties, for example. A discussion of basic equipment requirements is also included. The Manual guides the designer in appropriate choices of the APJTUB-PC input variables and suggests suitable assumptions when exact values are not available. The proper use of the program to optimize a design is also discussed. Example problems and sensitivity of pull loads to variations of key parameters are also provided. The program has been verified by a field measurement program conducted by Columbia Gas on Chevron’s Garden Banks Block 236 platform for a 16-inch riser [20]. When actual pipe material properties and actual pipe installation conditions are used the program accurately predicts observed results. APJTUB-PC is available through the OS Division of CPTC in San Ramon, CA and is free-of-charge for Chevron OPCO’s.
2.
OFFPIPE - Pipelaying Static/Dynamic Analysis Capabilities OFFPIPE is a static/dynamic, three dimensional, finite element PC program developed specifically for the modeling and structural analysis of nonlinear problems encountered in the installation of offshore pipelines [23]. The program performs dynamic analyses for both regular and random seas, including current. Analyses should be performed by the Offshore Systems (OS) Division of CPTC. for the purpose of checking the contractor’s final design calculations. The PC program performs the following:
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– –
Pipelaying analyses for a broad range of laybarge and stinger configurations, Pipelaying initiation, abandonment and recovery analyses in which a cable is used to raise or lower the pipeline to the seabed, and Davit lift analyses for conventional riser installations and subsea tie-ins.
OFFPIPE can model the following pipelaying equipment: – – – – – 3.
Conventional lay barges, lay ships and semisubmersible vessels, Vertical or steeply inclined pipeline assembly ramps, as in the “J-Lay” method, Articulated, flexible and rigid fixed-curvature stingers, Fixed stern ramps, and Pipelaying without a stinger.
PIPETOW - Shell Pipe Towing Simulator This program is available on the OELIB disk but has not been verified. PIPETOW was developed for predicting the gross horizontal movements of floating pipe strings during towing and handling. This program is useful for: –
Planning specific maneuvers —Embarkation from shore —Towing along restricted routes
–
Planning general strategies —Effect of storing (anchorage of) pipe strings in currents —Best methods for maneuvering into proper laying alignment —Types of tug maneuvers —Lay rates to avoid damage to the pipe or ramp
–
Guidelines for offshore operations —Recommended tug maneuvers during alignment, handover, and pipelaying —Emergency procedures such as the loss of tug service or suddenly applying lateral loads to avoid collisions
A user’s guide is contained in Reference [7]. 4.
AGA Submarine Pipeline On-bottom Stability Report/PC Program The Offshore Systems (OS) Division has the American Gas Association’s (AGA’s) two-volume report and associated PC program to assist in conceptual, preliminary and detailed on-bottom stability design [26]. The program is stateof-the art; however, it is not written to be “user friendly”. Stability questions
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that require an advanced level of analysis should be referred to the OS Division of CPTC for solution. Volume One is an extensive discussion of the state-of-the-art of offshore pipeline on-bottom stability analysis and is based on over ten years of large and small scale testing. Volume Two is the PC software manual for the three levels of stability analysis: a.
Level 1 - Traditional static analysis (uses the same method as in Section 935),
b.
Level 2 - Quasi-static analysis, and
c.
Level 3 - Dynamic analysis.
The three levels of design are required depending on the familiarity with the location and environment, etc. The AGA Level 2 and 3 programs account for the following factors, which are not addressed in traditional static analysis: a.
Oscillatory flow conditions due to surface wave-generated particle motion. (Hydrodynamic forces predicted by static analyses are generally much lower than the forces calculated in dynamic analyses.)
b.
Effects of past cyclic loading history on pipe/soil resistance forces. (The actual soil resistance forces are typically larger than predicted by the static method.)
Level 2 analysis or design requires site specific soil data, which may be available from the soil boring at the platform location. If clay, input the Soil Cohesive Shear Strength, PSF. If sand, input the Soil Relative Density. This technology can be applied to the conceptual, preliminary and detailed engineering of offshore pipelines. The PC calculations can be used to provide a review of contractor-proposed pipeline designs, including a comparison of onbottom stability calculations. 5.
Submarine Pipeline On-Bottom Stability - PRC/AGA Software and Manuals - Enhancements, 9/93 (Brown & Root) [51] These include one diskette containing the new revised, executable Software and Manual. The AGA enhancements to offshore pipeline software include the following: Level 2 incorporates new soil model coefficients for cohesive soils (clays) which more accurately models the pipe and soil interaction. The result is less conservative designs in clays. Level 2 also incorporates changes to the wave simulation routines which allow the analyses to be performed in deepwater without the program failing to run. Recently, the state-of-art in pipeline stability design has been changing very rapidly. The physics governing onbottom stability are much better understood now than they were previously. This is due largely because of research and large scale model tests sponsored by the PRC/AGA. Analysis tools utilizing this new knowledge have been developed. These tools provide the design and construction engineers with a rational approach for weight coating design, which he/she can use with confidence
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because the tools have been developed based on full scale and near full scale model tests. These tools represent the state-of-the-art in stability design and model the complex behavior of pipes subjected to both wave and current loads. The PC program can be used to perform conceptual and preliminary design of pipelines for on-bottom stability and to assess the Contractor’s proposed design." 6.
Pipe Lift Analysis - PC Program (SEALIFT-PC) (Chevron/APTECH) [52] Contractors frequently use barge single point crane or davits to lift a pipe end to the surface for riser stalk-on or subsea flowline tie-ins. SEALIFT was developed to solve single or multiple davit pick-up problems. Pipe parameters, number of lifting points and their spacing and water depth are specified inputs. The analysis of the lift includes all important parameters, such as wire angles and take-up, tensions and pipe stresses at each lifting point until the pipe end is at the specified distance above the water surface. The program is “user-friendly”, IBM compatible and provides an efficient design/analysis tool for pipeline davit pick-up in the form of a User’s Manual and PC software. The program is intended for use by engineers and designers during pipeline initial design, and for general verification of the pipeline Contractor’s analysis. It can also be used to plan actual pipe lifts and aid in designing the lift procedures. Multiple point lifts are generally limited to less than 350 ft water depth, whereas single point pipe lifts are generally limited to about 800 ft water depths.
7.
Pipe Span Analyses - PC Program (SEASPAN-PC) (Chevron/APTECH) [53] SEASPAN-PC was developed to provide a span analysis, i.e. for vortex shedding, and static loading. (To assess the hoop stress due to operating or hydrotest the user should run PLDESIGN-PC. The PLS-PC Pipeline Stability Computer Program can be used to calculate the inertial drag, lift, and inertial forces (force per foot) which act on the pipeline. The SEAPIPE-PC program can be used to estimate the pipeline residual tension from installation.) SEASPAN-PC can also be used to determine the maximum clamp spacing for conventional risers or the maximum allowable span length for pipe placed on an irregular seabed. The user inputs the pipe parameters and environmental design criteria. The static stress analysis is based on the beam analysis of pipe segments. Tension in the pipe is included in the analysis. The seabottom is assumed rigid. A pipe span may be subject to vortex oscillations if the excitation frequency is close to the natural frequency of vibration of the pipe span. The program is “user-friendly”, IBM compatible and provides an efficient design/analysis tool for pipeline span static stresses and for vortex shedding in the form of a User’s Manual and PC software.
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The program is intended for use by engineers and designers during preliminary or final riser/pipeline design, and for the verification of the pipeline contractor’s analyses or as- builts to assess spans which do not meet specifications. It can also be used to plan modifications to stabilize a pipeline which later develops spans after construction. This has occurred offshore California and Australia. The user is required to specify the basic pipe, span and current parameters. (For vortex shedding, a 5-year storm condition should be used, if necessary contact CPTC’s, Cort Cooper at 510-842-9119.) Several default values are incorporated in the program to make it easy to use. Should you need additional information or assistance in running/installing the PC programs, please contact the OS Division of CPTC in San Ramon, CA.
942 Contractor’s Stress Analysis The contractor shall submit a “Stress Analysis” based on the following discussion: The contractor shall compute, by methods acceptable to the Company, stresses to be expected during all phases of operations. Nowhere shall the maximum total combined stress exceed 80 percent of the Specified Minimum Yield Strength (SMYS) during installation (see Section 963). During hydrostatic testing the maximum total combined stress shall not exceed 90 percent of the SMYS. The contractor shall submit a complete set of calculations to ensure that installation stress shall be maintained within the allowable limit. Calculations shall show a plan and profile of the lay barge, stinger and pipeline from the bow of the barge to the touch-down point on the ocean floor. The contractor’s three dimensional pipe lay stress analysis shall account for tensioner dead band and environmental conditions. Stress control computations shall include analysis extensions to determine laying operational limits due to variations between plan and actual field conditions. As a minimum, considerations shall include: • • • •
Pipe wall thickness variations Weight coating thickness variations Weight coating density variations Stinger angle/depth variations.
The davit lift calculations shall account for any planned horizontal movement of the line.
Nominal Vessel Tension A nominal or optimum vessel tension shall be selected by the contractor (see Section 936). The actual length of pipe on the stinger during laying operations shall be expressly identified in the contractor’s analyses. For the nominal tension, a length of approximately two-thirds of the total stinger length is our recommendation as a “guide-
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line” for initial selection for rigid stingers. However, a longer length may be used based on the contractor’s three dimensional pipelay analyses, which should include environmental conditions, wave and current. It is preferable that the pipe does not bear on the last stinger roller, since this may produce a large bending moment in the pipe or shear stress due to vessel motion or low tension. With this in mind it is very important to have a long enough stinger and the proper nominal vessel tension to avoid these concerns.
Pipelaying Analysis Extensions - Procedure These extensions to determine laying limits and pipeline route radius (also see Section 936) are a part of three more general problems that govern pipeline stress control: • • •
Pipeline weight control, Stinger angle/depth control, and Tension control.
For pipeline weight control the contractor shall take the nominal weight. A final lay stress check shall be performed based on the average measured coated pipe weight. For stinger angle/depth control, stress control computations shall show the lower and upper attitudes of the stinger that lead to 80 percent of SMYS in the overbend. For tension control, the contractor shall anticipate a minimum 20 percent variation of the nominal tension, i.e., a dead band of plus or minus 20 percent of T, where T is the nominal tension. The following matrix, which assumes no variation in pipeline weight (W), results: Tension (T)
Stinger Attitude (S)
Low dead band
Low
Nominal tension
Nominal
High dead band
High
The contractor shall carry out calculations for the following cases: Case 1 : T nominal, W nominal, S nominal Case 2 : T low, W nominal, S nominal Case 3 : T high, W nominal, S nominal Case 4 : T nominal, W nominal, S low Case 5 : T nominal, W nominal, S high For a grey fine to medium sand, the lateral soil friction coefficient may be taken as 0.9 for a newly laid pipeline which is empty and has not settled down in the seabed.
Pipelaying Initiation The contractor shall issue a calculation note for the Company’s approval for connecting of return sheaves at the bottom or top of any Company jacket leg for the
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pipelaying initiation. Alternatively, calculations are to be provided for pipelaying initiation using a “dead man” anchor.
950 Component Selection This topic covers selection of components unique to submarine pipeline operations. Additional discussion of pipe, valves, fittings, etc., is included in Section 300.
951 Subsea Pipeline Valves and Actuators Subsea Pipeline Valves Subsea pipeline valves provide an efficient and cost effective method of controlling product flow in subsea pipeline systems [8]. Placing the valves subsea can optimize system configuration and provide flexibility without using up space and other support equipment on the platform. The main trade-off is that subsea valves are not accessible for repair/inspection. However, with increased industry use, experience, and steady product improvement, subsea pipeline valves and actuators have functioned reliably since 1960 with few problems. Use of subsea pipeline shut-down valve (SDV)/actuator or manual ball valve/check valve (FSV) technology for platform isolation is a recent development, primarily occurring in the North Sea. Three types of valves are commonly used: • • •
Ball valve Check valve Gate valve (Not discussed in this manual [8].)
In recent years, in the vast majority of subsea pipeline applications, ball valves have been used in preference to gate valves due to size (especially with actuator) and lower cost [48]. Christmas tree valves are typically gates and give excellent service.
Applications Typical applications of subsea pipeline valves are:
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Provision for platform isolation—a shut-in subsea valve/check valve installed in the pipeline upstream and/or downstream of the platform riser can permit the platform riser and facilities to be depressurized without depressurizing the pipeline; such isolation valves also help minimize (or prevent) hydrocarbon spills in case of pipeline damage (also see Section 958). The valves will not necessarily minimize pollution from the pipeline, but will minimize pollution from the platform.
•
Control of product transfer between platforms and export loading facilities
•
Tie-in of a peripheral field to an existing export system; a valved tee installed during the laying of the trunk line provides for later tie-in of the lateral pipeline with minimum disruption of the trunk line
•
Interconnection of two or more trunk lines at a subsea pipeline junction
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•
Flow diversion and control for subsea production facilities such as production fluid flow from templates, single and clustered satellite wells, and commingling of production fluids and pigging of the pipelines
Design Considerations Factors that influence or dictate the design and application requirements of subsea pipeline valves are: •
System operating pressure and temperature
•
Fluid composition including H2S, CO2, sand, and other solids
•
Hydrate formation
•
Valves in a static condition, either open or closed for long periods of time during installation and operation
•
Long service life requirement
•
External corrosion from sea water
•
Debris from product and construction activities
•
Capability to test against a lateral without a spill or flow disruption
•
Passage of pigs
•
Restricted maintenance access due to a protective subsea structure
Subsea Pipeline Valve Design Basic subsea pipeline valve (mainly ball valve) design is similar to that used for onshore pipelines. Subsea valve material would generally not be different from that for a surface valve. For example, for sour service, NACE MR-01-75 would be specified for either location. Higher quality materials might be warranted for some items such as elastomeric or metal-to-metal seals and valve trim because subsea valves are less accessible than surface valves. However, the user should be left to determine the appropriate standards. Chemical injection may be used to prevent hydrate formation in pipelines, if necessary. Permafrost will likely require some form of pipeline/valve insulation. Permafrost may be found in the offshore Arctic and very deepwater areas. Valves should meet the requirements of API-6D and ANSI B16.5, B16.10 and B16.34 as a minimum. External corrosion protection is usually provided by the cathodic system protection of the pipeline. Coal tar epoxy or other coating systems are available from manufacturers to provide additional corrosion protection.
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The sizes and pressure ratings of subsea ball valves are similar to those used on land. Some of the commonly used subsea ball valve manufacturers, ranges of sizes and pressure ratings, and design features are listed below: Cooper Industries (See Appendix G) 2 through 48 inches
150, 300, 600 ANSI
2 through 36 inches
900 ANSI
2 through 30 inches
1500 ANSI
Cameron ball valves are generally forged steel, welded body design, chrome plated alloy steel ball, and Nylon seal inserts. Injection ports are provided for both the main valve bore and stem seals for injection of sealant for temporary repair of seal leaks. Grove Valve Co. 2 through 48 inches
150, 300, 600, 900 ANSI
2 through 20 inches
1500 ANSI
2 through 12 inches
2500 ANSI
Grove ball valves are cast or fabricated steel body design, with a nickel plated steel ball, nickel plated steel metal-to-metal seat using a Viton O-ring back-up. The metal-to-metal seals are designed to be bubble tight. An injection port is provided for the main valve bore seals. A coal tar epoxy coating is available for application to the exterior of the valve for additional corrosion protection. Neles (See Appendix G) 1 through 36 inches
150, 300 ANSI
1 through 24 inches
600 ANSI
2 through 36 inches
900 ANSI
2 through 8 inches
1500 ANSI
Neles ball valves are a cast steel body design, with a stainless steel ball and Nylon seats. Metal-to-metal seats are available using Stellite on stainless steel seats and a chrome plated stainless steel ball. (However, a metal-to-metal seal may not provide a bubble tight valve bore seal in this design.) Other manufacturers of subsea pipeline valves include Cooper Oil Tool (WKM), TK, Borsig, Cort, and Mapegaz.
Company Criteria for Reliability of Pipeline Valves/Actuators Reliability depends on the valve type and operating experience with such valves. Some form of protection may also be required to prevent damage from external sources. (Furthermore, because a subsea SDV or FSV would be a secondary safety measure, it is not necessary that it be “bubble tight”.)
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The Company should choose seals for selected valves based on the hydrocarbon’s composition. (The Company should provide this information to the valve manufacturer(s).) Careful consideration should be given to selection of valve/actuator materials. A quality assurance inspection should be required by the Company: 1) during valve assembly to check the ball plating for holidays, 2) for actuator operation (stroking the valve)/testing, and 3) after assembly for an onshore (at factory) valve hydrotest (and air test) per API 6D. These tests should be witnessed/reviewed by a Company representative/inspector. Acceptance testing of valve and actuator should include application of the maximum operating pressure in both directions in separate tests. The valve should be shown to be closed or opened fully from a previously open or closed position with 90 percent of the normal operating hydraulic fluid pressure applied to the valve. Start-up, during the installation phase, can be a significant problem area. The line and valve should be kept clean and free of construction materials, such as welding rods, scale, etc. Also, normally a cleaning pig is run after pipeline construction, prior to start-up. This type of debris can damage the ball coating and elastomeric seat seals. The Company should require a corrosion inhibitor when the pipeline is to be filled with sea water for more than six (6) months. (The valve seat and stem seals must be compatible for the service conditions, including the corrosion inhibitors.) Ball Valve Testing. Testing of ball valves should include breakaway torque for a valve with full pressure on both sides of the valve. There have been instances where the ball cavity blew down when the downstream section of the line (gas) was blown down. The line was repressured from the downstream end to avoid sudden pressure surge or cutting of the seats when the surface valve was reopened. The seats of the valve clamped the ball so severely the actuator (pneumatic) had to have extra operating pressure applied to move the ball. When it moved the reaction was so swift and powerful, the valve bonnet was cracked. The stem seals held so no catastrophe occurred, but the line had to be shut down to replace the bonnet. Use of speed retarders probably would not have helped. A hydraulic operator would have been much more appropriate. Subsea Shutdown Valve (SDV) Testing. Subsea SDV testing should include an annual test with the valve fully closed with leakage noted and corrected, and a biannual test for partial closure. Testing of the valve can be achieved from the surface providing there is a means to detect when the valve is cycling. (Provide for partial closure of the valve with a test stop. Use limit switches and a “Test Position” to allow testing without shut-in of the platform.) Pressure Venting. Pressure venting should not be necessary for subsea valves during production operations. However, the valve should be fitted with vent valves or plugs to allow safe maintenance.
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Bi-Directional Operations. Block valves should be designed to seal against design pressure from either direction. Pigging Operations. Pipeline riser design needs to accommodate pigging. Selection of bend radius is dependent on the types of pigs that will be used. For normal spheres or poly pigs, a long radius (1-1/2 diameter) is usually sufficient; however, in the North Sea and most other operating locations, the use of 5-D induction bends for risers is standard. To accommodate the passage of “smart” inspection pigs, a larger radius is required for small diameter pipe. In addition, some pipelines are pigged regularly and others have chemical injection to prevent/minimize corrosion problems, for example, lines having a high CO2 or H2S content in the gas. For pigging operations, the valve should be “throughconduit full bore”. Ball/check valve design should allow the passage of spheres or scrapers in either direction. Performance Acceptance Testing. Newly fabricated valves and actuators should be tested together on-shore under the simulated conditions, prior to acceptance by the operator, i.e., the actuator should be installed by the valve manufacturer and tested and actuated under load conditions in his shop. To enhance performance the design, manufacture and testing procedures of the valves and actuators should be thoroughly evaluated. Additional Design Considerations. Subsea valves should be removable, i.e., bolted-flanged or provided with a mechanical connector. Flanges should have ringtype joints. Lifting eyes for lifting the complete valve and actuator assembly should be provided. For large diameter pipelines, the flanges should be designed to spread hydraulically for gasket removal and reinstallation. A double seal design for the seats and stem is recommended. A top entry requirement for a ball valve is not necessary, but may be of interest for small diameter valves in very deep water. Consider having the contractor install a wrap-around sleeve to protect the flange gasket. Consider a shrink wrap. (Provide a rust preventative for the machined surfaces and also for bolting and caps.) The design of subsea valves should take into account external hydrostatic pressure. Water depth will influence selection of the installation method. Depth will also affect choice and difficulty of repair methods.
Subsea Valve Design Considerations and Specifications
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The subsea check valve shall be a lock open (by diver or ROV) design. This is a standard RTJ, flanged swing check valve.
•
A minimum ANSI 900 rating shall be used for the valves and flanges.
•
The subsea ball valve shall have a gear operator, with a position indicator and locking device, if the pipeline is greater than or equal to 8-inches NPS and a wrench. The gear box shall be pressure compensating type.
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•
The ball valve shall be manually actuated (by diver or ROV).
•
The valves shall meet the requirements of API-6D and ANSI B16.5 and B16.10, as a minimum.
•
Coal tar epoxy or the manufacturers recommended coating system, 3 coats minimum, shall provide external corrosion protection.
•
The ball valve shall have a 3-mil (minimum thickness, electroless nickel plated steel ball and be designed per the manufacturer’s recommendations for the Company’s intended service.
•
The subsea valves shall be removable and replaceable in-lin, i.e., bolted flaned.
•
The flanges shall have a ring-type joint, RTJ. The studs shall be B7M material, with a coating per the manufacturer’s recommendations for subsea service.
•
Lifting eyes for lifting the valve(s) shall be provided.
•
The flanges shall be designed to spread hydraulically for oval ring gasket removal and reinstallation.
•
A double seal design, compatible with the intended service, including corrosion inhibitors if specified, for the ball valve seats and stem shall be used. Ports shall be provided for seal injection by diver or ROV, if required for future valve maintenance. Design shall include sealant injection fittings with double ball checks, compatible for the service and the subsea environment.
•
Contractor shall install a wrap around sleeve to protect the flange gasket. Consider a Trenton wax tape. Contractor shall provide a rust preventative, compatible for service in the subsea environment for the machined surfaces and also for bolting and caps, on all valves and flanges.
•
Check and ball valves shall be “full conduit” and allow for passage of spheres or scrapers in either direction.
•
Two-inch NPS bleeder valve exclusions: 1) Lifting eyes, 2) ability to spread flanges hydraulically, 3) double ball check fittings for sealant injection, i.e., in the event of damage to the face seal, sealant can be injected through the drain fitting to provide a temporary seal, and 4) 3-mil (minimum) thickness nickel plating, i.e., use a 1-mil (minimum) thickness.
Maintenance of Subsea Pipeline Valves Subsea pipeline valves have a history of reliable service. Most of these valves are designed to not require periodic maintenance or seal lubrication. The majority of the maintenance operations on these valves are to repair flow path or stem seal leaks and actuators. Some of the common repair methods are as follows: •
Chevron Corporation
Leakage of subsea valves around the valve ball and seats or stem seals can sometimes be repaired temporarily by injecting sealants at the valve seats through ports provided for that purpose.
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•
Repair of an inoperable valve or permanent repair of seal leakage usually requires the replacement of the valve actuator, valve stem, ball or seats. Divers or ROV’s are used to assist in the repair. Large valve repair usually requires the retrieval of the valve to the surface and replacement.
The mobilization of equipment required for a major repair job is substantial (saturation diving, heavy duty lift crane, etc.) Other reported problems associated with subsea pipeline valves are: •
Failure of ball plating due to poor workmanship, corrosion and galling leading to a valve unable to adequately seal and isolate
•
Damage to the valve ball and seals by debris and pigging operations
•
Failure of valve stem to ball connection resulting in an inoperable valve
•
Improper material selection resulting in failure due to corrosion or mechanical breakage
Subsea Pipeline Valve Actuator (See Appendix G) The actuator for a subsea pipeline valve may be manually or remotely operated. Manually operated actuators can be designed for operation by divers or remotely operated vehicles (ROV’s). Remotely operated actuators are mainly hydraulically operated. Manual overrides for the hydraulic operators are sometimes provided and can be operated by divers or ROV’s. All remotely operated subsea ball valve actuators are hydraulically operated except in very shallow water where pneumatic operators may be used. There are two main types of hydraulic actuators for this application: a rotary piston operator and a rotary vane operator. Rotary Piston. The rotary piston actuator is available in both spring return (Figure 900-19) and double acting styles. The spring in the spring return type actuator provides a fail-safe action in case of a hydraulic failure. Rotary piston actuators are capable of producing a torque of 2,000,000 in-lb with 1000 psi hydraulic control pressure. Rotary piston actuators with spring return are generally limited to less than 200,000 in-lb of torque with 1000 psi hydraulic control pressure. Major manufacturers of this type of actuator are Shafer Valve Company, GH Bettis, and Kracht. Rotary Vane. The rotary vane type actuator is shown in Figure 900-20. It is not available in the spring return configuration. This type of actuator is capable of producing torques up to 5,800,000 in-lb. with 1000 psi hydraulic control pressure. Shafer Valve Company is the only major manufacturer of this type of actuator. For the double acting rotary piston actuator and the rotary vane actuator, fail-safe valve action will require subsea accumulators installed close to the actuator. Sizing of the actuator for a subsea ball valve must take into account the breakaway and running torque of the specific valve at its maximum operating conditions (consult the manufacturer), installation water depth plus the elevation of the valve
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Fig. 900-19 Typical Spring Actuator with Seaport
control system above sea level, and the hydraulic supply line size, and aging. There are two considerations: 1) Water depth plus the elevation of the control system to account for the hydrostatic head of the control fluid and 2) the hydrostatic head affecting the operator due to sea water in a case where the control line develops a leak. The Specific Gravity of common hydraulic control fluids ranges from 1.011 to 1.055. The actuator should be suitable for use with water or oil-based hydraulic fluid. Facilities should be provided for flushing the actuator, through a hose connected by a diver or ROV. The actuator design must provide travel adjustment to give accurate alignment of the valve ball for clear, free passage of pigs. (Valves with a stop built in at the time of manufacture are preferred to stops on the actuator.) The actuator should be designed for removal from and refitting to the valve subsea with the pipeline at pressure. Unique orientation of the actuator attachment to the valve is required. The actuator should be provided with a clear visual and tactile indicator showing the valve position to a diver or ROV. The indicator should be in line with the pipeline when the valve is open. The hook-ups (hydraulic control cable, attachment, fittings) for the actuator should be designed to be substantial to resist damage from the marine environment. Compatibility of the materials used should be considered.
Subsea Check Valves (Gas pipelines) Operators are increasingly considering and installing subsea emergency shutdown (ESD) systems in order to mitigate the consequences of a gas pipeline failure in the
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Fig. 900-20 Rotary Vane Actuator Features
vicinity of manned facilities (also see Section 958). Check/ball valves have been used as part of the shutdown systems in the North Sea at several locations. The location of the check valve with respect to the platform is an important consideration in this case. The same check valve manufacturer (Tom Wheatley of Houston, TX) has been specified on each occasion since it is one of the few check valve designs that allows the passage of spheres or scrapers in either direction. Check/ball valves have also been used in the Gulf of Mexico. Company experience has been primarily with Wheatley Gaso Inc of Tulsa, OK, a different valve company than Tom Wheatley. The Company has also used Wheatley check valves.
Reference Lists of Subsea Pipeline Valve Users/Applications Lists of subsea pipeline valve users/applications are contained in Appendix G.
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952 Subsea Pipeline Mechanical Connections General Subsea pipeline mechanical connections are needed during new pipeline construction, repair (see Section 971), or a lateral tie-in to a main line [3]. Connections can be made for a pipeline tie-in to a riser or between a pipe and a subsea-tap assembly. Connections can also be made between pipe segments to provide a continuous pipeline, such as in the case of a repair, when pipe segments are layed by different vessels, or when pipeline segments are towed to location from a distant fabrication site. In shallow water, connections can be made on the surface by lifting pipes to a vessel, making the connection, then lowering the pipe to the sea floor. In-line connection methods that connect two pipe segments, such as flanges or welding, can generally be used to connect the pipe and the riser. Other methods to connect pipe and riser include hyperbaric welding and J-tube (see Section 965). Good subsea positioning of the pipe ends to be connected greatly facilitates the connection process. Spool pieces may be used to bridge a gap, especially when connecting to a riser.
Mechanical Connection Methods Various mechanical connection methods/connectors exist for joining the ends of subsea pipelines. These methods include: • • • •
Flanged connection for pipeline-riser tie-Ins Flanged spool Angular misalignment (ball joint) assemblies Mechanical connector systems
(Other tie-in methods for pipelines and risers are generally discussed in Section 965.)
Flanged Connection for Pipeline-Riser Tie-Ins In shallow water, flanged connections are sometimes used for pipeline-riser tie-ins. Pipe spools, fabricated aboard a work vessel, may be used with flanges. Flanges are RTJ, ANSI Class 600 or 900 minimum rating. Alternatively, ball joints have been used to accommodate angular misalignment between the pipe and riser (discussed later). The spools may have right-angle or Z-bends to provide flexibility in accommodating thermal and pressure expansion. In many cases, rotating (swivel-ring) flanges are used to ease the installation. (One advantage of flanges is that they permit easier repair in the remote event of pipeline/riser damage or corrosion.) The Company has experience with standard flanges used in very shallow water, swivel ring flanges, and misalignment-ball joint flanges. The type of flange to be used is a function of the equipment, line size, water depth, and previous experience of the personnel involved. These have been used to install risers “in-board” of a platform, rather than using the “out-board” above water riser tie-in method which provides an all-welded connection. Experience has been good with flanged subsea
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connections; no problems of leaks after installation/testing have been reported. In the Gulf of Mexico, these are normally installed by divers from a jack-up or spud barge rather than from a pipelay barge.
Flanged Spool Method Flanges may be preinstalled on each pipe end during laying. The pipe ends are positioned approximately in line, with a gap in between. An adjustable fixture (template) is lowered to the sea floor and temporarily attached to the flanges. The fixture is locked in position, released, and raised to the surface. A rigid pipe spool is prepared to match the exact dimensions of the fixture, lowered to the seabed, and bolted into place. This method is generally limited to applications involving relatively small diameter pipe and shallow water, although rotating flanges have been used to 36-inch diameter in water depths to 500 feet in the North Sea. Flanges are low in cost, but they can take a long time to install. However, they are considered “trouble free” once they have been installed and tested.
Rotating (Swivel-Ring) Flange A rotating (swivel-ring) flange is used (by divers) on one spool end to facilitate alignment of the bolt holes in the flanges. It can be attached to a preinstalled conventional weld-neck flange (see Figure 900-21; this flange looks like a welding neck flange, but has a retainer and a rotatable ring). Swivel-ring flanges are typically available in 300 ANSI Class (12- to 42-inch OD pipe), 600 and 900 ANSI (3to 42-inch OD), 1500 ANSI (3- to 24-inch OD) and 2500 ANSI (3- to 12-inch OD). The Company has used these manufacturers: Preferred Machine Works, Southwestern Flange & Fittings Co., Coffer Flange, Cameron, HydroTech and Gripper. Fig. 900-21 Gripper Rotating (Swivel Ring) Flange
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Underwater Hydraulic Bolt-Tensioning Tool The process of tightening large flanges has been made considerably easier and faster by the use of a hydraulic bolt-tensioning tool. For example, the Hydra-Tight Tool, sold in the U.S. by Flexatalic Gasket Co., has been used by divers in the North Sea for many years. It consists of a series of hydraulically operated tensioners that are attached to the protruding ends of the flange studs. Hydraulic power provided from the surface causes the tensioners to tension each stud uniformly. The nuts may then be tightened in less time. The primary advantage, however, is uniform tensioning of the studs. This reduces the likelihood of a leak, especially for large flanges. (Another similar device is the Gripper-Snapper-Stud Tensioning System.)
Angular Misalignment Method — Single Ball Joint A variation of the flanged spool method is the use of a misalignment ball joint flange to accommodate angular misalignment. Small diameter lines (10.750- to 12inch OD or less) in 200- to 300-foot water depths may be lifted to the surface to make a connection using a ball connector. One end is raised by one or more lifting points. A ball-connector half is welded to this first pipe end. A joint or two of pipe is first welded on to bridge any gap between the two pipe ends. The first pipe end is lowered to the sea floor so that it overlaps the second pipe end. A measurement is taken on-bottom, and the second pipe end is raised to the surface. The pipe is cut, the second ball half is welded onto the pipe, and the pipe is lowered to the sea floor. The two pipe ends are then lifted slightly, and the ball halves are mated. The connected pipe is lowered to the seabed, and the bolts are tightened to lock and seal the ball joint. (If the pipes must be dewatered for lifting, temporary end “blind” flanges are attached to the ball halves, before the pipe ends are lowered. A small—perhaps 2-inch—ball valve allows the pipeline to be flooded or dewatered as needed. A laying/pulling head can be added to the blind flange to facilitate lowering/raising of the pipeline. After the pipes are flooded, the temporary end flanges are removed.) This method may not work on the first try, since each time the pipe is lifted some slack is pulled out. This could also be performed by aligning the pipelines, taking a measurement, and adding pipe.
Angular Misalignment Method — Pair of Ball Joints The ball connectors may also be used as a pair at the ends of a rigid spool for new construction or for a long spool repair where the pipe ends can be lifted to the surface. Measurement of the required spool length must be accurately made because the ball connectors will provide only limited length adjustment. Moreover, an axial movement of about one pipe diameter may be needed to make the connection.
Misalignment Flange — Ball Joint Connector The misalignment flange (MAF) is a special type of flanged ball joint connector that provides for angular misalignment between two pipelines being connected underwater (see Figure 900-22). It is a ball joint connector similar in principle to a
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standard ring joint flange, but with significant installation and functional advantages. The MAF uses a replaceable metal seal for high integrity and long-term sealing. Fig. 900-22 Hydrotech Systems–Misaligning Flange Ball Connector
The MAF may reduce the time needed for subsea pipeline and riser connections. Subsea assembly and make-up are accomplished by divers with the same tools used to assemble and tighten a standard flange. Forced alignment of the pipeline may not be necessary because an MAF allows up to 12 degrees of misalignment in any direction. Some manufacturers require a “pull-in” capability of only one-fourth the pipe diameter to mate the ball and housing. The Company has used these manufacturers: Hunting Oil Field Services—Big Inch Division, Cameron, HydroTech and Gripper.
CABGOC’s Experience with Spool Piece Construction Angular misalignment flanges (ball joints) are discussed above and in general. Cabinda Gulf Oil, CABGOC prefers not to use them and views them as a potential leak source. They allow the pipeline Contractor to use a spool for the pipeline to riser tie-in, but do not allow the use of a ball joint in this spool for misalignment. The spool must be hard piped and any misalignment made up with a 5D pipe band. They also require the Contractor to align the pipeline and riser to minimize misalignment as much as possible. CABGOC has never had a problem hard piping the tie-in and the equipment used to measure distance and angle for the spool fabrication is normally very accurate so there hasn’t been a problem with repetitive modifications to the spool to make it fit. The spool does have swivel ring flanges on each end.
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Mechanical Connector Systems Several mechanical connector systems are available for in-line subsea pipeline connections. These include the Big Inch (FlexiForge), the Cameron connection system (Camforge), the Gripper connector system, and the HydroBall/Hydrocouple system by HydroTech [3]. Mechanical connector systems are faster and less expensive than hyperbaric welding. Also, they can be less costly to install than surface tie-in methods, but require about the same amount of time to complete. The installation is also less weather sensitive than surface welding, which may be an important advantage in bad weather areas. Mechanical connector systems consist of a means for attaching the connector to the pipe on the sea floor, provisions for length adjustment, ball joints, and a rigid pipe spool. A means of manipulating the connector assemblies may be provided by the installation contractor or by the equipment manufacturer. The manipulating equipment can take a variety of forms; the choice is normally made by the installation contractor or the operator. If the pipelay contractor uses his lay barge as a work platform, the barge davits can be used. In deep water, inflatable airbags may be used to buoy the connector assembly off the bottom. For small pipe sizes up to about 12 inches, a simple A-frame may be sufficient with “come-alongs” to maneuver the assembly into position. For large pipe sizes, an alignment frame may be of benefit. (Subsea cranes have been used in the North Sea and offshore Indonesia.) Gripper and HydroTech offer special bottom-manipulating equipment for use with their connector systems. Very large alignment frames, as used for hyperbaric welding, are not normally required with these mechanical-connector systems because precise alignment of the pipe ends is not necessary.
Big-Inch Marine Systems Big-Inch, a division of Hunting Oilfield Services, is best known for its Flexiforge end connector, a means for cold forging a fitting onto the end of a pipe on the sea floor. However, Big-Inch has also developed a complete connector system for new construction. This includes either conventional ring joint flanges or boltless flanges to connect the system to the pipe ends, ball joints, and slip joints. All components have metal-to-metal seals. Each component may be disassembled on the sea floor by unbolting, if it becomes necessary to remove the system. The boltless flange is a hydraulically operated mechanical pipe connector, designed to effect rapid connection in lieu of a bolted ring joint flange. The slip joint provides axial adjustment of up to several times pipe diameter, facilitating pipe section or spool piece length adjustment. The Flexiforge System consists of a cold forging tool and associated power and control equipment that is used for installing end connectors. The tool forges an end connector on to a pipe to make a mechanically-joined, 100 percent metal-to-metal sealed connection, stronger than the pipe. The tool is available in a range of sizes
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from 6 to 36 inches. The finished connection has a smooth inside surface that does not impede production or pigging operations. The Company has used this device on pipelines in the Gulf of Mexico.
Cameron The Cameron in-line connection system includes two collet connectors with integral or separate actuators and positioners, four pipeline swivels, and two rigid pipe spools. A mating Cameron hub with a tie-in base is pre-attached to each pipe end to be joined. (The Camforge tool may be lowered to the sea floor and used to cold forge the ends of the pipeline to the collet connector mating hubs.) Temporary end caps are required for each pipe end to retain air in the pipelines during laying and positioning. These may be attached by means of Cameron clamps. The Company has used the Cameron system on pipelines in the Gulf of Mexico. The system may be operated from a work vessel equipped with a crane or other equipment to lift the spool assembly. Guide cables are attached to each tie-in base. The spool is made to the correct length with swivels and collet connectors welded in place. The spool assembly is attached to a spreader bar and lowered on the guide wires to the sea floor. Once the assembly is on the bottom and the connectors are landed on the two tie-in bases, a diver operates controls to position each connector and actuate the collet fingers to grip the mating hub and effect the seal. The seal made by each connector is then tested to confirm integrity of the connection. Then the actuators and support equipment are retrieved for re-use. Up to four swivels may be used to provide the required axial movement of the connectors and to accommodate misalignment. (Cameron’s length compensating joint can shorten the overall required spool piece length significantly. This joint can be used to replace the midpoint swivels and to facilitate handling.)
Gripper (Now part of Hydrotech) Gripper offers the Grip and Seal Mechanical Coupling (GSMC) and Gripper Ball Connector - Flange LOK (GBCFL) devices for new construction and repair. The GSMC unit incorporates metal tension and compression gripping collars and soft packing in a cylinder that slips over a pipe end. It is set and sealed by tightening a series of stud nuts, and it may be removed from the pipe by loosening the nuts. The Company has used the GSMC on pipelines in the Gulf of Mexico. The GBCFL unit is a ball-joint flange with metal-to-metal seals. It is designed to “make-up” pipe connections that are out of alignment up to 10 degrees. The Gripper Metal Seated Coupling unit slips over and seals against the cut end of a pipe. The unit has no provision for length adjustment. It is intended for riser repairs where the riser pipe can be machine cut to provide a smooth sealing surface. It could also be used to attach a flange or fitting to a pipe on the seabed, provided that the pipe end is machine cut. The Gripper Pipe Length Compensator (GPLC) device is a slip joint intended for new construction. Metal seals are set against a machined cylindrical surface. The GPLC unit is used in a spool, with a GBCFL unit at each end.
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HydroTech HydroTech manufactures several products for pipeline connections. The main products include the HydroBall/HydroCouple System, the misaligning flange (MAF), and the HydroBall swivel and bias-cut flange. The Mark IV HC units include gripping and sealing mechanisms, along with temperature compensation, and have not experienced leakage. The Mark IV unit is hydraulically set with separate tension and compression slips. The seals are separately actuated metal-contained elastomers. The Mark V unit is a more compact tool with interfacing tension and compression slips and metal-contained seals. The slips and seals are set simultaneously by tightening a ring of bolts. The device structurally attaches to and seals off bare ended pipe. It also provides telescopic adjustment of one pipe diameter or 12 inches, whichever is greater. The telescopic adjustment allows for error in diver measurement when preparing the spool piece and will also provide the necessary adjustment to accommodate ball swallow. The Pressure Balanced Safety Joint by HydroTech Systems is a pipeline fitting designed to separate at predetermined externally applied loads, independent of pipeline pressure. It functions when a dragging anchor, mud slide or other external force is applied to the pipeline. Employing the Pressure Balanced Safety Joint with a check valve eliminates loss of pipeline content. In the event of an accident, this will assure minimal environmental damage.
Subsea Lateral Tie-In to a Mainline In some cases, it may be necessary to provide for a lateral pipeline tie-in to a subsea mainline. If the operator is aware of the future need for a tie-in, then the mainline can be laid with a side tap assembly and temporary spool as shown in Figure 900-23, Step 1 (shown using HydroTech equipment as an example). (An unplanned tie-in could require a subsea hot-tap.) Any lateral tie-in to a mainline should consider the need to be able to pig the lateral. We do not use the welded-in valves as shown in the figure, but bolted [40]. In U.S. waters, 30 CFR Part 250 — “Oil and Gas and Sulphur Operations in the Outer Continental Shelf - Final Rule” dated April 1, 1988, Subpart 250.154(b)(6), “Safety equipment requirements for DOI (Department of the Interior) pipelines— states that ”Pipelines incoming to a subsea tie-in shall be equipped with a block valve and FSV, flow safety valve (check valve). Bidirectional pipelines connected to a subsea tie-in shall be equipped with only a block valve." (See Section 958.) In the Gulf of Mexico, CUSA’s GOMBU has previously installed 24 lateral tie-ins, with valves having an ANSI 900 rating, in most cases, in sizes to 20 inches. (The block valve is a manually actuated ball valve). The valves for a single direction lateral are shown in Figure 900-23, Step 3. Figure 900-23, Step 2 shows the lateral line, as laid, with the temporary spool and anchor flange bracket removed. Figure 900-23, Step 3 illustrates the tie-in spool assembly, after lowering from the surface as attached to the side tap assembly and
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Fig. 900-23 Subsea Lateral Tie-in
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to the anchor flange bracket. This assembly is then attached to the lateral pipeline using a swivel ring flange, with provision for misalignment using a spool piece and an MAF.
Side Tap Installation Procedure The in-line side tap valve assembly installation procedure is designed to ensure that the assembly is properly buoyed with temporary buoyancy that will cause the assembly to be landed on the seabed in a near vertical orientation. The orientation of the main subsea ball valve stem should be within plus or minus ten (10) degrees of vertical in its final position on the seabed (i.e., the ball and check valves, RTJ flanges, temporary spool, blind flange and 2-inch NPS “bleeder” valve shall be located directly above the pipeline). Two anchor flanges should be provided to structurally support the side tap assembly. During installation, the orientation of the assembly should be visually monitored to determine that it is within this required orientation tolerance. After the lateral tie-in has been placed on bottom, the Contractor should place sandcement or grout bags around the assembly for protection. The sand-cement or grout bags and filler should be the same as that specified for pipeline crossings. Further detailed design considerations and specifications for a side tap assembly may be found in [39].
Underwater Branch Connection Study (PRC/AGA/R.J. Brown) [54] This report was prepared with the object of developing guidelines for designing underwater connections of branch lines at existing tap valves and hot taps in diver accessible water depths. The report considers ANSI Classes 600 and 900 branch lines of up to twelve (12) inches nominal diameter that conform to API Specification 5L. Loads due to gravity, buoyancy, internal and external, thermal expansion, hydrodynamics and random events are considered. External corrosion, temperature cover, bottom conditions, stability, testing, commissioning, trenching, and pigging are also addressed. A general discussion of these issues is included in the body of the report. Methods of analysis are included in the appendices and in various references. “Lotus 123" spreadsheets that compute the expansion stresses resulting from pressure and temperature at points on a generic piping geometry are presented. A program diskette is included with the report. Future requirements should be considered when the initial pipeline is being designed and when a branch connection is planned. If future connections are anticipated, additionally tap valve assemblies should be installed at strategic locations in the main line and when a branch line is being connected, provisions should be made for additional connections at that point. Before any branch connection is installed, the extent and nature of pigging requirements should be decided. If a wye connection is not required, hot taps can be used where a tap valve assembly is not available. Wye connections cannot be installed with a hot tap. It is,
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therefore, particularly important to anticipate types of “through-pigging” which require a wye connection.
953 Concrete Weight Coating (Also see the Coatings Manual, Specification PPL-MS-4807 and Appendix H.)
Design Considerations Concrete Weight Coating Thickness. Offshore pipelines are weight coated for two reasons. The primary reason is to give the pipeline negative buoyancy for onbottom stability. A secondary reason for weight coating is to protect the underlying corrosion coating from mechanical damage. The weight coating concrete density and thickness are determined by the on-bottom stability design, see Section 935. Concrete Slippage and Surface Sliding. Pipelay analysis will determine the axial tension required during pipe laying to avoid line buckling on the lay barge; axial tension is applied to the pipeline by the tensioner as a shear force on the concrete coating surface. The weak link in the shear transfer from the tensioner to the pipe is typically either the tensioner link slipping on the concrete surface or the concrete slipping at the concrete/corrosion coating interface. Surface sliding is minimized by increasing the grip pressure or by increasing the pipe/tensioner link contact area. A spacer installed over the bare pipe joints prior to their entering the tensioner provides added contact area and resistance to slippage from the next joint. The likelihood of slippage of the concrete at the concrete/corrosion coating interface is largely dependent on the type of corrosion coating. Experience has shown that coal tar enamel and asphaltic wrap coatings typically do not have a problem with concrete slippage. However, fusion-bonded epoxy (FBE) coatings do not develop as high a shear strength with the concrete weight coating and are susceptible to slippage. Concrete Weight Coating Slippage Calculations. Using concrete/corrosion coating shear data [9] and the contact area of the contractor’s proposed tensioner, the maximum “Safe Tension” can be estimated. An example calculation is given in Figure 900-24. Avoiding Concrete Slippage. Research and experience have shown that concrete slippage problems on FBE coated pipe can be avoided in several ways [10,25]. In order of decreasing effectiveness, these include:
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•
Two Part Epoxy: A two part epoxy mix is applied just a half rotation before the compression of the concrete. The epoxy wicks into the moist concrete and adheres to the surface of the FBE and upon curing provides a mechanical lock between the two.
•
Rough Band: On the bow end (i.e., the last part in the tensioner) of each pipe joint, prior to weight coating, a 40-inch-wide circumferential band of 15-milthick liquid epoxy is applied to the FBE coating and small flint chips are
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embedded in the liquid epoxy while it is curing. Meticulous care must be used when handling and transferring the pipe to the welding line on the lay barge or both ends should be coated with the rough band to assure that the banded end is properly oriented relative to the tensioners. •
Ring: On both ends of each pipe joint, a 1-1/2-inch high and 3-inch wide ring of cementitious epoxy is applied prior to weight coating.
•
Barrier Coating: Along the entire length of the joint, an 80-mil polymer cement intermediate (or barrier) coating is applied prior to weight coating. This intermediate coating is temperature cured and is usually applied in the coating mil by the coating applicator immediately following the FBE coating while the pipe is still warm.
•
Raised FBE Spiral: During FBE application, a 20-mil high and 0.2-inch wide spiral of FBE is superimposed on the pipe joint.
Tests have shown that the rough band and epoxy cement ring methods are the most economic and effective methods of avoiding concrete slippage. Barrier coating (an option when the concrete weight coating is applied by the impact method) and epoxy spirals decrease the chance of slippage, but do not always prevent it. Avoiding Concrete Slippage on Plastic. The best method to avoid concrete slippage on multi-layer plastic pipeline coatings systems like Himont, Elf Atochem, DuVal, and Du Pont Canada is to apply a suitable plastic powder with a sintering weir onto the pipe surface to create a rough (sandy) surface condition. It is important that the plastic powder “bites” into the extrusion layer to anchor it, but still leaving a rough, textured finish. This must be done immediately after the application of the extruded outer plastic jacket and before the cooling step in the pipe coating mill." Other Damage. The concrete weight coating is susceptible to damage other than slippage at the corrosion coating/concrete interface. The tensioner grips can slide on or crush the concrete surface. Assuming the concrete is adequately reinforced, these grip pressure problems can be minimized by optimizing the grip pressure; the grip pressure should be high enough to prevent slippage, but low enough to avoid localized crushing of the concrete surface. The concrete can also crack; either circumferential or longitudinal cracks can occur. Longitudinal cracks result from inadequate reinforcement or from excessive grip pressures. Recent tests have shown that longitudinal cracking of the concrete may occur when the out-of-roundness reaches 1.375 percent, due to excessive grip pressure and compression. Some circumferential cracking will always occur when the pipeline is put into tension as it passes over the stinger and into the sag bend. Cracking is only detrimental if it results in significant spalling (i.e., loss of weight) of the concrete. In some cases circumferential cracking can be significant. The reinforcement and axial tension in the pipeline will influence the severity of circumferential cracking. If the concrete coating is not adequately reinforced, circumferential cracks can permit significant spalling of the concrete to occur.
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Fig. 900-24 Example Tensioner Slipping Calculation An example derrick lay barge uses a single dual-track tensioner machine. Each track is equipped with 14 links in contact by two points to the pipe. The width of a link is 220 mm. The length of contact area per track is 3,080 mm. There are two tracks. The lateral pipe loading (compression) capabilities of the tensioner is a maximum of 80 metric tonnes on each side of the pipe. The tensioning band is adjustable such that the variations of the tension around the nominal value will not create an action of the machine. Assumptions: Pipe Diameter Width of Link Length of Contact Open Length Between Joints Effective Length of Contact Assumed Contact on Circumference
= 24 inches = 220 mm = 0.722 foot = 3,080 mm = 10.10 feet = 2 feet = 8.10 feet = πD/3
Area = 8.10 x 12 x 24 π/3 = 2,443 in2 (Eq. 900-41) Calculations: Tension test information, for a FBE corrosion coating and wrapped applied concrete coating, obtained as part of the Shell Deepwater Pipeline Joint Industry Project (JIP) dated 3/16/77, indicates the following: Failure Shear Stress = 41.6 psi The corresponding “Failure Tension” for a 24-inch O.D. line is: 41.6 x 2,443 = 101,621 lb = 46.1 metric tonnes (Eq. 900-42) The first “safe” test value is 35.9 psi, i.e., the"Safe Tension" is: 35.9 x 2,443=87,698 lb = 39.8 metric tonnes If we assume an effective contact length of only half of the track length, the design allowable value of tension would be 24.8 metric tonnes, giving a safety factor of 1.6 over the “Safe Tension” of 39.8 metric tonnes. The JIP performed a second test using a higher value of lateral pipe loading (compression). For this case, shear stress reached a value of 49.6 psi without failure. This is a factor of 1.38 above 35.9 psi. The amount of grip (compression), therefore, does affect the slipping of concrete wrapped coating upon FBE.
Circumferential cracking of the concrete is more of a problem with coal tar enamel (CTE) and asphaltic wrapped coatings. These coatings are not as prone to concrete slippage, hence higher axial tensions can be applied to the pipeline, making cracks more likely. Detrimental circumferential cracking is typically not a serious problem for FBE coated pipelines, because the concrete will slip before it cracks. If the concrete is successfully inhibited from slipping, circumferential cracking might be a problem on FBE coated pipe.
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Concrete Application There are two primary ways of applying concrete weight coating: the compression wrap method and the impact method. The compression coat wrap method is preferred, but the impact method is acceptable. Compression Wrap Method. The compression coat method is a relatively new proprietary process. It has been commercially available since 1975. The commercial name is “Compression Coat.” Capabilities of the Compression Wrap Method. The compression wrap method has been used on pipe sizes NPS 3 to NPS 54. The concrete thickness applied has varied from less than 1 inch to 7.5 inches and the density from 140 to 190 lb/ft 3. For pipe sizes NPS 4 to NPS 24, typically a density of 140 pcf is preferred. For pipe sizes greater than NPS 24 or thickness greater than 2.75 inches, 190 pcf density should be considered. The pipe joint length (usually 40 feet) can vary from 26 to 80 feet. Description. Refer to Figure 900-25. Concrete is fed from a mixer through a hopper and onto a polyethylene outer wrap which is supported by a delivery belt. The concrete coating is put into compression by loading this belt and compressing the concrete between the outer wrap and the pipe. Hence the derivation of the trade name “Compression Coat.” The concrete is wrapped onto the rotating pipe in a continuous spiral about 6.5-inches wide beneath the polyethylene outer wrap. The edges of the spiral are formed to ensure that the seam is adequately joined. The concrete thickness is accurately controlled by an adjustable compaction roller on the underside of the (pipe) end of the material delivery belt. At the same time, through another preset adjustable guide on the applicator, the specified reinforcing wire is fed through at the same rate as the polyethylene outer wrap. The distance between the reinforcement and corrosion coating (as well as the polyethylene film) is controlled by guides built into the rear of the feed applicator. Following application, the weight coating ends are cut back, the pipe is weighed, and stacked for curing. For the joints which require anodes or buckle arrestors, the green concrete and reinforcement are cut back prior to curing; the anodes and buckle arrestors are attached after the concrete has sufficiently hardened to handle in the yard. In the case of pre-installed “welded-in” buckle arrestors, the concrete may be applied over the entire pipe length as normally done. Because the concrete is in compression by the outer polyethylene wrap, freshly coated small diamter pipe can be immediately stacked. Typically, pipe diameters up to NPS 24 with up to 3.75 inches of concrete can be stacked immediately. Reinforcement Compression Coating. There are two ways to reinforce compression wrapped concrete. Compression coat’s standard mesh is Bekaert (Belgium) Armapipe, a spot welded netting made of galvanized low-carbon steel. The mesh compreises 8 line wires which are deeply crimped in the jiddle between cross wires. The second way is a generic wire mesh. Some specifications call for wire reinforcement which is a wire mesh with dimensions, 1-1/2 inch x 17 gauge for NPS 10 and above and 1-inch mesh by 18 gauge for smaller pipe. Both provide adequate cross sectional area of steel mesh under normal conditions to keep the concrete in place.
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Fig. 900-25 Compression Wrap Method of Concrete Application
The compression coat method does not typically have longitudinal reinforcement. However, in addition to the wire mesh, a continuous spiral of 8-mm rebar has been successfully introduced into the concrete coating during application. The reinforcement should be isolated from the pipe, so that it is not electrically bonded to the pipe cathodic protection system. For concrete thickness greater than 2.75 inches, two layers of wire mesh are used.
Impact Method This method is the original method of applying concrete weight coating to corrosion coated pipe. Description. The corrosion coated (and intermediate coated if FBE or 22-mil dry film thickness if FBE) pipe is supported on its ends, rotated, and passed in front of the throwing unit. The throwing unit applies the concrete by using a belt/brush unit or a belt/belt unit which is counter rotated at high speed. The concrete is impinged on the rotating pipe until the required thickness is obtained. Surface scraping to remove irregularities and a spray-applied curing compound complete the process. Pipe weight coated by the impact method should not be stacked until the concrete has sufficiently cured.
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Reinforcement. Impact concrete weight coating can be reinforced in one of two ways: •
At the same time as the concrete application, depending on the thickness of the applied weight coating, one or two layers of woven hexagonal wire mesh are spooled onto the pipe.
•
Prior to the concrete being applied, a rebar cage is attached to the pipe. The rebar cage would typically consist of 8-mm diameter circumferential bars at 100-mm longitudinal spacing with 5-mm diameter longitudinal bars 30 degrees apart around the circumference.
Advantages and Disadvantages of the Impact and Compression Coat Methods Compression Coat Method Advantages:
Does not require an intermediate coat to protect the FBE corrosion coating Uniform concrete thickness, therefore good adherence to weight tolerance Sizes to NPS 24 may be stacked immediately after coating The polyethylene outer wrap allows consistent concrete curing Plant is portable for large orders
Impact Method Advantages:
May be the only method available for small orders in some parts of the world Can improve the longitudinal reinforcement by using a reinforcing cage
Disadvantages:
Requires an intermediate coating to prevent damage of the FBE corrosion coating or an FBE dry film thickness of 22-mils nominal Concrete coated pipes can not be stacked until the concrete is cured
Pipeline Installation Weight Coating of the Joints. Weight coating of the joints provides protection of the field joints. The joints need not be weight coated if the stinger arrangement will not damage the joint coating during pipe laying and the joint does not require weight coating for protection during service. (However, the on-bottom-stability analysis, see Section 935, should account for any missing joint material.) The contractor should determine if the absence of field joint material will cause unacceptable high stresses locally on the pipe during laying.
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Concrete Coating Repairs. Following installation, the line should be inspected by an ROV or diver. Cracks need not be repaired. Loose or spalled concrete up to 10 percent of the area of the pipe joint should be acceptable, with no need to restore the nominal design negative buoyancy. Damage in excess of 10 percent of the area should be reviewed to determine the need to restore the nominal design negative buoyancy. Negative buoyancy can be restored by placing grout or sand bags over the pipeline. Weight coating of oil pipelines is normally only required for the purpose of pipe installation. The repair decision should be based upon the inservice requirements, as well as constructability.
954 Corrosion Coatings Pipeline Coatings For more information on pipeline coatings, see Sections 340 and 953 in this book, and also see the Coatings Manual. Common Offshore Pipe Coatings. Most new offshore pipelines are coated with fusion bonded epoxy (FBE) or coal tar enamel which should be used up to an operating temperature of 200°F. FBE at 14-mil dry film thickness (DFT) is limited to 150°F, but for higher temperatures, 30-mil DFT should be used. If the pipe is to be concrete coated using the impact method of application and a FBE corrosion coating is to be used, then the DFT should be 22-mils rather than only 14-mils to prevent damage to the FBE during application of the concrete. This method of application was successfully used on the Papua New Guinea, Kutubu offshore loading line. Tests were run by the Contractor prior to acceptance of the winning bid to verify the method. (FBE can be purchased using Company Specification COM-MS4042.) (A typical density of FBE is 87.4 pcf. For coal tar enamel a range of thicknesses from 94 to 156 mils is appropriate. Typically 94 mils is used for non-weight coated and 156 mils for weight coated pipe. The typical density of coal tar enamel is 92.7 pcf.) New lower moisture absorption FBE pipeline coatings now exist such as Scotchkote 226N and O’Brien NapGard “Gold” 7-2501/7-2504). Presently, offshore experience with these new FBE pipe coatings systems is very limited. New offshore pipeline coating systems that many pipeline operators are using in the operating temperature range of 200 to 235°F are multi-layer pipe coating systems such as DuVal, Elf Atochem, and Himont. this new pipe coating uses FBE as a primer with either a single or two layer polyoropylene outer jacket. Joint Coating Options. The field joints for offshore pipelines are typically covered by shrink sleeves. Shrink sleeves are available with various temperature ratings; the shrink sleeve selected should have an adequate temperature rating for the intended service. Currently, heat shrink sleeves are not available for the new multi-layer polypropylene pipeline coating systems. Check with CRTC M&EE (Materials and Equipment Engineering, Richmond, CA) for updated information on coating the field joints of this new pipeline joint coating system and for pipe coating specifications.
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The girth welds of FBE pipe joints can be coated with FBE on the offshore lay barge. Field applicators of FBE include: Commercial Resins Company (CRC), Commercial Coating Services Incorporated (CCSI), and Pipeline Induction Heat (PIH). The girth welds of multi-layer polypropylene coating pipe joints can be coated with a two layer polypropylene pipe coating on the offshore lay barge. Field applicators of the two layer polypropylene girth weld coating system include: Commercial Coating Services Incorporated (CCSI), and Pipeline Induction Heat (PIH).
Pipeline Riser and Conductor Coatings Different coatings are used to protect the pipeline risers and conductors in the splash zone. The most common riser coatings are rubber and Monel. Epoxy splash zone coatings are also used. Rubber. Vulcanized rubber (e.g., Mark Tool Splashtron) is used on pipeline risers and conductors operating at temperatures up to 160°F (special formulations are good to 200°F). The elastomer EPDM (ethylene propylene diene polymer) has been used at 212°F and can probably go even higher. These coatings are applied by hot vulcanizing the rubber directly to the steel in an autoclave. The main disadvantage is availability and scheduling, because the pipe to be coated must be sent to the applicator’s shop. The rubber is not easily damaged, but when damaged it is nearly impossible to repair. Mark Tool has repair kits available. For risers in the splash zone the Company typically coats a 40-ft joint with 1/2-inch of Splashtron or equivalent for later offshore installation. For J-tube risers the entire length of riser pipe to be pulled inside the J-tube is coated with a 1/2-inch thickness of Splashtron or equivalent. A Splashtron or equivalent stopper is coated on to the bottom of the riser pipe to later seal with the mouth of the J-tube during installation and prevent seawater from entering the annulus. The annulus is then filled with corrosion prevention chemicals. Some suppliers propose attaching the rubber with an adhesive to allow field application; this procedure is not the preferred method of application. Application with an adhesive will typically have a lower reliability and temperature rating than rubber attached by vulcanizing. Monel. Monel sheathing is used on risers and conductors at temperatures up to 250°F. The disadvantages of Monel are high cost and risk of damage during installation. The Monel can be repaired by either dry welding or using an underwater epoxy repair compound. Epoxy Splash Zone Coatings. Epoxy splash zone coatings (e.g., Ameron Tideguard) are used on risers and conductors operating at temperatures up to 140°F which are not pressure tested. The coating is usually applied above the riser sheathing up to an elevation of plus 12 feet. Pressure testing of the line can cause the coating to crack. Epoxy splash zone coatings are the cheapest option for protection of the riser. As with any corrosion coating, the surface preparation and application methods are critical for satisfactory service performance.
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Grout Filled Steel Sleeves. Grout filled steel sleeves, similar to monel, provide a seal which protects the riser from impact and corrosion.
Internal Corrosion Control NACE RP-01-75 should be followed for design, installation and evaluation of the results of an internal corrosion mitigation program (see API RP-1111). Where necessary, internal corrosion may be mitigated by one or more of the following: Running pipeline scrapers at regular intervals, dehydration, inhibition, bactericides, oxygen scavengers, and internal coating. The variables and severity of each case will determine the preventive methods that should be used. A monitoring program should be established to evaluate the effectiveness of the internal corrosion mitigation systems or programs. Appropriate corrective measures should be taken when evaluation indicates that protection against internal corrosion is required. (For assistance in evaluating inhibitors, contact CRTC’s Materials and Equipment Engineering Unit in Richmond, CA.)
955 Insulation Submarine pipeline insulation is rarely required. Heat tracing may sometimes be added to an insulated pipeline. The following information is from a Joint Industry Project (JIP) [11]. (The reader is cautioned to get CRTC’s Materials and Equipment Engineering Group and CPTC’s Offshore Systems Division involved early in any insulated subsea pipeline project.) Concrete coating and/or burial provides limited insulation when required.
Design and Installation of Insulated Submarine Pipelines Insulated submarine pipelines have been installed in several locations worldwide since 1973. Most of these pipelines have been relatively short distance lines with small diameters. There is a trend toward larger diameter and longer length insulated pipelines driven by the development of offshore oil/gas reservoirs which have less favorable characteristics (high pour point, waxy crude oil, or wet gas) or are in/offshore arctic regions. Because insulated pipelines designed for subsea applications represent an integration of several specialized technologies when compared to conventional offshore pipelines, there are some critical areas where present industry experience and technology are limited. Reference [11] addresses relevant aspects of insulated submarine pipelines and provides a rationale and technical basis for: • • •
Selection of cost effective materials Establishment of design considerations Evaluation of installation methods
The JIP addresses the interrelated aspects of corrosion prevention designs, insulation integrity monitoring, damage prevention, and compatible repair methods to assist in providing guidelines for developing a thorough design and operating philosophy for use during conceptual/preliminary engineering of specific insulated submarine pipeline projects.
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Budgetary cost data are also provided as a basis for evaluating and selecting insulated pipe designs, materials, and installation methods. These data indicate that the total installed cost for an insulated deepwater pipeline is about double that of the line without insulation.
Insulated Pipeline Design Concepts Insulated pipelines generally consist of the following components: •
Carrier pipe
•
Insulation material
•
A protective casing or jacket pipe to protect the insulation
•
A corrosion prevention/coating system
•
A concrete weight coating
•
Water stops or bulkheads to seal the ends of each pipe joint to prevent water intrusion at the field joints
Existing insulated pipeline design concepts vary for shallow water and deepwater applications, with major differences in the design/selection of the protective casing and insulation materials. Three commonly used insulation design concepts are as follows: •
A polyethylene (PE) or crimped steel jacket/high density polyurethane foam (PUF) system
•
A steel pipe/low density PUF system
•
A rubber jacket/PVC foam system
Typical cross sections for the above design concepts are depicted in Figure 900-26. A review of progressive technical developments indicates that material selection and design criteria for water stops or bulkhead integrity and corrosion prevention vary significantly and in many cases are inconsistent. For shallow water applications, brush applied bitumastics, butyl rubber tapes, PE based heat shrinkable sleeves, and polyurethane elastomers have been used for water stops or end seal coatings in conjunction with a PE or crimped steel jacket. For deepwater applications (greater than 150 feet) a steel casing pipe is sealed and structurally connected to the interior (carrier) pipe at each end by either a welded or forged bulkhead. Corrosion prevention coatings used on the carrier pipe exterior surfaces include fusion bonded epoxy, coal tar epoxy, polypropylene, and inorganic zinc primer. Sometimes, corrosion coatings are not used. Although not explicitly discussed in the literature, all operators and design engineers contacted during the JIP expressed concern about the lack of commercially available high temperature resistant corrosion prevention coatings. This concern is compounded by questions regarding protective casing and insulation material shielding effects on an effective cathodic protection system. (The Company has tested high-temperature pipeline coatings.
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Fig. 900-26 Insulation System Design Concepts
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Results are available upon request from CRTC’s Materials and Equipment Engineering Unit; see Reference [18].) Relevant insulated pipe/tubular design concepts that have potential for subsea applications are also reviewed in Reference [11]. These concepts include insulated well casings or tubulars used for downhole or steam injection applications. The applicable experience noted for the insulated casings/tubulars are the welded annular seal designs and the prestressing technology developed specifically for high-temperature applications. Finally, the review includes insulated and heat traced flexible pipe.
Insulated Pipeline Installation Methods Insulated submarine pipelines have been installed by the lay barge, reel, bottom tow, and mid-depth tow methods. (See Sections 961 and 980). For offshore insulated pipelines installed to date, there have been no reported failures of insulation systems during installation or while in service. However, continued performance of existing offshore insulated pipelines (up to a 30-year design life) is dependent on the long-term reliability of the end seals and the effectiveness of the corrosion prevention system design.
Company’s Joint Venture Experience-Insulated Pipelines The Company has participated in several Joint Venture Projects which included insulated pipelines. South China Sea Offshore Indonesia, Udang “A” - Operated by Conoco. In 1978, Conoco installed dual insulated 1.1 mile long 8-inch diameter pipelines in the Udang “A” Field offshore Indonesia in a water depth of 300 feet. The dual lines required insulation in order to carry 100 deg F pour point crude oil. The lines were insulated with 1.25-inch thick, banded 9.6 pcf rigid polyurethane and protected by a 12.75-inch O.D. steel outer casing. The casing is sealed and structurally connected to the interior pipe by a welded steel bulkhead at each end of the 40-foot long joints. Syntactic foam was rejected because of its high water absorbency at 150 psi hydrostatic test pressure and 200 deg F. Installation was by the lay barge method. South China Sea Offshore Indonesia, Udang “B” – Operated by Conoco. In 1980, Conoco installed dual insulated 3 mile long 12-inch pipelines connecting the Udang “B” Field with the Udang “A” offshore platform. The lines were insulated with 2.2-inch thick, 3.2 pcf polyurethane foam and each protected by an 18-inch steel outer casing. Steel end washers were attached to provide a water tight seal and pressure tested to insure water tightness. Installation was by a combination derrick and lay barge method. Insulated Pipeline Study - Santa Inez Unit Development Project - Option A Hondo “B” - Pescado - Operated by Exxon. This study [12] determined the feasibility of designing, fabricating and installing two 20-, 14-, 12.75-, or 10.75-inch insulated steel jacketed subsea oil/water emulsion pipelines. One of the lines was to run a distance of about 6.5 miles from the Pescado Platform, located in a 1,082-foot water depth, to the Hondo “B” Platform, located in a 1,183- foot water depth. The maximum water depth along this route is 1,350 feet. The other pipeline was to run a
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distance of 3 miles from the Hondo “B” platform to Exxon’s existing Hondo “A” platform in a 840-foot water depth on OCS Lease P-0188. A unique feature of this project is that insulated subsea pipelines have never before been installed in this depth of water. Pearl River Mouth Basin of the South China Sea, Huizhou 26-1, Operated by ACT. Huizhou 26-1 is located in the Pearl River Mouth Basin of the South China Sea at a water depth of 360 feet. Insulated pipe joints were fabricated utilizing the Snamprogetti Double Pipe Insulated System.This system consists of concentric 12.75-inch O.D. and 16-inch O.D. pipes. The pipes are connected using a proprietary tapered Special Joint Connector at each end and then filled with 3.1 to 3.7 pcf polyurethane foam. The 12-inch pipe is welded at each joint. PVC was considered but would not retain its long term insulating characteristics if exposed to high operating temperatures and hydrostatic pressure. Installation was by the laybarge method. North Sea, Alba Field Development Project. A 1.6 mile bundle carrying a 4.5inch O.D. fuel line and an insulated, 12.75-inch O.D. oil export line was installed in the Alba field, located in the North Sea in a water depth of about 450 feet. Alba crude does not have a high pour point. Insulation was specified to minimize the heating requirements on the Floating Storage Unit, FSU. Maintaining temperature also controls viscosity and results in better hydraulics. Pipeline installation was by Controlled Depth Tow Method. Both lines are protected by a 27-inch O.D. carrier pipe. High Density and Low Density Polyurethane are being considered for the insulation material. Simulated service tests will be done to verify product applicability. These include material degradation tests at the 140°F operating temperature and water absorption tests at the hydrostatic pressure of 660 psia. Bundle installation will be by the near surface tow method. For more information on the above examples and other insulation projects, please contact CPTC’s OS Division or CRTC’s Materials and Equipment Engineering Groups.
Deepwater Flowlines - Wax/Hydrate Study[30] The purpose of this study is to investigate ways to control paraffin, hydrates and flowing temperatures in deepwater flowlines/pipelines, including: 1) use of chemicals, 2) internal coatings, 3) insulation, 4) heat tracing and 5) purging. As an example application of this technology, the report cover letter discusses the implications for the crude/gas properties found at Green Canyon 205, located in the Gulf of Mexico in 2,670 ft water depth, and provides a brief assessment. This technology is also beneficial for shallow water, warm and cold, producing areas, such as West Africa, The Gulf of Mexico, North Sea, Canada, in the Arctic, etc where wax/hydrates may be of concern for flowlines or pipelines. Operational experience with wax and hydrate problems in pipelines is presented for Texaco - Offshore Angola, Conoco - Jolliet TLP, Shell - Gulf of Mexico, Panarctic Oils Ltd - Canadian Arctic Islands and Exxon - Mobile Bay. The Appendices include information on insulation materials and a vendors and suppliers list."
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956 Flexible Pipe This section presents an overview of current information of flexible pipe. Additional information of flexible pipe is contained in API Recommended Practice 17B. The primary suppliers of flexible pipe are Coflexip and Wellstream.
Application Flexible pipe is generally used to achieve flexibility with high pressure capability, in both static and dynamic applications. Typical applications are listed below and are shown in Figures 900-27 and 900-28. •
Flowlines from a subsea completed well to a fixed platform
•
Flexible pipeline to platform connections in mudslide areas
•
Flexible spool pieces between a steel pipeline and a subsea facility
•
Dynamic risers connecting pipelines to floating production facilities or single point moorings
Fig. 900-27 Example of Static Applications for Flexible Pipe
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Fig. 900-28 Examples of Dynamic Applications for Flexible Pipe
Types Nonbonded Construction. The structure of nonbonded flexible pipe, such as manufactured by Coflexip or Wellstream, is shown in Figure 900-29. The pipe is made up of several individual separate layers having no adhesion between them. Alternating layers may be stainless steel, carbon steel or extruded thermoplastic. Each layer has a primary purpose such as collapse resistance, fluid containment, internal pressure resistance or axial tension. Flexible pipe is engineered for a specific application; depending upon size and paressure rating, all layers shown in the figures may not be required. In dynamic applications, adjacent steel layers may rub against one another causing wear, galling and eventual failure, if the pipe is not designed properly. Coflexip has supplied that is being successfully used for dynamic applications in the North Sea, Brazil and Australia. Wellstream has furnished pipe for a few dynamic applications
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in Brazil and Austrailia. Wellstreams’s dynamic design provides a thin thermoplastic layer between adjacent steel layers to minimize wear. ID, in.
Maximum Working Pressure (psig) Coflexip
Wellstream
≤4.0
10,000
10,000
6.0
7,500
5,000
8.0
5,000
5,000
10.0
4,500 (built for a dynamic bench test program)
2,000
12.00
2,500
16.00
750
Typical size vs. pressure ratings are given below for pipe actuallly supplied by Coflexip and Wellstream. In most cases, pipe with lesser pressure ratings has also been supplied. Nonbonded flexible pipe can be manufactured in very long lengths. Limiting factors for length are the capacity of installation reels and weight of the pipe. Manufacturers of nonbonded flexible pipe, other than Coflexip and Wellstream, do not have an established track record and are not recommended at this time. Fig. 900-29 Nonbonded Flexpipe Construction
1. Interlocking stainless steel outerwrap protects outer thermoplastic layer. 2. Outer thermoplastic layer protects steel structural components from corrosion; resists abrasion and chemicals. 3. Contiguous layers of spiraling steel wire provide tensile strength. 4. Steel carcass of interlocking, spiraled Z-section withstands high internal and external pressures, resists kinking. 5. Inner thermoplastic liner makes the assembly leaktight, isolates steel components from fluids, resists abrasion and chemical effects. 6. Interlocking stainless steel liner protects the thermoplastic layer from damage by TFL tools.
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Bonded Construction. The second type of flexible pipe uses a bonded construction (see Figure 900-30). One company, PAG-O-FLEX, Germany, is marketing this type of pipe. The bonded type of construction is generally built up on a mandrel with helically wound steel wires and a polymer material. After assembly, the pipe is vulcanized to create a bonded assembly. Some pipes use an inner steel carcass that is not bonded to the adjacent layer. A potential advantage of bonded construction is that there is no wear, abrasion or galling of adjacent metal layers during bending. However, fatigue of wires and delamination between the polymer and the wires is a design consideration for dynamic applications. Fig. 900-30 Bonded Flexible Pipe Construction
A. STAINLESS STEEL STRIP WOUND INTERLOCK TUBE B. ELASTOMERIC LINER C. ANTI-EXTRUSION LAYER D. HIGH TENSILE STEEL STRAND REINFORCEMENT E. ANTI-CHAFFING LAYER
Bonded pipe is only manufactured in relatively short lengths of 50 meters or less, due to limitations in the size of vulcanizing furnaces.
End Terminations End terminations are usually built-in during pipe manufacture, but they can also be installed in the field. The most common type of end termination for flexible pipe is shown in Figure 900-31. Epoxy is injected into the termination to anchor and seal the pipe layers. Terminations of this type are done by hand and are very time
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consuming. Any common end connection such as API line pipe threads, bolted flanges, clamp hubs, proprietary connectors, and butt weld joints can be incorporated into the termination. Fig. 900-31 Typical End Termination for Nonbonded Flexible Pipe
Minimum Bend Radius The allowable minimum bend radius varies by manufacturer; a value of 10 times the pipe ID can be used for preliminary evaluations. Bend limiters are often provided at the end terminations to protect the pipe from overbending during installation and operation.
Temperature Limits In general, nonbonded flexible pipe uses thermoplastics (usually a nylon compound) that limit long term operating temperature to less than 200°F. Coflexip has published the following guidelines for use of their standard pipe liner material, Rilsan [55]. Description
Temp Limit °F
Estimated Service Life (Years)
Crude with no water
212
10
Crude with no water
194
20+
Crude with 10% water (max.)
194
20+
Crude with up to 100% water
158
10
Crude with up to 100% water
140
20+
Coflexip is using a fluorocarbon plastic. “Floraflon” (Polyvinylidene Fluoride), which they call “Coflon”, for high temperature applications. They claim that it is suitable for temperatures in excessof 250°F [55]. Industry experience with Coflon is limited.
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Installation Flexible pipe is typically laid from a portable reel or reels that are installed on the back of a workboat. Typically the vessel of choice has been a specially equipped, dynamically positioned, North Sea pipe carrier, see Figures 900-32 and 900-33. Pipe is spooled onto the installation reel(s) onboard the installation vessel. Pipe is paid out over a sheave or steel chute in a catenary shape (similar to a J-lay operation). Pipe is tensioned by the portable reel. Figure 900-32, or by shape (similar to a J-lay operation). Pipe is tensioned by the portable reel. Figure 900-32, or by tensioners, Figure 900-33. Alternatively, flexible pipe can be laid from vessels that Fig. 900-32 Winch, Chute
Fig. 900-33 Sheave, Winch, and Tensioner
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carry pipe in large carrousels and install pipe in a manner similar to that employed for long submarine cables. Coflexip operates two dynamically positioned installation vessels and a third which will be in service in late 1994. Northern Installer - North Sea pipe carrier that can accommodate up to ten 220 ton reels of pipe or two 1,500 ton carousels. Flexservice 1 -
Ship that can carry up to 3,500 tons of pipe in two carrousels. This vessel has been operating in Brazil laying flexible pipe for Petrobras for several years.
Sunrise -
A new build scheduled for delivery in the second half of 1994. This ship will be operating initially for Petrobras in Brazil. It will have the capability of carrying 6,500 tons of flexible pipe. Sunrise will be able to lay three lines simultaneously.
Performance Survey of Flexible Pipe in Static & Dynamic Service - Final Report [31] The objective of this survey was to obtain “experience based operator” data that documents the applications and performance history of actual offshore installations of the various types of flexible pipe in static and dynamic service. The survey was able to obtain detailed information on actual performance, including both successes and failures, of flexible pipe in 155 installations in the Gulf of Mexico, the North Sea, and the Far and Middle East. In all cases the installations involve flexible pipe in production related applications, including oil production, gas lift, water injection, etc. Major conclusions are summarized as follows: 1.
The great majority of flexible pipes that have been installed perform as good or better than expected,
2.
The majority of flexible pipes are in static type applications and have been in service for 10 years or less,
3.
The majority of problems with flexible pipe seem to occur during the installation phase,
4.
Costs are the major deterrent against the use of flexible pipe,
5.
There are a number of deepwater developments that specify flexible pipe for one or more applications: This illustrates the overall acceptance of its reliability and long term performance.
957 Cathodic Protection—Anode Systems API RP 1111 recommends that the design and installation of cathodic protection systems should be in accordance with NACE RP-06-75, “Recommended Practice
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for the Control of Corrosion on Offshore Steel Pipelines” (also see the Corrosion Prevention Manual, Section 1200). Cathodic protection may be provided by a galvanic anode system, an impressed current system, or both, capable of delivering sufficient current to protect the pipeline. (In recent years, the Company has used anodes rather than impressed current systems for offshore pipelines.) The following items should be considered in the design of cathodic protection systems: 1.
Galvanic anode systems should employ only alloys which have been successfully tested for offshore applications, typically zinc or aluminum.
2.
Galvanic anode systems should be designed for the life of the protected pipeline, typically 20 to 30 years.
3.
Cathodic protection system components should be located and installed to minimize the possibility of damage.
4.
Design consideration should be given to minimizing electrical interference currents from neighboring pipeline or structures. (Severe CP problems have resulted in the Gulf of Mexico, Pacific OCS, and the North Sea where pipelines have caused major deficiencies in platform CP systems where the platform relied on an impressed current system for part or all of its CP.)
5.
Design considerations should include allowance for water depth and provision for the effect of electrical current variation with time.
6.
Insulating joints should be installed in the pipeline system where electrical insulation of portions of the system is necessary for proper cathodic protection. If practical, these devices should be installed above water.
Det Norske Veritas, DnV RP B401 is an important document for cathodic protection, CP design in the North Sea. However, the Company is not an advocate of codes and standards which may lead to high cost pipelines such as this code for anode design, which is overly conservative and if applied, costs the Company a lot of money for no apparent benefit.
Materials Overseas, the Company uses aluminum bracelet anodes manufactured of an aluminum-zinc-indium alloy. The alloy is typically Galvalum III, manufactured under license from Dow Chemical Company or Sealloy-150 made by Kaiser Chemical. All steel used in the anode bracelet construction is ASTM A-36 plate. In the Cabinda field, zinc alloy bracelets were previously used for the larger lines. In the marsh/swamp where brackish water is found, zinc anodes are preferred for pipelines and are used in Louisiana and Nigeria, for example. In the Gulf of Mexico, the company uses zinc alloy bracelets, such as manufactured by American Corrosion Services. The zinc alloy should not include mercury. Figures 900-34, 900-35, and 900-36 provide selection tables for zinc and aluminum anodes. When the surface temperature of the pipeline exceeds 120° to 140°F, aluminum bracelets are used. Typically, a system design life of 20 or 30 years is specified.
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Fig. 900-34 Weight and Spacing of Zinc Alloy Bracelets for the Gulf Of Mexico Pipe Nom. Size, in.
Pipe OD, in.
20-Yr. System (Weight, lb. @ Spacing, ft.)
30-Yr. System (Weight, lb. @ Spacing, ft.)
2 1/2
2-7/8
24 lb. @ 530
24 lb. @ 350
3
3-1/2
36 lb. @ 650
36 lb. @ 435
4
4-1/2
36 lb. @ 505
36 lb. @ 335
4
4-1/2
48 lb. @ 675
48 lb. @ 450
6
6-5/8
60 lb. @ 575
60 lb. @ 380
6
6-5/8
72 lb. @ 690
72 lb. @ 460
6
6-5/8
84 lb. @ 805
84 lb. @ 535
8
8-5/8
72 lb. @ 530
72 lb. @ 350
8
8-5/8
96 lb. @ 705
96 lb. @ 470
8
8-5/8
108 lb. @ 795
108 lb. @ 530
10
10-3/4
84 lb. @ 495
84 lb. @ 330
10
10-3/4
120 lb. @ 710
120 lb. @ 470
10
10-3/4
132 lb. @ 780
132 lb. @ 520
12
12-3/4
108 lb. @ 535
156 lb. @ 355
12
12-3/4
144 lb. @ 715
144 lb. @ 475
12
12-3/4
108 lb. @ 775
156 lb. @ 515
14
14
120 lb. @ 545
120 lb. @ 360
14
14
168 lb. @ 760
168 lb. @ 505
Notes:
1. 2. 3. 4.
Weights are net alloy—Based on available size bracelets. Ambient temperature. Zinc bracelets—Based on current density of 6 mA/ft 2 and zinc consumption rate of 25 lb./amp.yr. and 2% holidays. When surface temperature of the pipeline exceeds 140°F, aluminum bracelets must be used. Above 170°F temperature, the polarity of zinc alloy reverses, so it is cathodic instead of anodic relative to steel pipe. (See Figure 900-36 for mildly hot and Figure 900-37 for very hot pipeline.) 5. Bracelet anodes for weight coated pipelines must be individually calculated due to wide range of coating thicknesses. 6. Variations in soil resistivity due to varying moisture and/or salinity necessitate specific calculations for the individual circumstances.
Bracelet anode sizes for weight coated pipelines must be individually calculated due to the wide range of coating thicknesses. These are usually “Special Order” unless the manufacturer happens to have the necessary size mold available. (See Figure 900-37 for “readily available” zinc anodes from one manufacturer.) Individual circumstances require specific calculations and must include consideration of: • • • •
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Variations in soil resistivity due to varying moisture and/or salinity Water salinity Pipe surface temperature Oxygen content of the water
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Fig. 900-35 Weight and Spacing of Aluminum (Deltalum, Galvalum 3, Seallow IV) Alloy Bracelets for Intermediate Temperatures Pipe Nom. Size, in.
Pipe OD, in.
20-Yr. System (Weight, lb. @ Spacing, ft.)
30-Yr. System (Weight, lb. @ Spacing, ft.)
2-1/2
2-7/8
13 lb. @ 430
13 lb. @ 285
3
3-1/2
17 lb. @ 460
17 lb. @ 305
4
4-1/2
25 lb. @ 530
25 lb. @ 350
6
6-5/8
36 lb. @ 515
36 lb. @ 345
8
8-5/8
44 lb. @ 485
44 lb. @ 325
10
10-3/4
57 lb. @ 505
57 lb. @ 335
12
12-3/4
101 lb. @ 755
101 lb. @ 500
Notes:
1. Mildly hot pipeline—Pipe temperature125°F; saline mud temperature 100°F. 2. Current density—10.3 mA/ft2. Consumption rate of alloy—9.7 lb./amp. yr. and 2% holidays.
Fig. 900-36 Weight and Spacing of Aluminum (Deltalum, Galvalum #3, Seallow IV) Alloy Bracelets for High Temperatures Pipe Nom. Size, in.
Pipe OD, in.
20-Yr. System (Weight, lb. @ Spacing, ft.)
30-Yr. System (Weight, lb. @ Spacing, ft.)
2-1/2
2-7/8
13 lb. @ 115
13 lb. @ 75
3
3-1/2
17 lb. @ 120
17 lb. @ 80
4
4-1/2
25 lb. @ 140
25 lb. @ 90
6
6-5/8
36 lb. @ 135
36 lb. @ 90
8
8-5/8
44 lb. @ 130
44 lb. @ 85
10
10-3/4
57 lb. @ 135
57 lb. @ 90
12
12-3/4
101 lb. @ 200
101 lb. @ 130
Notes:
1. Very hot pipeline—Pipe temperature 212°F; saline mud temperature 180°F. 2. Current density—16.6 mA/ft2. Consumption rate of alloy—21.9 lb./amp. yr. and 2% holidays.
• • • •
Whether or not the pipe is buried Whether or not the riser has anodes A longer design life or “safety factor” Water depth
Fabrication Anode bracelets are molded in either cylindrical or segmented shapes. Bracelets are sized to fit the outside diameter of the pipe plus the thickness of the coating. For pipe not requiring concrete coating, the end of the anode is typically tapered at a 1:2 slope. (For example, see Figure 900-37.) For concrete coated pipe, the anode thickness should be equal to the concrete thickness, with a tolerance of perhaps onequarter inch. Where possible, the selected manufacturer should supply stocked or
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readily available anode bracelets. Anode weight is defined as the minimum acceptable weight of the bracelet excluding the internal and external supporting structure. Fig. 900-37 Dimensions of Zinc Bracelet Anodes(1) Pipe Size, Nom (in.)
Pipe OD (in.)
Anode Length (in.)
Anode Thickness (in.)(2)
Length of Taper (in.)
Inside Radius (in.)
Max. Pipe Coating Thickness (in.)
Anode Net Weight (lb.)
Anode Gross Weight (lb.)
Tapered Bracelets 3
3.500
12.00
1.25
2.50
1.844
0.040
39
40
4
4.500
12.00
1.50
2.50
2.344
0.040
59
61
6-5/8
6.625
11.50
1.50
2.50
3.406
0.040
85
89
8-5/8
8.625
12.00
1.50
2.50
4.406
0.040
108
112
8-5/8
8.625
12.75
1.50
2.50
4.406
0.040
120
124
12-3/4
12.750
17.00
1.50
2.50
6.531
0.094
247
261
Square Bracelets 8-5/8
8.625
14.25
1.25
4.406
0.094
129
134
10-3/4
10.750
19
1.30
5.531
0.156
211
219
16
16.000
20.50
1.375
8.156
0.156
368
380
(1) Available mold sizes as of 9/18/86 from Corrosion Products, Inc. (Sizes other than these are Special Order and will require an additional delivery time to fabricate a new mold size.) (2) 1/4-inch thickness at the smallest end, tapering to the listed thickness
Anode Design/Installation Anode bracelets may be provided by the contractor or the Company. Anodes are installed by the contractor at spacings specified by the Company. Typically, the Company uses a constant 1,000 foot spacing for aluminum anodes. For Zinc anodes used in the Gulf of Mexico, the spacing is typically varied as shown in Figure 900-34. In addition, if the spacing exceeds the maximum allowable to keep the voltage (IR) drop to an acceptably low level, then the spacing must be reduced (for example, see Figure 900-38, which allows for a 0.06 volt drop, typical of a Gulf of Mexico design). (Consideration should be given to the anode size. If an anode is too big, it can “hang up” on the stinger rollers and be severely damaged. A smaller spacing with smaller anodes may be required in this case.) Normally, the first anode on a Company pipeline, excluding those which may be specified for attachment to platform risers, is placed no closer than 100 feet nor farther than 250 feet away from the riser. Anodes are not normally installed on risers in less than 300-foot water depths. For non-concrete coated pipe, anodes are typically installed at the weld pipe joints. Because anodes may be damaged during installation, it is prudent to order extra. Also extra anodes may be installed on the pipeline near the riser. The Company’s
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Fig. 900-38 Maximum Spacing of Bracelet Anodes for Schedule 40 Pipe Zinc Bracelet Anodes(1) Nominal Pipe Size (in)
Pipe OD (in.)
Wall Thickness (in)
Maximum Spacing (ft)(2)
3/4
1.050
0.113
610
1
1.315
0.133
640
1-1/4
1.660
0.140
660
1-1/2
1.900
0.145
670
2
2.375
0.154
680
2-1/2
2.875
0.203
750
3
3.500
0.226
770
4
4.500
0.237
790
6
6.625
0.280
840
8
8.625
0.322
890
10
10.750
0.365
920
12
12.750
0.375
930
(1) Table provided by Corrosion Products, Inc (2) Allowing for 0.06 voltage drop
typical anode attachment to the pipeline for concrete weight coated pipe is shown in Figure 900-39.
Holidays In general, a minimum of 2 percent for flaws or holidays in an FBE corrosion coating (5 percent for coal tar) should be used for the design calculations.
Anode Attachment The anode halves have mating surfaces, formed by their support steel structures, which are welded together to assemble the anode around the pipe. The surfaces to be welded must be cleaned to bare metal before welding. The anode halves are placed on the pipe and aligned to give a snug fit. Then they are welded together. Molded cylindrical anode bracelets may be connected by circumferentially welding “T” shaped plates in four evenly-spaced places for each bracelet. The final anode assembly should be in accordance with the manufacturer’s recommendations. To electrically bond the anode to the pipe in one design, copper wires are lead from the anode to the pipe. The corrosion coating is removed to bare metal in a small area, and the wires are bonded to the pipe using a Cadweld. Cadwelding uses an aluminum-thermite charge to weld the wire to the pipe without producing temperatures high enough to cause metal embrittlement. The correct Cadweld kit size is important, however. Typical anode specifications by the Company include the choice of welded-on, see Figure 900-40, or cadwelded anodes, see Figure 900-39. For pipelines without
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Fig. 900-39 Typical Anode Bracelet, Molded Cylindrical Type, Installed on Pipe
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concrete weight coating, the welded-on type is preferable since the cadwelded leads could possibly be damaged while going over the stinger rollers. After the anode has been installed, the corrosion coating and concrete weight coating are repaired. All aspects of the installation process are made available for inspection by the Company during installation of the anodes.
Manufacturers of Offshore Pipeline Anodes The Company has used the following manufacturers for offshore pipeline anodes: Cathodic Protection Services Company, American Corrosion Services, Global Cathodic Protection, Inc., Harco Corporation and Wilson Walton International.
Insulating Flanges Insulating flanges are used to break electrical current flow by nonmetallic, nonconductor gaskets, sleeves and washers. Flange insulation kits are available from Central Plastics Company, F. H. Maloney Company, and others. They may be installed on lines near or at the platform cellar deck level. Use of insulating flanges results in a system that uses jacket anodes and pipeline anodes for protection of each. Insulating joints are used for the following reasons: 1.
When the platform jacket and pipeline(s) have different corrosion protection (CP) types, typically the pipeline uses sacrificial anodes. (If the jacket uses impressed current CP (uncommon), then, without electrical isolation, the impressed current system can drive anodic corrosion of the riser due to the differential voltages between the riser and the jacket.)
2.
If the pipeline were bonded to an unprotected (no CP system) structure (uncommon), the structure would drain the pipeline system.
3.
When a pipeline coming to or leaving a Company platform is not owned by the Company.
Insulating joints are not needed if the pipeline and jacket are both protected with sacrificial anodes of the same potential (voltage). In this case there is no differential voltage and no drain or anodic corrosion of either the structure or pipeline. This must be explicitly designed for in order to match the potentials. Insulating flanges are easily broken during installation. This is a delicate operation, and care should be taken to prevent damage. In addition, the pipe/riser clamps must provide for electrical isolation of the riser from the platform. Neoprene rubber on the clamps may be used for this purpose. Another instance when insulating flanges should be used is at tie-ins to “foreign” pipelines - i.e., pipelines owned or operated by companies other than the Company. Thus the Company pipeline is isolated from any cathodic protection deficiencies in the foreign pipeline.
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Fig. 900-40 Typical Anode Bracelet “Welded” Attachment
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Maintenance/Repair A well-protected platform structure can protect a short pipeline. In some cases where insulating flanges have been used, and the pipeline’s anode system has failed after a long period of time, the insulating flange can be removed to provide corrosion protection to the line. This, of course, must be considered on an individual basis. If it is not an option, then the line and/or anodes must be replaced (also see Section 973).
Sample Calculations The following sample calculations illustrate the design of a sacrificial zinc anode cathodic protection system for a 8.625-inch OD, FBE coated, submerged pipeline with a length of 5.3 miles. (Also see “Pipeline Design Using the PLDESIGN Computer Program” in Section 934.) The pipeline is located in 225 feet of water in the Gulf of Mexico. The design life of the system is 20 years, which satisfies DOI’s minimum requirement (30 CFR Part 250.152). For sample calculations for an aluminum anode cathodic protection system for offshore pipelines, see Section 1250, Volume 1, of the Corrosion Prevention Manual. Step 1—Determine the area of the pipe per lineal foot: AL = Area/ft = pipe OD × π / (12 in/ft) = 8.625 in. × 3.14159/12 = 2.258 ft2/ft Step 2—Determine the total area of the pipeline: TA = Total area = AL × length of pipeline = 2.258 ft2/ft × 5.3 mi × 5,280 ft/mi = 63,188 ft2 Step 3—Determine the area of the pipeline that is not protected by the insulating barrier coating. In general, a minimum of 2 percent for flaws or holidays in an FBE corrosion coating should be used. AP = Area to protect = TA × 0.02 = 63,188 ft2 × 0.02 = 1,264 ft2 Step 4—Determine the total current required to protect the pipeline: I = Total current = AP × current density
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The current density is a function of the environmental parameters in which the pipeline is laid. These environmental parameters include the sea water temperature, production fluid temperature, salinity, and soil resistivity. The current density should be 6 mA/ft2 for the following conditions: production fluid temperature of 120° F or less, on the ocean floor or shallow buried, and water depths of 300 feet or less in the Gulf of Mexico. For deepwater installations and/or conditions found in other locations, the current density may have to be increased. For example, for offshore California in water depths of 600 feet or less, a minimum current density may be 10 mA/ft2. I = 1,264 ft2 × 6 mA/ft × (1/1000) amp/mA = 7.58 amps Step 5—Determine the amount of zinc required for a 20- year design life. The consumption rate of zinc is 25 lb/(amp yr). ZW = Required weight of zinc = I × consumption rate × design life = 7.58 amps × 25 lb/(amp yr) × 20 yr = 3,792 lb Step 6—Determine the weight of the anode, the number of anodes, and the spacing of the anodes. Typically specified Chevron U.S.A. - Eastern Region zinc alloy bracelet weights are shown in Figure 900-34 for various pipe sizes and a 20- or 30year design life. (Readily available sizes from, for example, American Corrosion Services are shown in Figure 900-37.) AW = Anode weight = 108 lb (selected from Figure 900-34 and Figure 900-35) NA = Number of anodes = ZW / AW = 3792 lb / 108 lb = 35.1 ( round up to 36 anodes) AS = Anode spacing = Pipeline length / NA = (5.3 mi × 5280 ft/mi) / 36 = 777 ft If the anode spacing exceeds the maximum allowable to keep the voltage drop to an acceptable low level, the number of anodes must be increased sufficiently to bring the anode spacing down (see, for example, Figure 900-38). Therefore, the spacing can be lowered by selecting a lower anode weight from Figure 900-34. In this case
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an allowable voltage drop of 0.06 volts would result in a maximum spacing of 890 feet (Refer to Figure 900-38). The 108-lb anode satisfies this spacing limitation. Step 7—Determine the interval of pipe joints that will require an anode bracelet: Interval =
AS / average pipe joint length
Average pipe joint length = 40 ft Interval = 777 ft / 40 ft Interval = 777 ft / 40 ft = 19.4 (round down to 19) Therefore, anode bracelets will be placed at 19 pipe joint intervals. However, the first and last anode should be spaced at one-half the interval. Step 8—Determine the number of anodes required for a 19-pipe joint spacing: Total number of joints = (5.3 mi × 5,280 ft/mi) / 40 ft = 700 jts Revised NA = Total number of joints/ interval = 700 / 19 = 36.8 (round up to 37) Step 9—Determine the revised design life due to the additional anode: Total anode weight = 37 × 108 lb = 3,996 lb Design life = Total weight / I = 3,996 lb/ (7.58 amps) (25 lb/amp/yr) = 21 years The revised NA results in a calculated design life of 21 years. Step 10—Anode Installation Procedure Zinc anode bracelet weight = 108 lb 1.
First anode attached at one-half interval
2.
2 to 35 anodes attached at 19 joint intervals
3.
36th anode placed on 674th pipe joint
4.
37th anode placed on 687th pipe joint
(Note: Anodes are attached to the middle of joints.)
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958 Safety Requirements and Component Selection This section provides a general discussion of pipeline safety as required by U.S. offshore regulations or as recommended practice by API (see Section 810).
30 CFR Part 250.154 — Safety Equipment Requirements for DOI Pipelines In U.S. waters pipeline safety requirements for Department of the Interior (DOI) pipelines are given by 30 CFR Part 250.154 (dated April 1988) as follows: 1.
The lessee shall ensure the proper installation, operation, and maintenance of safety devices required by this section on all incoming, departing, and crossing pipelines on platforms.
2.
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a.
Incoming pipelines to a platform shall be equipped with a flow safety valve (FSV).
b.
Incoming pipelines delivering to a production platform shall be equipped with an automatic shutdown valve (SDV) immediately upon boarding the platform. The SDV shall be connected to the automatic-and remote-emergency shut-in systems.
c.
Departing pipelines receiving production from production facilities shall be protected by high-and-low pressure sensors (PSHL) to directly or indirectly shut in all production facilities. The PSHL shall be set at 15 percent above and below the normal operating pressure range. However, high pilots shall not be set above the pipeline’s MAOP.
d.
Crossing pipelines on production or manned nonproduction platforms which do not receive production from the platform shall be equipped with an SDV immediately upon boarding the platform. The SDV shall be operated by a PSHL on the departing pipelines and connected to the platform automatic and remote-emergency shut-in systems.
e.
The Regional Supervisor may require that oil pipelines be equipped with a metering system to provide a continuous volumetric comparison between the input to the line at the structure(s) and the deliveries onshore. The system shall include an alarm system and shall be of adequate sensitivity to detect variations between input and discharge volumes. In lieu of the foregoing, a system capable of detecting leaks in the pipeline may be substituted with the approval of the Regional Supervisor.
f.
Pipelines incoming to a subsea tie-in shall be equipped with a block valve and an FSV. Bi-directional pipelines connected to a subsea tie-in shall be equipped with only a block valve.
g.
Gas-lift or water-injection pipelines on unmanned platforms need only be equipped with an FSV installed immediately upstream of each casing annulus or the first inlet valve on the christmas tree.
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3.
h.
Bi-directional pipelines shall be equipped with a PSHL and an SDV immediately upon boarding each platform.
i.
Pipeline pumps shall comply with Section A7 of API RP 14C. The setting levels for the PSHL devices are specified in paragraph (b)(3) of this section.
If the required safety equipment is rendered ineffective or removed from service on pipelines which are continued in operation, an equivalent degree of safety shall be provided. The safety equipment shall be identified by the placement of a sign on the equipment stating that the equipment is rendered ineffective or removed from service.
Discussion Pipeline safety regulations require an emergency shutdown (ESD) system to isolate hydrocarbon lines. Pipelines coming onto and leaving a platform should be provided with remote shut-down valves (SDV’s) and check valves that will effectively and reliably shut off hydrocarbon flow toward the platform in an emergency. In general, this should apply to most, if not all, gas lines. In the case of oil lines, it should be sufficient to be able to shut off flow from incoming lines via an SDV. However, item (b)(1) also requires an FSV (check valve). Because of corrosion and environmental forces on the FSV’s and SDV’s, they should be located well above the splash zone, e.g., on or just below the lowest accessible deck (see the discussion below). (In the U.K. Sector of the North Sea, regulations now allow site specific, safety case analysis regarding fitting of seabed ESD’s. If additional safety is not demonstrated, a valve is not mandatory. Operators have to demonstrate that their facilities have been analyzed as safe. The safety case is a detailed document that demonstrates this. Regulations require trade-off on topside ESD valve location. The valve must be closest to the splash zone consistent with damage, maintainability, and testing.)" Of the U.S. publications available on surface pipeline safety, the most important API document is RP 14C, “Recommended Practice for Analysis, Design, Installation and Testing of Basic Surface Safety Systems for Offshore Production Platforms.”
Company Experience — Subsea Pipeline Isolation Valves As an operator, the Company has not used remotely actuated subsea pipeline valves; regulations currently do not require them. Chevron USA- Eastern Region and Chevron Pipe Line Company have at least 24 installations that use subsea check (FSV) and ball (block) valves in sizes to 20-inch diameter in the Gulf of Mexico for pipelines incoming to a subsea tie-in (see Figure 900-41). These ball valves have all been manually actuated (by divers), not hydraulically actuated. This type of installation is required offshore U.S.A. by (b)(6) above. In terms of joint venture experience, there are platforms that provide subsea isolation of pipelines near/at the platform. In the Gulf of Mexico, one joint venture platform, operated by Texaco, has a subsea pipeline check valve (FSV) as the line leaves the platform.
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Fig. 900-41 CUSA Experience with Check/Ball Valves for Pipelines Incoming to a Subsea Tie-in The following information reflects Chevron USA-Production GOMBU’s experience with check/ball valves for pipelines incoming to a subsea tie-in. Design Considerations •
Prefers lock open (by diver) device for check valves (use when running acceptance test for a new pipeline or for pipeline maintenance/repairs)
•
Prefers an ANSI 900 rating (minimum), for maximum operating pressures less than or equal to 1,440 psi
•
Recommends a gear operator for ball valves if pipeline diameter is greater than or equal to 8 in ches
•
Prefers to install a block valve with the check valve
GOMBU Experience •
No maintenance required
•
Maximum valve size is 20 inches
•
Experience based on the use of 24 valve pairs
•
Ball valves all manually actuated (by divers), not hydraulically actuated
Valve Manufacturers •
Check Valves – Wheatley Pump and Valve Inc., Tulsa, OK
•
Ball Valves – WKM – Cameron – Grove
Ninian, Chevron U.K. — Subsea SDV’s Chevron U.K., Ltd. (CUK) preferred subsea ball valves to gate valves for installation in the Ninian pipelines located in the North Sea. The largest Ninian subsea valve is 24-inch O.D. CUK have installed four 8-inch subsea SDV’s on the gas lines with an 8-inch bypass valve for contingency. They preferred spring return, hydraulically actuated valves. CUK also installed subsea valves on the oil lines. All valves have been installed at existing tie-in spool flanges approximately 100 meters from the base of the platform. Subsea SDV’s and FSV’s have been used in the North Sea by other major operators since 1980.
Pipelines Incoming to a Subsea Tie-in — Subsea Check/Ball Valves CALASIATIC’s experience includes the Woodside Petroleum operated North West Shelf Development Project. In this case, the North Rankin A (NRA) platform has a subsea manifold. All valves in the subsea manifold are manual Cameron subsea ball valves. This manifold is located directly below the platform and was preinstalled onshore prior to platform installation.
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The technology and hardware currently exist to isolate a platform subsea, should it be required by the Company.
Location of SDV’s and FSV’s for Pipeline Safety Check/ball valves located below deck level or on the lowest deck near the riser, at a distance to prevent possible damage to them from an explosion or fire, offer a significant improvement in the safety of a platform. Also, risers and riser SDV’s and FSV’s should be located remote from personnel quarters. Additional safety can perhaps be offered to an already safe system by the use of subsea check/ball valves, although the exact reduction of risk is difficult to quantify. The use of risk analysis methods is helpful in this regard. In such instances, the consequences should be investigated in association with risk, not just risk alone. A statistical review of past failures should be included in the analysis. The optimum location of the subsea isolation valve with respect to the platform may be evaluated in two ways: 1) risk analysis, with respect to dropped objects or damage by other activities adjacent to the platform, and 2) consequence analysis, probably the governing approach, of failure. All riser ESD’s should also be protected from fire damage. (Company fire tests of bolted valves have demonstrated that on flanges and valve bodies, most bolted connections fail after being exposed to a hydrocarbon fire for about 20 minutes.) Valves placed on the riser just above the splash zone require careful selection of maintenance/corrosion protection. Such installations should be avoided. Loss of valve or actuator body material can cause very serious problems. Accessibility of such valves should be a prime consideration as well as the materials used (storm wave loadings should also be considered.) CRTC’s Materials Division can provide recommendations for materials and corrosion protection on such installations. These valves probably require replacement after some time, perhaps 15 to 18 years. If they are to be remotely operated, then the control system(s), actuator(s), and fittings must be carefully selected. (In all cases, SDV’s and FSV’s should be of failsafe, nonslam design.) SDV’s placed near the water line would be exposed periodically to heavy seas. These SDV’s would have to be designed to operate automatically through a platform ESD system, since it would not be safe to attempt to operate these valves manually during heavy seas. Placing SDV’s here would also expose the actuators, hydraulic lines, etc., to periodic pounding by large waves and possibly debris, making these components prone to damage and thus jeopardizing reliability. The extent and frequency of testing of topsides SDV’s should be thoroughly evaluated by the Company with respect to production loss and risk. Pressure venting of the platform section of piping should be considered carefully in gas systems, to avoid developing low temperature or cryogenic temperatures in the system. Therefore, the materials used in the venting system should be carefully evaluated.
Incoming Line — Surface FSV From an operating standpoint, an incoming line should have an FSV. There have been instances when reverse flow of a ruptured gas line dislodged internals of sepa-
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rators or dehydrators. The source of gas flow was from other incoming lines that connected downstream of the affected vessel. This is more of a production design problem than a safety design, but it should not be ignored. Incoming and outgoing pipelines in the Gulf of Mexico are typically provided with valves located on the platform cellar deck well above the water and close to the riser terminations. The incoming valve is typically a pneumatically controlled, spring loaded, fail-safe valve. (Spring loaded valves are typically 12-inch nominal and smaller. All other valves are typically power close.) In many cases, the platform may have scraper traps/valves with an automatic block-off. For incoming and outgoing pipelines, check valves are required per API RP 14C.
Pipeline Safety — Additional Considerations Additional considerations with regard to pipeline safety are as follows:
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All offshore production platform pipeline surface safety systems should meet API RP 14C requirements.
•
Pipeline surface SDV’s and FSV’s should be certified “fire safe”. See API Specification 6FA. For example, specify a fire tested valve assembly design (valve, gear operator and actuator). Also, all valves should be of an “antistatic” design, i.e., have provision for electrical discharge.
•
Subsea isolation should be considered as a secondary “back-up” to surface isolation, for gas lines which cannot be “blown-down” in 30 minutes or less. (Do not provide subsea isolation, at the platform, for oil lines. This may not be possible in the U.K. Sector of the North Sea due to regulations.) Subsea isolation is a secondary safety measure to prevent flow in case of a riser or topside SDV or FSV valve failure. The decision on whether both surface and subsea SDV’s or FSV’s are needed depends on the risk and consequences of failure.
•
Some degree of risk and assessment of financial loss should be used by the Company to determine when/if subsea safety valves (remotely operated) are required, i.e., large platforms with high investment should consider them. Platforms where several trunklines tie-in to a mainline should consider them (due to a potential loss of product). Small platforms with low risk and investment may not merit subsea isolation.
•
It may be more hazardous to attempt to install a new subsea SDV or FSV in an old line than to continue the current operation without a subsea valve. It may be appropriate to look instead for ways to improve safety through improved operating procedures, training, inspection, etc. Subsea SDV’s or FSV’s should only be installed where they offer real benefits.
•
Pipeline safety should include consideration of: (1) the implications of installing a system to depressurize gas lines in 30 minutes or less, (2) an investigation of the use of the flare system for this purpose and whether or not it could be accommodated, and (3) what modifications would be required for the Emergency Shutdown (ESD) system.
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Subsea SDV’s & FSV’s — Additional Considerations The conditions of activation for a subsea isolation valve should include local fire and gas detection, integrated into the “catastrophic” part of the ESD system. Additionally, manual pushbuttons, which cause the valve to go to the safe position, should be located in the Control Room and also at clearly marked strategic positions on the platform. Optimum location of an SDV or FSV would be outside the platform crane radius to avoid damage from dropped objects, but likely no more than 100 meters (or about 100 yds.) from the platform to minimize the exposure to anchors and fishing nets, and the gas volume contained in the pipeline between the surface and subsea isolation valve. Obviously, the location selected for installation of sea floor SDV’s or FSV’s is affected by the position of existing platforms’ pipelines. SDV/actuator burial should be avoided in order to ease maintenance/inspection. However, a protective structure could be devised for SDV/actuator burial applications. A manual ball valve and FSV (check valve) could be buried and used with flexible pipe. Flexible piping is typically used in a mudslide area. Subsea valves/actuators controlled from the surface would be difficult to operate and maintain because of possible pipe movement/burial. The hydraulic control line(s) would be very difficult to maintain in these areas. Pipeline disconnect devices that incorporate a check valve(s) are currently used in mudslide areas to prevent hydrocarbon pollution should a line fail near the base of a riser due to large soil movement (see Section 952). In non-mudslide areas a skid-mounted valve design could accommodate flexible pipe.
Investigation of Fire on South Pass Block 60 Platform B [44] A serious fire occurred on ARCO’s Platform B, South Pass Block 60, Lease OCS-G 1608 in the Gulf of Mexico, offshore Louisiana on March 19, 1989. This report was prepared by the Minerals Management Service (MMS), who are required to investigate and report on such occurrences. Anyone doing “hot work”, repair on risers should read it.
Investigation of High Island Pipeline System Leak [45] The MMS investigated a pipeline leak that occurred on February 7, 1988 at Galveston Block A-2 offshore Texas. The leak involved a 14" segment of the High Island Pipeline system.
Leak Detection Systems and Small Diameter Inspection Tools - Phases I & II [32, 33] H. O. Mohr Research & Engineering, Inc (HOMRE) conducted a Phase II Study “Evaluation & Selection Procedures and Cost Estimates” at the request and direc-
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tion of the Company, on leak detection systems and small diameter pipeline inspection tools, with emphasis on offshore pipelines that are used for transporting oil and multi-phase (oil/gas) products [33]. The Final Report & Appendix I, Volume I is “For Company Use Only”. This work was performed to implement the 1990 recommendations of the Offshore Oil Spill Prevention Task Force. Background. Phase I was a state-of-the-art survey for the subject systems and tools [32]. Phase II addresses the issues of availability, applicability and costs of leak detection systems, as well as inspection and survey tools for 6-inch and smaller diameter offshore pipelines and flowlines. The study objectives are: 1) To evaluate currently available leak detection systems or those under development, relative to a set of pipeline categories representative of those operated by the Company, and to assess their expected performance and reliability and 2) To evaluate the applicability and expected inspection/survey capabilities for the group of selected flowline subcategories. The study tasks included updating the literature and other technical information, meeting with key Company engineering and operations personnel and soliciting information from manufacturers and suppliers of leak detection systems and inspection tools. Discussion of Work. In summation, the project objectives were met. Leak detection system candidates that meet a series of functional requirements and desirable features for each of five major pipeline categories were identified and assessed. These categories include: 1) Shallow Platform to Shore (150 ft water depth and less), 2) Deep Platform to Shallow Platform (250 to 150 ft), 3) Deep Platform to Deep Platform (250 ft and greater), 4) Subsea Well to Deep Platform (250 ft and greater) and 5) Floating Production to Deep Water Platform. The installation and support requirements and limitations, as well as the associated system and component engineering, procurement, installation, operating and maintenance costs for each of the applicable leak detection systems were developed. The Table of Contents for Volume I is as follows: 1) Management Summary, 2) Conclusions and Recommendations, 3) Introduction, 4) Field Meetings and Input, 5) Pipeline and Flowline Categories, 6) Leak Detection Systems, 7) Small Diameter Inspection Tools and APPENDIX I - Project Data. APPENDIX II-Leak Detection Systems is three volumes: II.A, II.B-1 and II.B-2, which include regulatory, technical and supplier information. APPENDIX III-Small Diameter Inspection Tools is two volumes: III.A and III.B, which also include technical and supplier information.
Subsea Isolation and Surface ESD Systems Study [48] In order to establish the requirements for pipeline ESD and isolation systems and appropriate equipment and layouts for such systems, the Company directed a study of surface ESD and subsea isolation valves and systems, with particular emphasis given to regulatory requirements, current experience worldwide, system reliability and associated costs [48].
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This report: 1) Includes an introduction; 2) Summarizes the work performed, draws conclusions and presents recommendations; 3) Investigates existing and planned regulations pertaining to pipeline ESD and isolation systems; 4) Documents industry experience; 5) Reviews suppliers of suitable valves and actuators and presents an assessment of their capabilities; 6) Addresses inspection, maintenance and repair; 7) Provides an assessment of system component reliability based upon published data; 8) Assesses the pros and cons of differing valve types; 9) Discusses pipeline isolation systems for subsea valve installation; 10) Presents methods for providing protection to subsea facilities; 11) Contains cost information; and 12) Provides a list of references.
959 Coiled Steel Tubing Flowlines Coiled steel tubing, CST, has been used as flowlines in several instances in the marsh/swamp and shallow water in the Gulf of Mexico. Intec Engineering completed a report for CPTC/Marathon Oil Company in 1994 that defines feasibility of laying CST in water depths up to 400 ft with diameters of up to 4.5" O.D. [56]. Conclusions of this work are: •
While it is feasible to lay 4.5 inch O.D. CST in water depths up to 400 ft. manufacturers currently only have the capability to fabricate up to 3.5 O.D. pipe
•
Material cost for a project using CST are higher than for projects using conventional line pipe. However, installation costs, especially in remote areas should be less.
•
Installation of a CST flowline requires a minimum: a four point spread moored work boat / lay vessel, one or two hydraulically powered pipe spool stands, a short pipe stinger, and an anchor handling tug.
•
A 3.5 inch O.D. CS
•
A 3.5 inch O.D. CST flowline installed in 400 ft. of water in the Gulf of Mexico is estimated to cost $1,300,000 (1994 dollars), including engineering and contingency.
Prior to seriously contemplating a CST flowline installation, CRTC’s Materials and Equipment Engineering should be contacted regarding material specification, including QA / QC requirements.
960 Construction and Installation 961 Pipelay Methods This section describes pipeline installation methods and types of lay vessels for various water depth ranges. The methods most often used are S-Curve and J-Lay, each named for the shape the pipeline takes as it is laid from the vessel to the sea floor. Other methods are Reel and various towing methods.
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For an example of a specification used by CUSA-GOMBU to install subsea pipelines in the Gulf of Mexico, see Appendix C. General Specifications (GS’s) are used by COPI. The OS Division at CPTC in San Ramon, CA can assist in preparing pipeline project specifications and Bid Package upon request.
S-Curve Pipelay Method A conventional “S-Curve” pipeline installation spread typically includes the following major equipment [4] and is used to a depth of about 2,000 feet. Pipelay vessel with crew, fuel, consumables, and diver/ROV support • • • •
Anchor handling tugs Pipe supply barges and tugs Crew boat/supply boats Survey boat
0- to 75-Foot Water Depth. Typical examples of shallow-water flat bottom lay barges are the Diamond Services LB 5, LB 85 and Torch’s “Big Shane” LB 65. These lay barges are typically used for water depths up to 75 feet; the larger ones are capable of laying in 150 to 175 feet, with operating drafts from 8 to 12 feet. The pipeline is installed using manual welding in single (40-foot) joint lengths. Barges of this size are typically less expensive than conventional type lay barges for shallow water pipelines in spring and summer construction. Due to their shallow draft they are more susceptible to weather downtime which, in fall and winter, can greatly diminish their production rate and in turn increase costs. If the pipeline is to be laid in water depths of less than 75 feet, the shallow water barge will typically pull a jet sled. This can slow the production rate but reduce the duration and overall cost of the project in most cases. For a 0- to 50-foot water depth range, small spud barges can be used. 75- to 300-Foot Water Depth. Typical examples of conventional lay barges for these depths are the McDermott LB 23, 25, and 26; Offshore Pipelines, Inc., BAR 282 and 289; Saipem Castoro II; and the PLUS Cherokee, shown in Figure 900-42. 300- to 600-Foot Water Depth. Typical barges for these depths include the McDermott LB 27, 28, and 29; Brown & Root BAR 324 and 347; and Saipem Castoro V. These barges represent second generation conventional lay barge equipment with deeper water depth lay capability due to increased barge size, tensioner capacity, and enhanced mooring equipment. 600- to 900-Foot Water Depth. The larger second generation conventional lay barges described above are also applicable for pipe with less than a 30-inch OD, in the 600- to 900-foot water depth range. Third generation lay vessels are required for 36-inch diameter pipe in this water depth range and, depending on local availability, may be more cost effective for installing smaller diameter pipelines as well. 900- to 1,200-Foot Water Depth. Third generation lay vessels have extended pipe laying capabilities for these depths. Typical vessels of this class include the semisubmersible lay vessels: McDermott LB 200; Brown and Root M-420; the
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Fig. 900-42 First Generation Conventional S-Curve Lay Barge
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Saipem Castoro Sei, and ETPM 1601, a derrick/lay barge (see Figure 900-43). The production rates for these lay vessels are higher than for conventional second generation lay barges because they are typically equipped for double joint pipe (80 feet long) make-up procedures. Fig. 900-43 Third Generation S-Curve Lay Vessels
It should be noted that second generation lay barges can also be used for this water depth range in mild environments, but may require stinger, tensioner, and mooring system modifications. For example, the McDermott LB 29 and later the LB 27 were both used to install 12-inch diameter pipelines to Shell’s Cognac platform, located in the Gulf of Mexico in a water depth of 1,025 feet.
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1,200- to 1,800-Foot Water Depth. This water depth range is beyond the reach of conventional second generation lay barges. Third generation lay vessels can be used for pipeline diameters less than 30 inches. Major limitations for existing third generation lay vessels are summarized below. Figure 900-44 shows maximum achievable departure angles and tensioning capacities for the pipeline on third generation lay vessels. These capacities are achieved by installing two or three tensioning units in series. A typical tensioner is shown in Figure 900-45. Angles are for the pipeline at the top of the stinger. Fig. 900-44 Maximum Tip Angles and Tensioner Capacities for Third Generation S-Curve Lay Vessels Pipelay Vessel
Stinger Type
Max Tip Angle From Horizontal
No. of Tensioners
Total Tension Capacity
McDermott LB-200
Fixed Ramp
30°
3
450
Saipem Castoro Sei
Fixed Ramp
45°
—
—
Brown & Root M-420
Hinged
35°
3
240
Allseas Lorelay
Fixed Ramp
40°
2
200
ETPM 1601
—
—
3
450
The station keeping systems for third generation lay vessels limit the total horizontal force available to balance the horizontal pipe tension, environmental loads, and vessel move-up loads. The largest conventional mooring systems are limited to 200 to 300 kips horizontal force and have a practical limit of 1000- to 1500-foot water depth. More advanced third generation lay vessels such as the Castoro Sei and Allseas Lorelay, a ship, use dynamic positioning (DP) to supplement or replace conventional mooring lines in deep water. 1,800- to 2,400-Foot Water Depth. Third generation lay vessels can still be used to install up to 20-inch diameter pipelines in this water depth range. An example of this is the 20-inch diameter Sicilian Channel Crossing installed in a 2,000-foot water depth by the Saipem Castoro Sei.
J-Lay Pipelay Method “J-Lay” type vessels are used for very deep water installation. 1,800- to 2,400-Foot Water Depth. A DP drillship converted to install pipelines by the J-Lay method is probably required for pipe diameters greater than 24 inches and may be used for smaller diameters. This type of vessel is illustrated in Figure 900-46. More details are given in Section 980. The production rate for this type of J-Lay vessel is limited by the availability of only a single welding station, which may be equipped for automatic welding, flash butt welding, or other joining methods (see Section 964). An additional limitation of the J-Lay method is the minimum water depth to which pipe may be payed out without risk of damage to the suspended span. The minimum water depth is governed by the pipe size, material grade, and vessel motions.
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Fig. 900-45 Typical Lay Barge Tensioner
2,400- to 3,000-Foot Water Depth. The following pipelay methods are applicable for this water depth range: Pipeline Diameter (In.)
Pipelay Method
6 - 12
Third generation lay vessel with modifications
16 - 28
Drilling vessel modified for J-Lay installations
30 - 36
Newly built, dedicated J-Lay vessel
The dedicated J-Lay vessel might have an advanced pipe make-up system, such as flash butt or automatic welding and multiple joint pipe that would increase the production rate for single station pipe make-up.
Low Cost Flowline Installation Method: J-Lay Inclined Mast (JLIM) Concept - Report (Chevron/Starmark Offshore) [57] The primary goal is to provide less costly means of laying small diameter flowlines (to individual wells), using the inclined mast J-lay technique that is currently available with conventional pipelay barges. The JLIM equipment may be outfitted to a
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Fig. 900-46 J-Lay Method—Drillship Conversion
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suitable dynamically-positioned workboat (i.e. diving, soil, work, utility, etc. vessel). The study determined methods for the installation of small diameter, (typically one or two separate 4 inch -nominal flowlines, approximately 2.5-mi each or 5-mi for one line) flowline(s) between satellite (platform or subsea) wells and host facilities in remote areas, such as offshore West Africa. Water depths from 200 to approximately 450 ft. were considered. The example area is offshore Cabinda, Angola. Extension to other locations, deeper water depths, and 8 inch -nominal pipe diameter is technically feasible. The Scope of Work included the performance of a pipe handling and ship selection study to satisfy the following minimum requirements: 1) work boat size and length, moored or dynamically positioned, 2) candidate vessels, 3) procedures, 4) boat modification and fit-up requirements, including estimated costs, 5) pipe handling/laying (welded or threaded joints), 6) speed of laying, 7) monitoring of inclined mast J-Lay system, 8) Crane requirements for pipe/riser handling and/or Jtube pulling system for riser installation, 9) crew required, 10) cost for the mob/demob and the equipment welding/vessel spread during installation, and 11) report documentation. The potential application of this technology is to reduce offshore flowline costs in remote areas.
Other Pipelay Methods For short and/or deep water pipeline installations, alternative installation methods, such as the reel method (limited to NPS 16; see Section 980 for further details) and various towing methods or flexible pipe installation should also be considered (see Section 956). Some towing methods are:
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Surface pull/push—the pipe is floated into position and subsequently submerged and dropped to the bottom by filling with water or releasing the flotation drums which support the line while floating out to position. The method is commonly used for shore approaches.
•
Off-bottom pull—the pipe is buoyant via auxiliary flotation. It is kept submerged by the weight of heavy chains, which are attached to it at intervals. These chains drag along the bottom, keeping the pipe from touching the bottom.
•
Bottom pull—the pipe is pulled from shore along the bottom into position, sometimes a long distance from the shoreline fabrication site. This is a commonly used method for both crossings and offshore. This method will require special abrasive coatings for long tows.
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Tow Methods for Installation of Offshore Pipelines [34] Objectives of this study were to: 1.
Describe & document the various pipeline towing methods in use.
2.
Evaluate the use of tow methods for installing pipelines and flowlines in water depths from 70 to 3,000 ft with an emphasis on the Gulf of Mexico area but having applications worldwide. This includes defining the advantages, disadvantages and technical limitations of each tow method under the expected environmental conditions.
3.
Identify the tow methods which are most suitable for areas as the GOM and evaluate these methods based on general design, fabrication and installation requirements.
4.
Develop towed pipeline and flowline bundle installation scenarios and evaluate selected tow methods as alternatives to conventional methods for installing these lines. This evaluation is based on technical and economic criteria.
5.
Help advance industry capability to design, procure, and construct pipelines using towing applications.
Deepwater Tow Methods Design Guide for the Installation of Offshore Pipelines [35] Tow methods for the installation of offshore pipelines involve welding long strings of pipe on shore in 1 to 10 mile lengths and then towing them with tugs to the desired installation point. This Guide focuses on water depths beyond 1,000 ft. Limiting parameters for single, as well as bundled pipeline configurations are evaluated for various tow methods of pipeline installation. This evaluation shows that viable methods for construction of offshore pipelines in deepwater include the middepth and bottom tow methods.
Marsh/Swamp Pipeline Construction Manual (Chevron/Brown & Root) [58] Pipeline installation in marshes, swamps and very shallow water is often more difficult than for onshore or offshore pipelines in deeper water because of the difficulty of working with traditional land-based or offshore equipment. Several approaches to pipeline construction are available, such as: 1) Excavate a narrow trench and float the pipe in from a staging site; 2) Excavate a trench and float the pipe in from a barge or vessel in a waterway or river; 3) Dredge a narrow channel and install the pipe using a specifically-rigged narrow lay barge; or 4) Use trenching and installation similar to land pipeline techniques, using special swamp equipment such as marsh buggies and mat supported cranes and backhoes. The primary goal of the Marsh/Swamp Pipeline Construction Manual is to document the construction methods available and provide information and guidelines for planning, designing and constructing a pipeline in a marsh for swamp location. The report stresses the importance of up-front engineering for proper route selection, thorough project definition, and proper project specification as keys to lowering project uncertainty and construction costs.
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The potential benefit of this technology is for flowlines and pipelines in swamp, marsh or very shallow water locations to produce lower pipeline costs through improved design, project definition and specifications.
962 Pipelay Personnel and Equipment This section discusses contracted pipeline personnel and construction equipment used for conventional S-lay.
Lay Barge Personnel The major piece of equipment used for the installation of an offshore pipeline is the pipelay barge. A typical barge has quarters for about 200 persons. The Company representative and/or inspector(s) work with particular contractor individuals on the barge. Typical responsibilities are discussed below; however, these will vary from company to company. Barge Superintendent. The barge superintendent is ultimately responsible for all operations performed on the barge. Although authority is delegated to a number of foremen who operate under the supervision of the superintendent, any final decisions or changes will be made by the superintendent. The Company Representative (or inspector) works closely with the superintendent to ensure that all operations are undertaken in accordance with Company specifications and drawings. Barge Captain. The barge captain is responsible for ensuring that all mechanical and support operations are maintained on the barge. These range from the proper operation of all engines, motors, and mooring system to ensuring that the crew’s quarters are cleaned. In short, the captain is responsible for maintaining a safe, operational, and seaworthy vessel. Barge Foreman. The barge foreman is in charge of construction activities, other than the actual pipeline welding, which takes place in conjunction with the pipeline operation. Such activities include material handling, rigging, running anchors, and miscellaneous fabrication required as support for the job. Welding Foreman. The welding foreman ensures that the welding is performed according to specifications and proceeds as expeditiously as possible. Should a higher-than-average number of rejected welds become apparent (see Radiograph Station), the welding foreman should determine the cause and correct the problem. Dope Foreman. The “dope” foreman manages the dope station where all weld joints are field coated and the pipe is jeeped to ensure that all flaws in the coating are repaired before the pipeline goes into the water. As simple as the operation is to field coat the weld joints and to jeep the pipe, difficulties are quite common in this phase of the operation. An improperly adjusted holiday detector will not show coating flaws. Additionally, dope crews may be less than diligent in performing their jobs, because the contractor does not want to slow down the production rate of the expensive welding station.
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Lay Barge Equipment and Stations Because many operations may be performed simultaneously, the typical side-lay barge has a number of work stations usually situated on the starboard side. (Some barges are center lays with work stations located on the vessel center line.) A specific function is performed at each of these stations, beginning at the bow and concluding at the stern. Pipe Handling. Pipe is brought to the work site on material barges, transferred to the lay barge with the barge cranes, and stacked in the pipe rack, typically on the port bow corner. The pipe should be inspected and cleaned and the ends prepared. The stacking machine, a conveyor for moving the joints to the starboard side (for side-lay barges) for alignment and welding, is filled with pipe; and each joint is measured for length, numbered, and recorded. Alignment Station and Root Passes. The first work station in the barge assembly line is the alignment station. The pipe joints are aligned with the use of the stalking machine and an internal line-up clamp. After proper alignment and the root gap is achieved, the root bead and hot pass are made. Large-diameter pipe should not be moved until this is done, to avoid cracks. The pipe may also be back welded at this location if specified. Welding Stations. Upon completion of the two passes at the alignment station, the barge advances and the pipeline rolls toward the stern on rollers until the weld joint is situated at the second station. Filler pass welds are added to begin filling out the beveled weld joint. The same procedure takes place at the third welding station. When the weld joint reaches the fourth welding station, the filler passes are made; and the cap bead is added, completing the welding process. It should be noted that the number of weld passes made at each station is dependent upon the pipe wall thickness and the weld qualification procedure. The number of stations is project specific and should be optimized by the contractor for a particular job. Pipe Tensioners (Where Necessary). One, two, or three pipe tensioners may be used (see Figure 900-44). Pipe tensioners may be located between the second and third welding stations and sometimes the third and fourth welding stations. (A single tensioner is usually located after the last welding station.) These machines are hydraulically operated and place an axial (and lateral compression) load on the pipeline to prevent buckling of the pipeline during the laying process. (In very shallow water, pipe tensioners are not required. A barge without tensioners can be used. The pipe is then handled with a crane and on-board winches.) Radiograph Station — “X-ray.” Following completion of the welding process, each welded joint is radiographically inspected to ensure weld quality per API 1104. If a flaw exceeding the specifications is detected, the weld is repaired at that station. Dope Station. After acceptance of the weld by the Company engineer or inspector, the welded joint is field coated at the dope station with the specified protective coating or shrink sleeves. At the same time, the entire joint of pipe is jeeped with a holiday detector to locate any flaws in the protective coating, which must be repaired prior to continuation.
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Sacrificial anodes for cathodic protection can also be added at predetermined intervals at the dope station (see Appendix C). (If the pipe is weight coated, anodes should normally be preinstalled.)
963 Construction Operations Installation Manual The contractor’s pipelay installation manual typically contains a description of the equipment and procedures to be used during installation. (For small diameter, short lines laid in shallow water in the U.S., typically an installation manual may not be required by the Company.) The manual should give pipeline construction procedures including: 1) Initiation, 2) Termination, 3) Laying, 4) Repositioning, 5) Pigging, 6) Hydrostatic testing and 7) Burial [39]. The manual should also give the following equipment information: 1) Barge: stinger hitch and ramp heights, 2) Stinger: ballast control, instrumentation and monitoring, 3) Tensioner(s): dead band, 4) Abandonment/recovery winch and 5) Davits. The manual should contain the installation drawings, including: pipeline route maps, ramp/stinger configuration, mooring, platforms, initiation, abandonment, raising, lowering, risers, pipeline crossings, trenching, tie-ins, etc. The drawing size is 11 x 17 inches. Mooring plans should include detailed anchor pattern drawings for the pipelay vessel. The anchor plans must show all planned anchor locations sequenced along the pipeline installation route. It is essential that the anchor plan show all existing pipelines and facilities. Anchor distances and “safety-zone” distances between proposed anchor locations and pipelines must be shown. The manual should show the nominal tension, stinger depth, minimum route radius, davit lift lengths/tensions, pipeline alignment, etc. Supporting calculations should be contained in an appendix. Calculations should include: pipelay stress, davit lift, initiation, abandonment, etc. The manual should identify the equipment to be used and provide a sequenced schedule of work by vessel. The project specifications should be included for reference.
Pipeline Initiation The initiation method, also known as the “lay-away method,” uses a “deadman” anchor at a predetermined point on the sea floor. A cable is run from this anchor to the pipelay vessel and connected to a pull-head on the first pipe joint. This cable provides the back tension required to control the pipe sagbend stresses until sufficient pipe is on the sea floor [3].
Pipeline Initiation with the Bow-String Method This method is normally used when a pipeline is initiated at a platform. Divers install a cable (the “bow string”) between the required elevations by passing two slings around the jacket leg. One sling is attached at the top and one on the bottom of the platform. The pulling head is welded to the first pipe joint, and the end of the stinger is positioned as close to the jacket as possible. A marker buoy is attached to
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the pulling head. Divers connect the pulling cable, an additional sling and a shackle to the bowstring as shown in Figure 900-47. Tension is applied to control the pipe stresses as the barge moves away from the platform, and the pipe progressively sinks until it touches the sea floor. Because this method requires the use of divers, too-deep water may prevent its use in some locations. It has been used frequently in offshore Cabinda.
Pipeline Termination Termination of a pipeline from a laying vessel is accomplished by welding the pull head to the last pipe joint. A cable from the vessel’s abandonment/recovery winch is connected to the pull head, and the vessel moves forward, using the winch to maintain required tension. At a platform the pipeline may be tied off with a cable.
Pipeline Repositioning The pipeline termination method described in the previous paragraph usually will not provide sufficient accuracy for locating the end of a pipeline in certain cases. This is because the pipeline must be laid to bottom by the barge moving out from under it. (Platforms restrict the barge movement.) Depending on the tie-in method and materials used, tighter tolerances may be required. The most common way to reposition a pipeline is to attach several cables, evenly spaced over a length, and lift the pipe off of the sea floor using the barge “davits.” By mooring the lay vessel on its anchors, the end of the pipe may be repositioned. Davit lifts should be carefully planned and executed to avoid over-stressing or buckling the pipeline.
Pipeline Monitoring and Control Stinger support and tensioning devices are used during pipelay operations to insure that stresses along the pipeline are within allowable limits. The maximum total combined stress should not exceed 80 percent of the Specified Minimum Yield Strength (SMYS) during installation and testing. The pipelay contractor should provide instrumentation for a continuous visual display of readouts for the Company Representative or Inspector to monitor the barge-applied tension and stinger configuration. Pipe tension should be monitored on a continuous basis via a strip chart recorder and visually via a gage during barge move-up. Maximum tension variation during move-up should be limited to less than 20 percent of the “Nominal Tension.” Stinger depth should be monitored visually with a gage. A TV monitor showing the stinger rollers and pipe should be provided in the barge control room.
Contractor Reporting The pipelay contractor should prepare a chronological schedule of work prior to the start of offshore construction showing estimated completion times of key activities. The schedule should include the pipeline, each riser, and other operations and marine vessels individually. This schedule should be updated as necessary during construction, to reflect actual and forecasted events. The contractor should also prepare daily field reports. They should include a daily forecast of all work to be performed over the subsequent 24 hours as well as known
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Fig. 900-47 Bow-String Initiation Method
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and projected vessel location and movements. A pipe tally report should be submitted upon completion of the pipeline, and for jobs outside the U.S., the report should be in both metric and English units, meters or feet. Diving reports should be submitted upon completion of each dive. Accident reports should be submitted within 24 hours for any person receiving treatment from the contractor’s medical personnel for an injury.
Contractor Safety Prior to arrival on-site, all marine vessels and pipelaying equipment should be inspected for safety. The contractor should prepare a plan to correct any violations. In general, work will be allowed on a 24-hour-a-day basis, except for hook-up work on platforms where lighting will be restrictive. Movement of anchors or moorings in the vicinity of existing facilities, such as platforms or pipelines, is generally not permitted at night. Lifting of equipment onto decks should not be permitted at night. The contractor should give a minimum of 24 hours’ notice to the Company Representative prior to moving barges at night. The contractor’s first approach to the site should be done during the daylight hours. Safety is of prime importance to the Company and the contractor. The contractor’s Installation Manual should include a brief description of the contractor’s criteria for safe operations, including crane operations. Also, communications between the surface and the diver(s) is an important safety consideration. All contractor cranes should be operated by qualified, authorized, experienced crane operators thoroughly familiar with the contractor’s safe operating procedures. The contractor should describe, in the Installation Manual, the safety procedures to be used during NDT, including shielding for both pipeline and riser construction.
Contractor Anchor Handling and Mooring The contractor should take precautions to avoid pipeline damage from spread anchors. The anchor handling vessel should be equipped with a radio or satellite positioning system. Prior to dropping an anchor, the vessel Captain should obtain approval of his location from the contractor’s authorized representative onboard the lay barge. Any anchor that will be located by using the minimum horizontal distances should require approval of the Company Representative or Inspector prior to dropping. The minimum horizontal distances for shallow water depths are: 1) 50 meters for pulling on an anchor away from a pipeline and 2) 100 meters for anchors pulled towards a pipeline. Anchor locations are to be reported. Any anchor dragging should be reported immediately to the Company Representative or Inspector. Anchors or cables should not be dragged along bottom. They must be picked up vertically so as not to damage pipelines and/or structures. The pipelay contractor should present procedures to assure the Company of compliance with the minimum vertical distances between the cable and pipelines and the minimum horizontal distances between an anchor and a pipeline. All mooring drawings should show lightening buoys, where required. The Installation Manual should indicate whether or not the contractor plans to moor to the Company’s platform(s) for riser installation, and if so, identify line attach-
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ment locations(s) on the construction drawing(s). The preferred attachment locations are the platforms lifting eye(s). Two lines off the bow of the riser installation vessel, in a bridal configuration are often used.
Welding Procedures The contractor should submit welding procedures for the Company’s approval. The procedure should cover welder qualification and onshore/offshore weld acceptance and repair; once approved, the procedures should be included in the Installation Manual. Welding should be performed in accordance with Company approved procedures, API 1104 and Company specifications.
Pipeline Pre-survey Prior to pipeline construction, the contractor should survey the sea floor along the pipeline route and report any significant debris to the Company Representative, and mark the pipeline route and any existing lines and/or debris with buoys. The procedure to be used for positioning should be included in the Installation Manual. The post-installation survey should also be described in the Installation Manual. The manual should also discuss how unsupported spans are located and measured.
Pipeline Pigging With all riser connections completed on each end of the pipeline, a scraper pig is pumped through the pipeline to remove most of the loose mill scale and weld slag that may have accumulated in the line during construction. The scraper pig run is followed by a gage pig run. The gage pig may be outfitted with aluminum sizing plates with a minimum diameter of 93 percent of the pipeline’s smallest inside diameter. The gage pig will detect any significant buckling that may have occurred during construction. Sea water that has been treated with a corrosion inhibitor or biocide is normally used to push the gage pig through the line. This treated water should remain in the pipeline until the line is placed into service.
Hydrostatic Testing A hydrostatic test is the final operation to be performed in construction of the pipeline. Depending upon which governmental agency has jurisdiction over the pipeline, the test requirements will vary. The DOI requires that the pipeline be tested to 1.25 times the designed working pressure for an 8-hour minimum, as prescribed in 30 CFR 250, while the DOT requires that the test pressure be held for 4 hours, as prescribed in 49 CFR 195.302b. (An additional 4 hours is required for locations where the pipeline cannot be visually inspected for leaks, i.e., divers and/or ROV used.) The Company requires a test pressure of the lesser of either 1) 150 percent of the maximum allowable working pressure of the pipeline or lowest rated valve or fitting in the section under test, or 2) the pressure which would result in a maximum combined stress of 90 percent of the SMYS of the pipe. The test period shall not be less than 8 hours. Pressure and temperature monitoring is required. All variations in pressure require explanation on the recording chart. All U.S. regulating agencies require that the hydrostatic test records be maintained on file for the life of the pipeline.
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One may want to consider using a third party consultant to witness the testing. The pipeline profile should be considered to avoid overpressuring. (Typical specifications are available for testing. See Section 700 for a discussion of hydrotesting.) Procedures for testing should include estimates for the pressures and volumes of liquids to be used.
Pipeline Burial Following a successful hydrostatic test, the pipeline may require burial, depending upon conditions of the sea bottom and water depth in which the lines were laid. (If the job is lump sum, one probably will not want to test until after burial.) In the Gulf of Mexico, pipelines are generally buried when water depths are up to 200 feet. The specifications detailing burial requirements for DOT submarine oil pipelines are contained in 49 CFR 195. Burial methods are described in Section 968.
Pipeline Dewatering for a Flare Line Consideration should be given as to how the water will be displaced after pigging for a flare line. The objective is to dewater the pipeline prior to commissioning to minimize any backpressure. The Company has dewatered flare lines using two methods, offshore Cabinda. First, the Company has the Contractor run a series of polypigs pushed by air from a compressor. Secondly, the water is blown out with high pressure gas when the Company commissions the line with the facility. This is usually not performed with a pig since the tip is normally installed at this time. A third method is to combine the two and blow out water by pushing polypigs with high pressure gas prior to installing the flare tip. This can be done by rigging up a frame to hold the tip up, act as a pig catcher and assist in lowering the tip upon completion (For example, see the CABGOC Takula ALP jacket and flare line drawings of the device from the Contractor’s Installation Manual).
964 Pipe Joining Methods Offshore Pipeline Welding Onshore and offshore welding practices in general do not differ significantly; thus refer to Section 630 for common welding methods, procedures, and code requirements. Typically, welding must meet API 1104 requirements. For information on weld inspection, see Section 966. The Shielded Metal Arc Welding process is the favored method for joining pipe sections offshore and onshore. Since the inception of the electric arc welding method, the development of new processes and automation has advanced substantially, resulting in increased efficiency, precision, and strength. This is particularly beneficial to offshore pipelaying operations, where a reduction in spread time results in significant cost savings.
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The following are examples of the innovations made in welding: 1.
Semiautomatic Gas Metal Arc Welding (or MIG—Metal Inert Gas) process uses small diameter wire with carbon dioxide or argon-CO2 as a shielding gas (see Section 632).
2.
Electron Beam welding is a fusion joining process, with the work piece bombarded by a dense stream of high velocity electrons, whose kinetic energy is transformed into heat. This process is entirely automated and permits the welding of square butts in a single-pass weld with deep penetration, high speed, precision, low distortion, and high strength.
Refer to Figure 900-48 for a summary of pipe joining techniques and offshore experience of the vendors and/or installers listed in Figure 900-49. Fig. 900-48 Pipe Joining Techniques and Offshore Experience of Various Vendors/Installers Technique
Offshore Experience
Vendors (1)
Shielded Metal Arc Welding
Heavy experience, universally accepted
1-5, 8-14, 16 17
Semi-Automatic and Automatic [28] —Gas Metal Arc Welding
Moderate experience
4, 5, 10, 11, 12, 13
Flash Butt
Minimal experience
2, 9
Friction Welding
Minimal experience, deepwater application
16
Cold Forging
Specialty method, no laying experience, risers, flange connections, repair, etc.
1, 3
Mechanical Interference
Minimal experience
17
Threaded Connections
Minimal experience
6, 7, 11, 14
(1) See Figure 900-49 for Vendor Cross Reference.
Alternative Joining Processes In the Flash Butt process the pipes are rigidly clamped close to the butt ends, preheated by using an induction coil, brought together for the flashing operation, and then upset, thus completing the welding. The resulting surplus metal inside and outside the pipe is subsequently removed. This is an attractive process for deep water pipelaying operations (J-Lay). A prototype has been built and tested (McDermott); however, it has not been applied offshore. Friction Welding involves rotating one component coaxially with another under the application of pressure to generate friction so that a solid state pressure weld can be produced. This also is an attractive process for deep water pipelaying operations (JLay); however, it has not been applied offshore.
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Fig. 900-49 Pipe Joining Vendors/Installers 1. Big Inch Marine Systems, Inc. 2. Blohm & Voss 3. Cameron 4. CRC Automatic Welding 5. H. C. Price Company 6. Hughes 7. Hydril Company 8. ETPM - Councellor II 9. McDermott 10. Mid-Continent Supply Company 11. Nippon Steel Corporation 12. SAIPEM 13. TOTAL - CFP 14. Vallourec 15. Vickers Limited Shipbuilding 16. Kvaerner Engineering, Ltd. 17. Zapata Off-Shore Company
Cold Forging creates a bond between the pipe segments by inserting the end of one segment into another and deforming the inner segment, so as to create a metal-tometal seal. The feature of this method is a single station for connecting, repair, testing, and coating (also see Sections 952 and 971). Mechanical Interference joints use a bell or groove end preparation installed on each end of a joint, and joints are joined together by a hydraulic press-fit unit in the field. Threaded Connections are applicable where reliable sealing and structural integrity are required in a hostile environment. This is a cost effective approach, if several joints are connected and then the multijoint strings are joined with threaded connectors. The technology available for well casing can also be applied to pipelines. (Refer to Drilling Technology Center Technical Memo 87-06, October 1987, “Guidelines for Selection of Threaded Connectors for Casing and Tubing.”)
965 Pipeline Tie-in Methods This section discusses methods for making subsea pipeline-to-riser and pipe-to-pipe connections. These types of methods may also be used when making subsea pipeline repairs (also see Section 971).
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Riser Installation Methods In shallow water locations, risers may or may not be installed by the same equipment spread which installed the pipeline. In the Gulf of Mexico shallow water locations, a jack-up barge is often used. Offshore Cabinda, the pipe bury barge is typically used. Each case should be individually analyzed. In shallow or deep water the riser may be preinstalled (onshore) on the platform prior to installation. 0- to 300-Foot Water Depth. For diameters up to 36 inches, the conventional “above water” riser installation method may be used. This method includes the following procedural steps: 1.
Cap off the pipeline end and lay it down.
2.
Deploy divers to obtain on-bottom measurements for pipeline cut-off.
3.
Raise the pipeline to the lay barge, cut off the cap, and weld on a prefabricated riser.
4.
Lower the riser and clamp it to the platform jacket.
In the Gulf of Mexico, the riser is often installed with a flange (also see Section 952). 1.
Pre-install the riser (onshore) on the platform.
2.
Cap off the pipeline and lay it down.
3.
Measure the distance from the end of the pipeline to the riser flange.
4.
Lift the pipeline on davits.
5.
Cut and weld on the flange.
6.
Lower and bolt up the flange.
The choice of method varies with the OPCO’s preference and experience. 300- to 600-Foot Water Depth. For pipeline diameters up to 16 inches, a preinstalled J-tube tie-in method is frequently used. Refer to Section 940. (However, a Jtube cannot be used with concrete coated pipe. For this case, the J-tube uncoated riser pipe may require an increased pipe wall thickness.) This method includes the following procedural steps [36,39]:
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1.
Install a J-tube on the jacket during fabrication.
2.
Position the lay barge adjacent to the platform.
3.
Release a spring buoy near the J-tube mouth and pass a wireline from a pulling device down through the J-tube and out to the lay barge.
4.
Attach the wireline to the pipe end.
5.
Pull the pipeline into the lower end of the J-tube as the lay barge continues to assemble and pay out pipe.
6.
Continue pulling until the pipe end is above the water level.
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7.
A Splashtron plug on the riser pipe is used to seal with the J-tube at the J-tube Bell Mouth.
8.
Fill the annulus with corrosion prevention chemicals.
For pipe diameters from 16 to 22 inches, a diver-assisted tie-in to a preinstalled riser with a flanged spool piece is typically used. 1.
Install a flange and cap on the pipe end and lay the pipe on the bottom.
2.
Deploy divers to obtain measurements between the flanges with a template.
3.
Raise the template to the surface and fabricate the spool piece on the lay barge.
4.
Lower the spool piece to the bottom and make-up the flanges with divers.
Hyperbaric welding is a feasible alternative method for making tie-ins at the base of a riser and is preferred by some OPCO’s. This tie-in method has the advantage of providing an all welded pipeline-to-riser tie-in and can be used for very large diameter risers. Specifications for a J-tube Riser pipe installation in a maximum water depth of 390 ft are contained in COPI/CABGOC’s Cabinda Areas B&C Pipeline Installation and Testing Specification 20.02-CBC [39]. 600- to 900-Foot Water Depth. Saturation diving is feasible in this water depth range, but is generally not preferred for J-tube riser installation because of the increased cost. An ROV is therefore used for tie-in procedures instead of divers. For pipe diameters up to 16 inches, the preinstalled J-tube method is applicable. Procedures involved are similar to those used for water depths between 300 and 600 feet except in this case, where the ROV is used for the hook-up of the wireline to a messenger wire. For pipe diameters from 16 to 36 inches, a diverless tie-in is recommended. The pipeline is tied-in to a preinstalled riser by means of a spool piece equipped with mechanical connectors, landing bases, and swivel joints. (Swivel joints may be eliminated if the system has flexibility.) This method includes the following procedural steps:
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1.
Install a landing base with a mating connector on the end of the pipeline and lay the pipe on bottom. (Similar provision is required on the riser end.)
2.
Measure the distance between the two end connectors with the aid of an ROV.
3.
Return the measuring apparatus to the surface.
4.
Fabricate a spool assembly on the barge.
5.
Lower the spool piece into position.
6.
Activate the final connection with the aid of an ROV.
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Other tie-in methods such as hyperbaric welding or atmospheric chamber welding are not included in this water depth range due to their relatively high cost. However, if a welded joint is the prime consideration, hyperbaric welding can be used. 900- to 1,200-Foot Water Depth. In this water depth range, preinstalled J-tube risers and diverless mechanical tie-ins to preinstalled risers are typically used. For a pipe diameter of 12 inches, a J-tube has been used in a water depth of 1,350 feet in the Gulf of Mexico. 1,200- to 3,000-Foot Water Depth. Diverless mechanical tie-ins to preinstalled risers or riser bases are considered for all pipe diameters in this water depth range and deeper (see Section 980).
Retrofitted Risers Retrofitted risers can be a major expense in deepwater where saturation diving is required. Riser clamps have also been installed using ROV’s or a diver in a one atmosphere diving suit. Project Specifications for a retrofitted riser installation in a water depth of 685 ft are contained in CUSA’s Garden Banks 191/236A Pipeline Installation and Testing Specification. A copy is available from CPTC’s OS Group in San Ramon, CA. A retrofitted riser method has also been developed by CUK for the Alba project in the North Sea.
Green Canyon Blocks 161/205 - Deepwater Pipeline Study [41] The objectives of this study were to examine the feasibility of the deepwater pipeline and flowline installation concepts for the field, to develop a design at a conceptual level of detail and to provide recommendations. Aspects covered include: • • • • •
Pipeline & Flowline Design Operation Problems Pipeline Installation Tie-in Methods Maintenance & Repair Methods
Two options considered were a 25 mile route to Shell’s Bullwinkle Platform in Green Canyon 65, located in 1,350 ft water depth or a 60 mile route to Chevron’s South Timbalier 151 Platform located in 150 ft of water. A third option not considered in this particular study, would be a subsea tie-in to Placid’s Green Canyon 29 template or pipelines, located in 1,540 ft water depth. Cost aspects were not included in the scope of work. This report is “For Company Use Only”.
GC161/205 - Risers and Tie-ins - Conceptual Design - Final Report [38] The proposed production system concepts for Green Canyon 161/205, located in a water depth of 2,670 ft, are a compliant tower, tension leg platform or semisubmersible. These systems and their pipelines, risers and connections were analyzed to select preferred pipeline riser and tie-in methods for the oil and gas sales lines and remote oil and/or gas template flowlines for each platform system [38].
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Installation procedures, design/construction schedules and cost estimates for each of the configurations are presented in the Final Report. Data supplied by Chevron and vendors/manufacturers during the course of the study and engineering calculations/analyses are presented in the Appendices. This report is “For Company Use Only”. This report is useful for deepwater pipeline/flowline riser and tie-in conceptual design, including selection of preferred methods.
Subsea Hot-Tap-Lateral Tie-In The tie-in method consists of making a hot-tap on an existing trunkline and connecting it to the incoming lateral by means of a spool piece. (Also see Section 952.) In shallow water the operation is carried out by divers. This method has the following typical characteristics: • •
The pipeline being installed is a lateral and is tied in to an existing trunkline. Materials include the hot-tap saddle, valves, flanges, and a spool piece.
Hot-taps would probably not be required in water depths beyond 600 feet. Subsea lateral tie-ins in deepwater are typically based on a diverless mechanical tie-in, as described for the deep water riser tie-ins [40].
Subsea Mechanical Hot Tap Tie-in Installation Prodecure Design/Specifications Conceptual design of the subsea mechanical hot tap tie-in assembly and spool piece shall be as required by the Company’s specifications. Detail design is the responsibility of the Contractor and supporting documents shall be issued to the Company for approval. The Contractor shall design the subsea mechanical hot tap tie-in valve assembly installation procedure to ensure that the assembly is properly buoyed with temporary buoyancy for safe installation that will cause the assembly to be installed in a near vertical (for a vertical hot tap) or horizontal (for a horizontal hot tap) orientation. The orientation of the hot tap assembly shall be within plus or minus ten (10) degrees of vertical or horizontal respectively. During installation, the orientation of the assembly shall be visually monitored to determine that it is within this required orientation tolerance. The Contractor shall ensure that the stresses do not exceed 80% of yield. The Contractor shall prepare a subsea hot tap tie-in assembly design and installation procedure, with supporting calculations and drawings for approval by the Company. The design shall be included in the “Design Report” and the installation procedure in the “Pipeline Installation Manual.”
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State-of-the-Art Study of Subsea Hot Tapping Systems Final Report and Appendix (Chevron/H. O. Mohr) [59] During the past several years, hot tapping of offshore pipelines has increased dramatically. The purpose of this study is to investigate and document the state-ofthe-art of subsea pipeline hot tapping systems. The study objectives are: 1) To investigate and document worldwide subsea hot tap installations; 2) To obtain comments from pipeline operators relating to the installation, performance, and reliability of existing hot tap installations; 3) To describe hot tapping methods and components available; 4) To discuss mechanical vs welded, horizontal vs vertical, and deepwater hot tap installations; 5) To discuss design, planning, construction, operations, maintenance and safety considerations; and 6) To provide subsea hot tapping procedures, typical specifications, vendor and contractor information. The potential application of this technology is offshore pipeline design and construction, pipeline tie-ins, pipeline rerouting or platform bypass.
966 Inspection During Installation This section discusses who should supply inspection services and what should be inspected during pipeline installation from a lay barge. Testing of completed subsea pipelines is also discussed briefly.
Contracting: Company Direct vs Contractor Subcontract - Supplied Inspection Services In an offshore operation, the spread cost may be in excess of $100,000 per day. It is therefore desirable to minimize downtime, which is charged against the Company’s account. Radiography and surveying are two items which the industry has used with either company or contractor subcontracting. If tight specifications are agreed to and the price is attractive, serious consideration should be given to including these services in the contractor’s scope of work. The Company Representative or inspector(s) would then enforce the specifications and still retain ultimate approval for acceptance or rejection.
Inspection from the Lay Barge Where joints are made up into the pipeline one at a time in a continuous operation, there is an opportunity to use different inspection procedures while installing from a lay barge. These procedures are discussed next. Joint Prep. Joints are moved to the pipe rack prior to the line-up station. There is sufficient time to measure, clean, and generally inspect. In some instances the ends are rebevelled. This ensures that the ends are in good condition and affords an opportunity to use an optimum bevel, if it is different from that ordered from the mill.
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Concrete Coatings Concrete coated pipe should be checked for damage before and during installation. Divers can be used, at four hour intervals, to observe any coating damage after going over the stinger. Pipe Tally. As the barge moves along the right-of-way, its position is correlated with the amount of pipe laid. The pipe tally is usually done on a shift (12-hour) basis, and a record is made of the joint number, mill joint number (this ties a joint back to the mill certificate, if used), length, weight coating thickness, and special features such as anodes or tap valves. Weld repairs are also noted. The pipe welded per shift and total to-date are recorded. These data are ideally suited for a PC spreadsheet. (The contractor prepares them for Company approval.) Tension. Pipe tension is a key variable in controlling pipe laying stresses (see Section 936). To ensure that the tension stays in the proper range to avoid excessive stress in the pipeline during laying, the actual tension is compared with the Contractor’s calculated tension requirement. Laying stresses are thus limited to a maximum of 80% of the minimum pipe yield strength. Calculations are made prior to construction, and plans are prepared for the tension required along the route. During construction a stripchart records the hydraulic pressure applied, from which is calculated the applied tension. The strip chart recorder also has a digital readout. A tensioner gage with an analog dial is also used. The tension gaging devices should be observed each time the barge moves up, usually about 10- to 15-minute intervals, and tension should not exceed 20 percent of nominal tension (see Section 936). The stripchart recorder should be calibrated before use and inspected each day or two to ensure it is still correctly calibrated. Welder Identification. In-line welders can be tracked using records of who was working at each station during each shift. Therefore, there is usually no need to mark each weld with the welder’s unique identification. Identifiers should be assigned so they can be employed if necessary. The contractor’s welder qualification/test procedure should be approved by the Company. Weld Inspection. The quality of welds made during the installation process is ensured by nondestructive testing on location. (Refer to Section 632.) Radiography is the most widely-used method of testing, because a permanent record is generated. Ultrasonic testing is also useful. Safety precautions are necessary for barge personnel during pipeline inspection. Adequate shielding must be provided. For radiographic inspection, use of an internal unit is much quicker and permits single-wall exposure/single-wall viewing. Magnets placed on either side of the weld serve to target the crawler and properly position it. A cable attached to the crawler runs back to the lineup station and is “dogged-off.” This cable lies at the bottom of the pipe. Special cable materials may be used so that the cable will not affect the radiograph. (If a weld repair is made to the lower part of the pipe, then the cable should be removed from this area; otherwise, the cable could become welded to the pipe.) In accordance with 49 CFR 195.234, 100 percent of the welds on offshore U.S. DOT pipelines must be tested. All test records, including radiography film, must be
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kept on file for 3 years after the pipeline is placed in service. (Refer to Section 631 - Regulations and Codes, concerning pipeline welding.) Stinger Configuration. Laying stresses are calculated with an assumed barge/stinger configuration (see Section 936). Several times per shift, usually every 4 hours, the pipe/stinger configuration is checked by using a pneumo (pressure gage, see Section 968) to record the depth below water at known points. Diver or ROV observation of pipe lift-off and pipe-to-stinger roller interaction/location is also used. These results are compared to those anticipated, and adjustments are made in the pipe tension, stinger configuration, or barge orientation as necessary. Buckle Detectors. A device with a gaging plate tied back to the pipe on the barge by cable can be placed beyond the sag bend to detect buckles. The device stays in the same position relative to the barge as the pipe is laid. If the pipe should buckle, cable tension would increase as the barge is moved forward, and the buckle detector senses this increase. The buckle detector system can result in lost time if the cable should part or if the gage hangs up. Because of this, contractors and the Company prefer not to use them for pipe diameters less than 20 inches. If divers or an ROV are monitoring barge position, tension, and the suspended pipe configuration, information will likely be available to suggest inspecting for a buckle. ROV’s should be considered for large pipe diameters, including 24 inch OD. Lay Barge Positioning. Onboard surveyors are employed to track the barge position and its relationship to the right-of way. They should also locate anchor placements. A radio or satellite positioning system is normally used on the barge and anchor handling boat. The use of an ROV or side scan sonar to confirm the preconstruction calculations is discussed in the following paragraph. Inspectors should check with the surveyors regularly to confirm that the system was properly set up, that the position correlates well with the amount of pipe laid, and that the position is correct in relation to the right-of-way centerline.
Environmental Criteria The Contractor should monitor and record the wind speed and direction, and the wave height, direction and period at least every six hours. The seastate for abandonment of pipelay, if required during construction should be recorded, with the date and time. Touchdown. Calculations before and during construction can predict the touchdown point (see Section 936). Using an ROV with a positioning system tied back to the surface or using a side scan sonar or a trailing work boat will permit verification of this. ROV’s with a 1500-foot umbilical are available to allow deployment from a barge. This technique should be considered if a complete understanding of the lay configuration is necessary. Vertical Curvature. Construction specifications limit the allowable vertical curvature. In most instances, the sea floor is flat and/or the curvature is large, allowing the use of pneumo readings (depth measurement, see Section 968) to verify compliance. Where curves are relatively small, pneumos may not be accurate enough. A more accurate method, however, is not readily available. A scheme using lasers, change in pipe angle, etc., can be developed but will take preplanning.
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Pipe Burial. Specifications normally call for a burial depth from natural sea floor to the top-of-the-pipe. (Also see Section 968.) Pneumos give a reasonable indication of the situation, and divers or ROV’s can spot the probe for readings. Due to the movement of seabed material during burial, referencing the natural sea floor requires an offset measurement. Quick backfill requires inspection while jetting. If the pipe remains exposed, it can be inspected at a more convenient time. When plows or trenchers are used for pipe burial, only minimum inspection may be required if the trenching tool operation can be confirmed.
Testing Gaging and hydrotesting for offshore pipelines are similar to those employed for onshore pipelines, except in the area of leak detection. Additional testing is used to verify the position, configuration, and cathodic protection for offshore pipelines. Leak Detection. Dyes are used in the inhibited seawater hydrotest fluid to identify a leak. The dyes are very luminous in extremely small concentrations. Divers, ROV’s, or submersibles may be used to check the line in the area of a surface indication, or they may track the line completely. Pipeline Position. In shallow water, divers are normally used to confirm pipe position for critical operations. Side scan sonar or an ROV deployed from a surface vessel could be used to fly the pipeline. Fixes can be taken periodically to locate the line. Data can be reduced in the field to compare predicted versus actual lay positions. Configuration. A subsea TV video of the pipe leaving the last roller on the stinger can be used to evaluate coating damage. The pipeline can be viewed from the top and both sides by using diver(s) or an ROV. A video tape can be made to determine the weight/joint coating condition, seabed construction or scour, spans, etc. Visibility can be a problem in high energy areas. Diver inspection using “feel” can be used in these circumstances if the line is on the sea floor. Cathodic Protection. After the pipeline is installed, an ROV equipped with a probe can be used to measure the potential difference and current flow of the pipeline anodes. This system confirms that the anodes are functioning properly and gives an indication of the corrosion coating condition.
967 Shore Crossings At shore crossings in water depths to 12 or 26 feet, a pipeline should be buried in order to protect it from the effects of waves, currents, and other hazards. The extent of the pipeline shore crossing is established from shoreline and profile erosion considerations due to storms. The length of the offshore segment varies depending on waves and littoral currents. The pipeline should normally approach shore at a 90degree angle to the shoreline, to minimize wave loadings on the pipe. For shore crossings an on-bottom stability analysis should be performed during the conceptual design phase of the project.
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Depending on the shoreline profile, soil conditions, and accessibility, shore crossings are classified into the following types.
Jetted Open Trench Beach crossings of this type are assumed to have the following characteristics: • • • • •
Access canal for the jet barge The pipeline is filled with water for trenching Sandy or silty soil No reefs or sand bars that would limit the use of a barge jetting spread Backfill not required
For this operation both air and water jetting equipment is used: air for hand jetting, water for machine jetting. Machines do 90 percent of the work. Typically, six passes or fewer are required for a complete jetting operation. Normally, the top of the pipeline is buried 10 feet below the undisturbed sea floor.
Dredged Open Trench Beach crossings in areas where a jetting barge cannot approach the shore or where the soil conditions are not suitable for jetting are often excavated with a clamshell or cutter-suction dredge. Typical characteristics for a dredged shore crossing are: • • •
Sand or stiff clay soil, no boulders Shore crossing excavated immediately before the pipeline is pulled ashore Backfill not required
Sheet Pile Retaining Walls (Trench) Sheet pile retaining walls may be necessary when littoral currents deposit material faster than equipment can keep the trench open. Sheet pile retaining walls may also be required in areas where environmental considerations restrict trench width. Normally, the length of this type of shore crossing is less than 400 feet. The trench depth is such that the top of the pipeline is kept 10 feet below the undisturbed sea floor. A trestle is constructed either alongside the sheet pile trench or on top of the sheet piling itself to support the pile driver and crane.
Difficult Crossings Difficult shore crossings are characterized by one or more of the following conditions:
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Essentially level but relatively wide shore zone such as tidal flats in areas with excessive tidal range
•
Rock or coral-like reefs
•
Severe and/or numerous changes in terrain elevation (cliffs, dunes, etc.)
•
High littoral currents, creating vertical hydrodynamic forces when large diameter pipelines are exposed over great lengths
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In areas with rock or coral-like formations, blasting will be necessary to make the trench for the pipeline. Directional Drilling. In areas with bluffs, it might be prudent to install the shore crossing by drilling a directional pilot hole and then enlarging the hole by a reaming operation. (See Appendix B.) Protection of Pipelines at Difficult Crossings. With every type of shore crossing used, the pipeline should be provided with adequate protection against floatation. Usually this protection is provided by concrete weight coating or concrete saddles. The onshore portion of the shore crossing is liable to be flooded by sea level set-up due to storm surges. Concrete saddles are normally used in this area to provide the necessary stabilizing force. The thickness of concrete coating and the size and spacing of concrete saddles are functions of pipe diameter and oceanographic conditions. In areas of high scour action, such as the surf zone, rock cover is an effective means of scour protection [24]. Where wave forces are not large, a pipeline may be covered with a simple rubble mound for scour protection.
968 Pipeline Burial or Trenching The pipeline is buried to improve stability, to provide protection against storms, ship anchors, fishing nets, dropped objects, or to correct spans, etc. Government regulations in some areas of the North Sea require pipeline burial based on technical considerations regardless of water depth, while other areas, such as the Gulf of Mexico, require burial only to the 200-foot contour. Offshore California regulations require pipeline burial in water depths to 12-ft. For newly laid lines Offshore Cabinda, we are burying lines to a maximum water depth of 26-ft. Since pipeline burial can represent a substantial cost, government requirements for pipeline burial should be confirmed, if possible, during the early stages of a project. In shallow water areas, pipelines are buried near platforms for a distance of 200 feet, then tapered to the sea floor. For pipeline burial near the base of the riser, divers use a hand jetting method.
Choosing a Trenching Method The efficiency of a trenching method depends on many factors, including soil type, pipe size and weight, water depth, production rate, sea state, trench stability, soil disposal, and power consumption. Detailed discussions of these factors and trenching regulations in different parts of the world are available in Reference [3]. Pipeline burial is normally accomplished by one of the following methods:
Jetting Conventional Jet Barge and Sled. Jetting is a widely used pipeline trenching method. The system consists of a jetting sled that fits over the pipe and dislodges soil from around the pipe by high pressure water jets. The jet nozzles must be capable of handling the type of soil encountered. The spoils are removed and deposited on the sides of the trench via eduction pipes, using airlift or water eduction as
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the driving mechanism. The surface support vessel is a barge with a mooring system, pumps, air compressor and an A-frame with winches for handling the sled. Figure 900-50 illustrates a typical high-pressure jet barge. (When a simultaneous lay-bury technique is used, the pipe is full of air but the submerged weight prevents the pipe from floating. This applies to smaller-diameter pipe.) Fig. 900-50 Conventional Jet Barge and Sled
If the pipeline is already laid, it should be filled with water prior to jetting. This is because the jetting operation causes part of the soil to form a liquid more dense than an empty pipe. The peak daily production rate is about 1 mile per day for each pass required. High-pressure jetted trenches tend to be wide at the mudline, and in granular soils, side slopes of up to 1:20 are expected. Consequently, these trenches offer limited protection to a pipeline. Divers observing jet sled operations should do so from a safe distance. Land and Marine Trenching Machine (TM). A significant variation on the jetting concept is embodied in the TM series of trenching machines, developed and operated by Land and Marine Engineering Ltd., England. Figure 900-51 shows the arrangement of the TM jet sled. The TM devices use low pressure high volume nozzles to fluidize the soil, which is then removed via sand pumps. This permits cutting a narrower trench with less disturbance of the surrounding soil. These machines are most effective in fine granular materials, but function poorly in stiff clay and well cemented materials. Pumps are located on the machines rather than up on the barge and are powered through an electrical umbilical so that hydraulic power losses are eliminated. Thus,
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Fig. 900-51 Land and Machine Trenching Machine
power requirements, barge size, and fuel expenditures are less than for conventional jet sleds. The trenching rate of these machines is about the same as other machines. One disadvantage is that the smallest diameter pipe they can handle is NPS 24.
Mechanical Cutters Heerema’s “Eager Beaver”. The Eager Beaver trenching system is illustrated in Figure 900-52. This machine uses three chain-type cutters to form the trench. The first two cutters make a slope of 60 degrees to either side of the vertical and from the wedge outline of the trench. The third removes the material of the remaining portion of the cross section. Crawler treads support and propel the machine, which does not touch the pipeline at any time. Surface support is provided from a dynamically positioned (DP) supply vessel. Based on contractor estimates, the rate of trenching is between 0.9 and 2.4 miles/day. Kvaerner Trenching System. The Kvaerner Trenching System consists of a rotating cutterhead at the end of an arm. A schematic of this device is provided in Figure 900-53. The machine is ballasted to near-neutral buoyancy, and is selfrighting during operation. The drive mechanism consists of traction motors attached to rollers that are clamped to the pipe. A dynamically positioned mother-ship is
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Fig. 900-52 The Eager Beaver Trenching System
required for surface support. Although this equipment has been field tested, no commercial pipeline trenching work has been undertaken. Other Mechanical Trenchers. During the past several years Saipem, Brown and Root, Subsea Oil Services, Undersea Systems, Tecnomare, and others have been developing different versions of mechanical trenchers. Some of these will probably be commercially available in the future.
Plowing Underwater plows make a clean-cut trench in the sea bottom, with little or no reduction of strength of the adjoining soils. These plows slope the sides of the trench more steeply than conventional jetting does. Figure 900-54 depicts the three different plows that have been used to trench pipelines. Plowing is done either before, during or after pipeline installation (called preplowing, coplowing, and postplowing). Preplowing. This method is most suitable for bottom towed or bottom pulled pipelines. Precise navigational aids are required to place the pipeline in the excavated trench, which gets more difficult as water depth increases. Coplowing. The plow is placed immediately ahead of the pipeline being installed. This procedure is suitable for both the bottom tow/pull methods as well as the lay barge method of pipeline installation.
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Fig. 900-53 The Kvaerner Trenching System
Coplowing -Inda Pipeline, Nigeria. Coplowing was the method employed on the Inda pipeline installed near the Bonny River in Nigeria. The soil in the area is a mix of sand and silt deposited by the Bonny River, and the seabed slope from the shore to deepwater is very gradual. Bougyues Offshore used this method to successfully pull and bury the 8 inch Inda pipeline a distance of 1,500 ft from the beach before the pulling tension became too great for the pipe and the pulling winch. (The remainder of the shore approach was pulled without trenching and a tie-in was made. The un-plowed section proved to be self-burying.) Very good soils data along the route is required to adequately assess the risk of using a plow for burial. In the case of the Inda pipeline, the soil stresses proved to be greater than anticipated and therefore the installation was a limited success; however this is a viable option for installing and burying pipelines in shallow beach approaches when soil data indicates that pipe stress will not be a problem. Postplowing. A vessel (or vessels) pulls the plow along the pipeline after installation. Rollers mounted on the plow keep the plow safely away from the pipeline and guide the plow along the line. The rollers are equipped with load cells to indicate loads on the pipe caused by vessel excursions.
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Fig. 900-54 Pipe Trenching Plows
The main advantage of plowing is high productivity. Plowing rate is governed by the rate of advance of the tow vessel, which in turn depends on soil conditions. Typically, for each pass, over a 1-knot speed can be achieved with a tow vessel such as a large tug, and about 0.2 knots with a pull barge, which requires constant anchor handling.
Dredging A pipeline can be installed in a trench that has been pre-excavated by a dredge. The dredged trench must be reasonably wide at the base to allow the pipeline to be installed without necessitating unusual specifications or position control of the installation vessel. The degree of pipeline stability against hydrodynamic forces in such a wide trench is very low and backfill of the trench may be necessary. Dredging is not typically used for general pipeline protection, because this type of equipment does not produce a smooth trench bottom unless special control require-
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ments are adapted. Alternatively, the trench can be leveled after dredging by dragging.
Fluidization Fluidization involves forcing a large volume of water into the soil surrounding the pipe, thus reducing the soil density and allowing the pipe to settle in the soil. The main advantage of this method is that, during fluidization, the pipe is immediately covered with soil and full protection is achieved. The main disadvantage is that it is effective only in sandy soils, and considerable variations in soil type may be encountered along a pipe route.
Self Burial If the seafloor soil is very soft, sometimes the pipeline undergoes self burial. The self burial of pipelines depends on several factors. The following equation can be used to predict pipeline sinkage [13], [14]: π Dγ′ γ p 1 z 0.123 γ′z = --- -------- ------- – --- ------- + 3.74 ---- D 4 Cu γ′F 2 Cu (Eq. 900-43)
where: Cu = Undrained shear strength of the soil, psf D = Outside diameter of the pipe, ft. z = Sinkage of the pipe, ft. γ′ = Submerged unit weight of the sediment, pcf γp = Submerged unit weight of the pipe, pcf F = Factor of safety In this equation zero sinkage (z=o) actually means that the pipe is halfway submerged in sediment. Therefore, when the value of dimensionless sinkage Z/D is 0.5, the pipeline is considered to have undergone self burial.
Confirming Pipeline Depth after Trenching The depth is measured using a “PNEUMO” gage. This gage system consists of a high-pressure air source located on the vessel with a hose running vertically to the sea floor to a diver. The air is directed into the hose after the diver places the end at the pipeline depth to be checked. When bubbles are received at the sea floor the surface air source is shut in. A reading is then taken of the stabilized pressure and from that the pipeline depth is determined. In deep water, an ROV could be equipped with a depth gage.
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Spanning A potential area for pipeline damage is the pipeline span. Spans may occur when a line is installed over an uneven seabed or where the bed below a section of the pipe is eroded by local scour. When a line is exposed and spans above the seabed, the water particle flow paths around and under the pipe change radically from the partially buried case. The interaction between any consequent line vibration and these flow patterns are poorly understood but critical to the assessment of pipeline spans. The bending stresses induced in the pipe wall or concrete coating may either result in fatigue failure of the pipe wall or loss of weight coating leading to pipeline instability, see Section 968 for calculation references. The decision on intervention needed to correct spans under previously installed lines will depend on a balanced consideration between potential damage and cost of correction. Spans on new lines are corrected by the Contractor, prior to Company acceptance of the completed line per the pipeline installation specifications.
Alternate Stability Methods for Marine Pipelines [24] Reference 24 discusses alternate (other than weight coating) methods of stabilizing marine pipelines against hydrodynamic force induced movement. Methods are described, advantages/disadvantages listed, construction equipment identified, and where possible, preliminary design procedures defined. The selection of an appropriate stabilization method is addressed by means of decision flowcharts. Vendor data and case histories have been included as separate appendices. Methods investigated include: 1) trenching, 2) trenching w/backfill, 3) armor rock cover, 4) directional drilling, 5) screw-in and drill-in anchors, 6) protective mats and 7) grout filled bags. Concrete coating is usually the most cost effective method to achieve stabilization. However, in some cases sufficient concrete coating cannot be added to stabilize the pipeline. Examples illustrating this include: 1.
When such large amounts of concrete coating are required to stabilize the pipe such that it cannot be installed by conventional equipment.
2.
When such large amounts of concrete coating are required to stabilize the pipe that just lifting the pipe joints will cause damage.
3.
When the pipeline is to be installed using the reel method, concrete weight coating cannot be used.
4.
When pipe sinkage into the soil is a concern. Such as in soils that are easily liquefied.
The Company has used alternate methods offshore CA, Nigeria, Cabinda, Zaire, U.K. and Australia. The report is “For Company Use Only.” Copies are available upon request to the OS Division of CPTC in San Ramon, CA.
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This report is useful for conceptual and preliminary design of pipelines for onbottom stability in cases where weight coating may not be the best method. The currents produced at the mouth of the Zaire river offshore Zaire are very high. This results in special requirements for on-bottom stability, as follows.
ZAGOC/COPI Pipeline Anchor Study Final Report [27] Submarine pipeline anchoring requirements are evaluated for offshore Zaire development areas. The evaluation includes pipeline on-bottom stability analyses, anchor design & installation review, and an assessment of alternative stabilization concepts. ZAGOC/COPI specified that the evaluation be conducted for 4", 8", & 10" nominal diameter gas and oil pipelines. Results from on-bottom stability analyses indicate that all pipelines are unstable at any water depth (15-75ft) under installation and operation conditions. Therefore, onbottom stabilization is recommended for each pipeline. The anchor set design and installation procedure used in past anchoring operations are adequate. Pipeline anchoring should be performed as soon as possible after pipeline laying operations. The following stabilization practices were evaluated for feasibility and cost: 1) Anchoring, 2) Concrete Coating, 3) Burial, and 4) Concrete Mats. Depending on water depth, results indicate that significant cost savings can be obtained by concrete coating or burying the pipelines, rather than anchoring. This report is “For Company Use Only”.
969 Pipeline Crossings Because pipeline crossings may cause higher maintenance costs, they should be avoided wherever possible (see Section 921). Where pipelines must cross each other, the barrier between them must be designed to prevent damage to the pipelines and to provide a favorable cathodic environment for corrosion control. A minimum of 18 inches of vertical clearance should be maintained between the two crossing pipelines by the use of sand/cement bags, grout-filled bags, or pillow-type separators [39]. The MMS requirement (30 CFR 250) of 18 inches is commonly used in the Gulf of Mexico. The various codes and regulations with regard to the clearance distance between two crossing pipelines are: Code
Clearance, In.
ANSI B31.4, para. 434.6 (c)
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ANSI B31.8, para 841.143 (a)
6
49 CFR 192, para 192.325 (a)
12
49 CFR 195, para 195.250
12
30 CFR 250, para 250.153 (a) (3)
18
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Offshore pipeline crossings are typically made in one of two ways. In some shallow water OCS areas, government regulations require that all pipelines be buried. Figure 900-55 shows a typical Chevron Pipe Line Company crossing in the Gulf of Mexico, where pipelines are buried in water depths to 200 feet. The existing pipeline is lowered by jetting. The lowered line gradually slopes up from this point to the original depth, over a length that prevents over-stressing the line. The minimum crossing angle should be 45 degrees to minimize the costs/area. However, in some cases this may not be possible. Crossings should be avoided near platforms, if possible. Figure 900-56 illustrates a crossing in greater than 200 feet of water for the Gulf of Mexico or for shallow water in the Gulf of Cabinda, where the existing pipeline is resting on the sea floor. (The minimum cover of bags over the top pipe should be 1 foot, with a minimum width of 1.5 x pipe O.D. or 4 feet, whichever is larger.) The installation procedure for a pipeline crossing is as follows: 1.
Locate and mark the existing line (requires a survey crew, magnetometers, divers, buoys, etc.)
2.
Lay the new line across the existing line.
3.
If required, lower the existing pipeline by hand jetting (requires a diving spread).
4.
Place sand/cement bags or other type of separators over the existing pipeline at the point of crossing. (The cement-to-sand mixture is typically 1 to 3 parts by weight, with the slope, typically 1 to 3.)
5.
If the existing pipeline is to stay at the sea floor, then additional supports for the new line are provided as shown in Figure 900-56.
6.
Trench and/or hand jet the new line, if it is to be buried.
Alternative Methods The design shown in Figure 900-56 can cause problems in high current areas: the bags may provide uneven support, a three-point loading; scouring may occur; and lateral stability of the upper pipeline may not be ensured. These problems may be alleviated as follows: 1) Jet down the lower pipe to a depth of 18 inches plus its diameter, 2) Install the upper pipe on the sea floor and 3) Make the bottom of the trench 10 feet wide at the top of the lower pipe. Regarding type and arrangement of bags, consider two options as follows: Option 1: Use grout-filled or sand/cement bags as in Figure 900-55 to achieve separation and lateral stability. Fill the trench, level with the mudline, with bags. Above the mudline use a pyramid shape, with a slope of 1 to 1. The minimum cover of bags over the top pipe would be 1 foot, with a minimum width of 1.5 x pipe O.D. or 4 feet, whichever is larger.
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Fig. 900-55 Typical Underwater Pipeline Crossing to 200 Feet Water Depth
Notes:
1. 2. 3. 4. 5.
Cement and sand mixture shall be 1 to 3 parts by weight. Bags shall be made of closely woven material with a wicking action. After filling the bag, it shall be closed by sewing or equivalent but not by bunching and tying the end. Sandbag shall weigh approximately 80# / bag with .91 cu. ft. in. volume per bag. 1 1/2 times O.D. of proposed pipeline or 4’, whichever is greater.
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Option 2: If it is more cost effective to do so, use an Alpha (single) bag design in place of the grout-filled bags in the proposed Option 1 design.
Pipeline Spanning Calculations The pipeline crossing shown in Figure 900-56 should be checked for vortex shedding and stresses. See ANSI B 31.4 (402.3 or 437.4) or B31.8. Checking should include a calculation for the allowable lengths of free spans. Vortex shedding calculations may be performed using the D.N.V. Rules for Submarine Pipelines, Appendix A.2.
970 Operations 971 Submarine Pipeline Repairs General The economic impact of a pipeline failure can amount to a substantial loss of revenue [3]. A fast response to a repair emergency is required. Various systems exist for subsea pipeline repair, and no one method is appropriate in all cases. Components needed for some types of repairs are stocked by operators/manufacturers. Pipeline operators are most concerned with those repairs required to be made on an operating pipeline as a result of corrosion, storms, mudslides, or damage resulting from marine operations, i.e., fishing (trawl boards), construction (anchors), supply boats, etc. When damage to an operating pipeline occurs that causes leakage, the line is immediately shut down, either manually or automatically, the regulatory authorities notified, and the total extent of the problem is determined. This includes field and office evaluation of the pipeline design, function, service, size, water depth, protection and cause of failure. A diver team and surface-support equipment are sent to the site to evaluate the type of damage, extent, and location. Contractors in the area are contacted to determine the availability of suitable equipment. The operator will evaluate the complete situation as soon as possible after the damage has been reported. Per 30 CFR 250.158(e), “The lessee or right-of-way holder shall notify the (DOI, MMS) regional supervisor prior to the repair of any pipeline or as soon as practicable. A detailed report of the repair of a pipeline or pipeline component shall be submitted to the regional supervisor within 30 days after completion of the repairs.”
Repair Methods and Practices Several methods have been used for the emergency repair of offshore pipelines. These methods can be divided into surface and subsurface repair methods. Subsurface repair methods include hyperbaric welding, split-sleeve clamps, and mechanical connection of a spool piece (see Section 952). These methods have been used for repairing midpoint damage in a pipeline and damage near a riser. The surface-
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Fig. 900-56 Typical Underwater Pipeline Crossing in more than 200 Feet of Water or Shallow Water in Cabidna
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welding repair technique is commonly used in areas such as the Gulf of Mexico, where pipeline diameters are relatively small, water depths are moderate, and weather conditions are typically favorable. Hyperbaric welding is more commonly used in the North Sea, where the large pipeline diameters, greater water depths, and often poor weather environment may limit the safety of lifting the pipe ends to the surface to make a repair. Mechanical connectors available for new construction (see Section 952) are also used for pipeline repair.
Surface Welding Surface-welding equipment is usually located on a pipelay vessel. This method involves lifting the pipe ends to the surface by use of the barge davits, then hand fitting and welding a spool piece to bridge the gap between the pipe ends, inspecting the welds, and lowering the pipe to the bottom. This method, used for a midpoint, shallow or moderate water depth “major” repair, involves the following steps: 1.
Survey and inspect damage to the pipeline.
2.
Plan the repair procedure. (This item can be critical for large-diameter pipelines and for water depths greater than 300 feet, where the lifting procedure must be carefully planned to limit the stresses in the pipe to a safe level during lifting.)
3.
Mobilize barge(s) to the site and moor over the damaged section.
4.
Inspect for damage, and if the pipe is buried, uncover a long section, perhaps 500 feet on either side of the damage using divers/hand-held jets. (The exact length is a function of pipe size, water depth, bend radius, etc.)
5.
Flush the oil out of the line with water, usually two times the volume of the line.
6.
Cut out the damaged section of pipe; dewater the line, if necessary, and retrieve the damaged pipe.
7.
Attach lifting cables to each section of the pipe on bottom.
8.
Lift both pipe ends to the surface by pulling on the davit cables according to a pre-planned lifting schedule. (Care should be taken to prevent buckling of the pipe by providing a limit on the minimum pipe bend radius. Also, the lifting schedule should be based on engineering calculations. See Section 940.)
9.
Cut and clean the pipe ends.
10. Fabricate a spool piece to fit between the two pipe ends. Weld the spool piece to the pipe ends, x-ray and coat the field joints. 11. Lower the pipe to the bottom while moving the barge laterally on its mooring lines until the pipe is on bottom.
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12. Hydrostatically test the line and rebury, if necessary. If damage is done to a pipeline riser located outside of the platform jacket or the pipe near the riser, then a modified surface-repair method may be used. The method involves lifting one end of the pipe to the surface using some or all of the barge davits, then welding the lower section of the riser to the pipe and lowering the pipe and riser as new sections of riser are added. If a significant length of the pipeline is also damaged, it is first removed. The remaining end of the pipeline is lifted to the surface and new pipe is laid up to the platform. The riser-setting operation then proceeds. The surface-welding method of repair is most effective in water depths up to about 300 feet. It can be used for greater water depths if the pipeline diameter is small or if buoyancy is attached to the pipe to control pipe stresses in the sag bend during the lifting operation. It may be necessary to use two (or more) barges to lift the two pipe ends to the surface.
Hyperbaric Welding In the hyperbaric-welding method, the damaged pipe section is cut out by divers and retrieved. A spool piece of the required length is fabricated on the surface vessel. The spool piece is lowered to the sea floor and two pup joints are used to connect the spool piece to each end of the line. Welding is done inside a welding habitat under the pressure at depth in a dry environment. This method is used in deeper water where surface welding is impractical or when the pipe ends are restrained by a riser, tap valve, or pipeline crossing. Typically, an alignment frame, a welding habitat, and a transfer bell are used to accomplish the pipeline repair by hyperbaric welding. The surface-support vessel may be a work barge or a vessel especially equipped for this work. Further detail is provided in Reference [3]. The high pressure dry environment affects the weld quality, and a prequalification test, under actual conditions (i.e., pipe type, welding rod, pressure, etc.), should be done prior to using this method offshore. This method has been applied most widely in the North Sea and is suitable for largediameter pipe. Water depth capability is limited by diver depth limitations, and the method has been demonstrated at water depths to 1,000 feet. It is expensive.
Mechanical Connectors Mechanical connectors (see Section 952) are also used to join the pipe ends during a repair operation. Several competing mechanical connectors are promoted for subsea-pipeline repairs. Among them are the Flexiforge manufactured by Big Inch, Gripper, HydroTech, and Camforge by Cameron. A rigid spool piece is used along with two mechanical connectors to bridge the gap between the two pipe ends. In general, of the “major” repair methods, mechanical connector repairs are the least costly and most rapidly completed especially in deep water (greater than 300 feet), when compared to surface welding or hyperbaric welding. “Minor” repairs use full encirclement sleeves (clamps); see the discussion below. These are the least expensive.
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The mechanical connectors are systems that include a means of attachment to the pipeline ends, provisions for axial length adjustment and swivels to accommodate angular misalignment (see Section 952). The primary equipment needed to make a repair using mechanical connectors includes a 200- to 250-foot-long surface vessel with mooring capabilities, diving support, surface pipe-welding facilities, a lifting crane, and bottom manipulating equipment. The procedure is similar if the pipeline is damaged near a riser at a platform. If the riser has been damaged, then a connector half may be preinstalled at the foot of the replacement riser section, prior to setting the riser. Procedures available for subsea pipeline repair differ somewhat by manufacturer as illustrated by the following.
Big-Inch Procedure A typical repair procedure using the Big-Inch Flexiforge connector is: 1.
Cut and clean the pipe ends.
2.
Lower the end flange connectors, and use the Flexiforge tool to forge them to the pipe ends.
3.
Make and lower a spool piece consisting of one slip joint and two ball joints.
4.
Align the flanges on the end connectors and spool piece. Have the divers insert the bolts and tighten. (A boltless flange can be used where the two flanges are compressed and connected using hydraulic power.)
Cameron Procedure For a discussion of Cameron’s pipeline repair procedure, see Section 952.
Gripper Procedure The Gripper procedure is: 1.
Cut and clean the pipe ends.
2.
Lower and stab each grip and seal connector coupling with the connector balls over each end.
3.
Make a spool piece with the ball connector cups.
4.
Lower the spool piece, and stab the connector balls into the spool cups. Make up and test the ball connection.
5.
Actuate and test the couplings.
HydroTech Procedure The HydroTech procedure is:
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1.
Cut and clean the pipe ends.
2.
Lower the HydroCouple connectors using a manipulating frame.
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3.
Stab the HydroCouple connectors over the pipe ends.
4.
Fabricate a spool piece with a ball on each end.
5.
Lower the spool piece and connect it to the misalignment flange (MAF).
6.
Have the divers insert and tighten the bolts.
7.
Set the seal (packer) and test the connections.
Small diameter lines (10 to 12 inches or less) in 200 to 300 feet water depth may be lifted to the surface for repair using a ball joint. The pipe is dewatered, if necessary, and raised by one or more lifting points. A ball-connector half is welded to the first pipe end. A joint or two of pipe may first be welded on to bridge the on-bottom gap between the pipe ends (see Section 952 for further discussion).
Full-Encirclement Sleeves (Clamps) Full-encirclement split sleeves or clamps are made by Pipeline Development Co. (Plidco), Gripper, and HydroTech. The Plidco split sleeve is sold for both onshore and offshore “minor” pipeline repairs. The appeals of the split-sleeve are simplicity and low cost for repair of a small leak or a weak spot in the pipe. This is usually the fastest, cheapest way of stopping a leak. To perform a repair with one of these sleeves, the pipeline must first be completely exposed by jetting. These sleeves are split in half axially and held together by studs and nuts. The larger sized units for subsea installations are hinged to facilitate assembly onto the pipe. The sleeve is lowered to the sea floor in an opened position, positioned over the leak and closed around the cleaned pipe. Studs and nuts are then inserted by divers and tightened to force the soft packing against the pipe OD. According to 30 CFR Part 250.153, when a pipeline is repaired utilizing a clamp, the clamp shall be a full encirclement clamp able to withstand the anticipated pipeline pressure. Plidco split sleeves have been used to repair many pipelines in the Gulf of Mexico, including the Company’s. These sleeves have typically been used for “minor” repair for pipe sizes from 3 to 20 inches.
Flexible Pipe Repair Flexible pipe, as manufactured by Coflexip, can also be used for subsea-pipeline repairs (see Section 956). Coflexip pipe is available with flanged-end connections or with plain ends that can be welded to a mechanical connector. In a repair situation, the required length of a spool cannot be known until the damaged pipe has been inspected and cut. As a result, it is either necessary to supply more than enough flexible pipe to add a rigid spool or to have qualified technicians and equipment to make up connectors/lengths onsite, to give length adjustment. Coflexip pipe provides large axial and angular adjustments that can preclude the need to reposition the pipeline ends prior to making a connection. Moreover, the Coflexip pipe remains permanently flexible. This can be an advantage in cases where a pipe failure occurs due to pressure or thermal effects or due to a mudslide.
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Guidelines for Subsea Pipeline Repair and Tie-In Systems [47] The subject AGA study presents a detailed overview of existing and developmental maintenance and repair systems for subsea pipelines and contains guidelines that identify economic aspects, capabilities and limits of repair systems. These guidelines are intended to encompass repair systems that are suited to a wide range of water depths, pipeline diameters, and local conditions. The major topics include: •
definition of the pipeline system characteristics, local conditions and nature of the damage;
•
assessment techniques to determine damaged pipe locations;
•
detailed information on damage types, level of severity, damage cause and required level of intervention for repair;
•
details of the limitations and capabilities associated with the actual means or mode of subsea intervention at the repair site, i.e. diver, manned submersible or remote vehicle (ROV);
•
details of minor, intermediate and major repair operations and associated techniques, hardware and procedures;
•
cost and schedule aspects of specific repair operations, covering a range of different representative repair cases.
Company Experience In terms of the Company’s experience, the most commonly used method for repair has been the application of full encirclement sleeves (clamps). Also, in the past, flanges, such as lapped joint flanges, were used to repair former Gulf Oil Company pipelines. Some pipelines were repaired using misalignment flanges. In shallow water, line repairs were typically made by conventional welding procedures using surface methods. Experience includes the general contractor’s experience/reliability and prior operator/engineer experience with a specific repair method. Most mudline repairs in the Gulf of Mexico have been done using surface welding and mechanical-connection methods. In the case of pipe and riser repair, most experience has been by the surface-welding method for small- diameter pipe or shallow-water depth. In relatively deep water (350 feet or greater) and for large-diameter pipe, riser repairs have been made using the mechanical-connection method. In the North Sea, the surface method has been used to repair a 24-inch pipeline located in a 450-foot depth, which was damaged due to a vessel dragging an anchor.
26-Inch Loading Line Repair at the El Segundo Refinery Hyperbaric welding was used in a 70 ft water depth to repair the 26-inch loading line at the El Segundo Refinery in California. In this case a barge was not available to lift the line. Buoys were used to lift it, with repositioning using an on-board winch located on the diving boat. Welding was limited to attachment of a flange on
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each end of the existing pipe. An inert gas was used for improvement of safety for the divers. The replacement pipe, a length of 160 ft was near surface-towed about 25 miles and lowered using cables. Then a spool piece was fabricated on the diving boat and lowered into position for attachment using bolted flanges.
12-Inch Pipeline Repair for ACT, Offshore China In August of 1991, Big Inch Marine Systems, Inc (Big Inch) was contracted by McDermott’s Singapore office regarding ACT’s urgent need for a 12" subsea pipeline repair system, offshore China. Big Inch shipped three 12" Flexiforge End Connector’s from it’s Houston inventory, along with the necessary installation technicians and equipment. Working in a 370 ft water depth from McDermott’s semisubmersible barge, the DB-100, divers cut away the damaged pipe section. Big Inch then “cold-forged” one 12" flanged Flexiforge End Connector onto the end of the pipeline. Total time for the connector installation from the time the forging tool left the deck until it returned to the surface was 80 minutes, with a forging time of 12 minutes. McDermott proceeded to lay away from the flanged End Connector and complete the pipeline installation. The remaining Flexiforge End Connectors remain in the ACT Group’s warehouse in China for use on any future emergency repair requirement.
Platform Riser - Inspection and Repair Methods [37] The purpose of this study is to identify methods that are currently available for offshore platform riser inspection, especially in the splash zone where corrosion is most severe, with or without shutdown of the pipeline. Methods for the repair of risers are identified, and brief installation procedures are described. A literature search was performed, and articles relating to riser/pipeline inspection and repair are included. Vendors were contacted and product literature relating to inspection and repair included. Volume I contains the study, a vendor list and vendor contacts. Volume II contains a literature search; and Volumes III-A and IIIB contain vendor data. Copies are available upon request to the OS Division of CPTC in San Ramon, CA. This report is “For Company use only”. The Table of Contents for Volume I is as follows: I. Introduction II. Inspection Techniques III. Repair Without Shutdown IV. Repair With Shutdown V. Appendix A - Vendor List VI. Appendix B - Vendor Contacts Volume II contains numerous articles on offshore platform riser inspection and repair methods. Volume III-A contains Vendor Data from: 1) RTD, 2) Ford, Bacon, & Davis, 3) Pipetronix, 4) Vetco Pipeline Services, 5) NKK, 6) British Gas, 7) T. D. Will-
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iamson, 8) IPI Services, 9) Enduro Pipeline Services, 10) Sonsub, 11) Foster-Miller and 12) Hydrotech. Volume III-B contains Vendor Data from: 1) International Composites, 2) Nowsco, 3) McKenna & Sullivan, 4) Oceaneering, 5) Rockwater, 6) Cooper (Cameron), 7) Big Inch Marine Systems, 8) Flexitallic Services, 9) Team, 10) IPSCO, 11) Daspit and 12) PLIDCO. This report is useful for offshore platform riser inspection and repair projects.
Subsea Repair of Gas Pipelines Without Water Flooding (AGA/J. P. KENNY) [60] To effect a major repair it is usual to open the pipeline to an external environment. In the case of a subsea gas line of considerable length this could necessitate partial or complete water flooding of the pipeline. Recommissioning and drying of the line may take considerable time in addition to the time needed for the direct repair operations. This is a study into the subsea isolation of pipelines without water flooding. The primary aims of the study were to: •
review the existing equipment, methods and vendors active at the present time;
•
to investigate future developments, the systems required, and the potential of the existing equipment to meet the projected demand, namely for isolation systems capable of performing in subsea, mid-line scenarios;
•
to outline the immediate industry requirements for development work and the concept and feasibility studies necessary to support the anticipated industry needs.
A basis for study was defined which considered a typical 300 km gas transportation line with various damage types occurring at either near platform, mid-line or near shore locations. The emphasis of the study is aimed at techniques capable of performing mid-line isolations as this is seen to be the area of most interest to the operator for future activities. It is evident that at least four remotely activated tools are now available and suitable for development to meet all the requirements of mid-line isolation. The study has also confirmed that there is an adequate number of well proven systems suitable for near platform or shore station deployment. Non-Intrusive systems consist of the following; 1) High Differential Pig Trains, 2) Non-piggable Tethered Mechanical Plugs, 3) Tethered Mechanical Plugs, 4) Remotely Activated Mechanical Plugs and 5) Pipe Freezing. Intrusive systems include: 1) Hot Tapping and Plugging,and 2) Combined Hot Tap and Tethered Mechanical Plug."
Shell Deepwater Pipeline Repair Methods (DPRM) (JIP) - Phase II - FINAL Report [43] DPRM-II is a plan for “surface layover” repair of damaged deepwater pipelines. The plan includes detailed design of the surface handling equipment necessary to repair 12, 14 and 16-inch pipelines in 1,000 to 4,000-ft water depths. With a modest
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further engineering effort the method could be extended beyond and below this range of parameters. The report consists of an engineering manual and two volumes of equipment data [42]. This study is the concluding phase of a joint industry program (JIP) to develop repair methodologies for deepwater pipelines. Principal conclusions from the study are: (1) The surface layover method has been sufficiently developed to permit repairs in all depths accessible to J-lay, without the need for offshore test confirmation. (2) By investing $650,000 (1991 dollars) for long lead components, mobilization time can be shortened from 16 to 3 weeks. This assumes that some components that are also needed for J-pipelaying would be available. (3) Approximately five weeks would be required to repair the line, not including mobilization. Total repair costs could reach $6 MM for Gulf of Mexico lines. (4) For deepwater pipelines, the probability of repair is about 10 percent for 25 miles of pipeline length per 25 years of life.
Diver Assisted Pipeline Repair Manual (PRC/AGA/H. O. Mohr) [61] The Pipeline Research Committee (PRC) of the American Gas Association (AGA) has sponsored this development project with the objectives of providing a guide for the identification and selection of an appropriate repair method, determination of the required service support, location of the appropriate repair hardware, and estimation of the time and cost associated with the repair. The manual is intended as an aid to the field engineer when planning a repair to an offshore pipeline in water depths from 0 up to 800 ft. For the purposes of evaluation, water depths of 0 to 50, 51 to 200, 201 to 400 and 401 to 800 ft are used. Line size is separated into: 6" and below, 8" to 12", 14" to 20", 22" to 30" and 32" and larger. The information is generally presented in tables and matrix type format. The first volume is intended to allow the field engineer to quickly match the pipeline damage condition to one or more repair options. The second volume generically describes the procedures for each of the repair methods and techniques identified in the first volume. Volume II also contains the results of the survey of recent repair operations submitted by PRC/AGA member companies. Volume III begins with an alphabetical directory of equipment suppliers and service companies whose hardware, facilities, and expertise may be required by the field engineer responsible for the repair operation. The potential application of this technology is for the repair of offshore pipelines using divers.
Determination of Clamp Repairable Leaks (PRC/AGA/Stress Engineering) [62] Once a leak in a subsea pipeline has been located, there are several methods available to repair the pipe. These range in cost and difficulty from relaying the line to clamping. Clamping is obviously the quickest and least expensive method. However, no clear guidelines exist as to where clamp repair is applicable. The object of this project is to explore the limits of a dent which may be sealed by a clamp. This is to determine whether or not a particular dent can be sealed by the
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prototype clamp. This work was done with the aid of non-linear finite element analysis of a typical rubber seal using the ABAQUS program. The finite element analysis (FEA) teaches that independent circumferential and longitudinal seals are desirable so that ovalites and dents can be more easily accommodated by circumferential seals. Deep pits may be a problem which should be evaluated with a field simulation. The suggested guidelines for acceptability of clamp repair are as follows: 1.
The pipeline must not be dented to such a degree that pigs can no longer pass.
2.
The pipeline must not have structural damage to the extent that a split clamp will no longer fit around the pipeline.
3.
The ovality of the pipeline where the split clamp is to seal against must be within the limits set by the clamp manufacturer which are generally based on API pipe tolerances.
4.
Most small weld defects away from flanges, valves, etc. are usually clamp repairable.
Deepwater Pipeline Maintenance and Repair Manual (MMS/R. J. Brown) [63] The MMS of the U. S. Department of the Interior has sponsored this development project with the objectives of collecting information, organizing it and providing guidance for maintaining deepwater pipeline systems integrity during their operating life. Effective maintenance and repair of pipelines is an aspect of ensuring that subsea pipelines fulfil their operating purpose. Although this report is written for deepwater, i.e. 1,000 to 6,000 ft it does contain useful information for water depths less than 1,200 ft where divers can perform the pipeline repair work. The purpose of this report is to establish the current state of capability of systems to make repairs on submarine pipelines because of damage, leaks or line breaks. The objectives are: 1) to provide a detailed view of existing, developing and conceptual repair systems in regards to key criteria, line diameter and water depth and 2) to develop guidelines for each of the repair systems, to establish their limits and to assist in the selection of the most effective system for a particular pipeline maintenance or repair situation. The potential application of this technology is for the repair of offshore pipelines using various methods, including divers, ROV’s, manned submersibles, etc.
972 Pipeline Inspection The following operations/maintenance activities, which relate to pipeline inspections, are required by U.S. offshore regulations (DOI), Department of Transportation (DOT), and/or done by the Company.
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49 CFR 192 and 195 - Inspection Requirements for DOT Pipelines For Offshore pipeline inspection requirements for the DOT refer to 49 CFR 192 and 195.
30 CFR 250.155 — Inspection Requirements for DOI Pipelines In U.S. waters pipeline inspection requirements for Department of the Interior (DOI) pipelines are given by 30 CFR 250.155 (April 1988) as follows: (a) Pipeline routes shall be inspected at time intervals and methods prescribed by the Regional Supervisor for indication of pipeline leakage. The results of these inspections shall be retained for at least 2 years and be made available to the Regional Supervisor upon request. (b) When pipelines are protected by rectifiers or anodes for which the initial life expectancy of the cathodic protection system either cannot be calculated or calculations indicate a life expectancy of fewer than 20 years, such pipelines shall be inspected annually by taking measurements of pipe-to-electrolyte potential measurements. Directives from the Regional Supervisor’s letter to lessees dated April 18, 1991 indicate that pipeline routes shall be inspected at least monthly for indication of pipeline leakage. These inspections can be made by using a helicopter, marine vessel or other approved means.
Discussion The Company’s operation/maintenance activities that relate to pipeline inspection in the Gulf of Mexico are typically performed monthly, bi-monthly or in some cases annually. For example, the routes (see item (a) above for DOI pipelines) are flown monthly using either fixed-wing aircraft or helicopters to visually check for leaks. Inspections are conducted bi-monthly or monthly for old pipeline systems that use rectifiers (see item (b) above). There is also an annual check of the pipe-toelectrolyte potential for the corrosion protection system. (The more recent lines use anodes). In addition, Chevron USA GOMBU has monthly pipeline inspections for: (1) valves, including functioning of the actuators and a visual inspection for corrosion; (2) operating pressure; and (3) risers, including a visual inspection for the splash zone. In some areas of the Gulf of Mexico, riser inspection includes ultrasonic and/or radiographic methods. In addition, some pipelines are pigged regularly and others have chemical injection to prevent or minimize corrosion problems; for example, lines having a high CO2 or H2S content in the gas [29]. Unique operations, such as periodic inspections using side scan sonar or visual means using divers or remotely operated vehicles, are not normally required for operations/maintenance. However, for repairs these are used (see Section 971). Periodic inspection of subsea valves is not required.
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The Company has recently conducted a study on “Leak Detection Systems and Small Diameter Inspection Tools - Phases I & II”, also see Section 958 Safety Requirements and Component Selection [32, 33].
973 Abandonment This section discusses pipeline abandonment as required by U.S. offshore regulations or as recommended practice by API. It is important to know that with the DOT jurisdictional pipeline shutdown, inactive, idle, etc (not abandon the pipeline), the Company is still required to maintain the line according to DOT regulations. The Company must continue the corrosion program, ROW inspections, valve inspections, etc.
Federal Regulations In U.S. waters abandonment and out-of-service requirements for Department of the Interior (DOI) pipelines are given by 30 CFR Part 250.156 (April 1988) as follows: (a) 1.
A pipeline may be abandoned in place if, in the opinion of the Regional Supervisor, it does not constitute a hazard to navigation, commercial fishing operations, or unduly interfere with other uses in the OCS. Pipelines to be abandoned in place shall be flushed, filled with seawater, cut, and plugged with the ends buried at least three feet.
2.
Pipelines abandoned by removal shall be pigged, unless the Regional Supervisor determines that such procedure is not practical, and flushed with water prior to removal.
(b) 1.
Pipelines taken out-of-service shall be blind flanged or isolated with a closed block valve at each end.
2.
Pipelines taken out-of-service for a period of more than 1 year shall be flushed and filled with inhibited seawater.
3.
Pipelines taken out-of-service shall be returned to service within 5 years or be abandoned in accordance with the requirements of paragraphs (a)(1) or (2) of this section.
Similar requirements are contained in 49 CFR 192.727 for DOT gas pipelines.
API Recommendations Section 7.6.4 of API RP 17A addresses abandonment for pipelines used in a subsea production system. Abandonment of subsea pipelines is accomplished by either abandonment in-place or complete removal. (This is similar to the 30 CFR 250 requirements given above). Each line abandoned in-place should be flushed of hydrocarbons and filled with seawater or other inert material. The ends of the line should be disconnected and sealed from all hydrocarbon sources and should not extend above the mudline in a snagging position.
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Discussion Pipelines do not normally constitute a hazard to navigation or commercial fishing operations, nor do they unduly interfere with other uses in the OCS. Therefore, these lines normally meet the criteria in (a)(1) above and can be left on or below the mudline, with the ends buried. In unusual cases, however, pipelines to be abandoned may have to be removed from the sea floor. For example, fishing gear-trawl boards may snag on a suspended pipeline span that has been exposed due to a strong current or on a line crossing a shipping fairway, in relatively shallow water, where large ships may anchor.
Procedure The Company does not have a standard procedure for submarine pipeline abandonment. (Very few Company lines have been abandoned to date.) Some pipelines may be abandoned when the platform is abandoned. If the platform is to be removed, then the crane barge may be able to undertake pipeline abandonment work using surface methods. (However, this may require installation of additional davits and winches on the barge.) The pipe/riser can be raised to the surface and the end cut off and a cap (or blind flange, see below) installed. Care should be taken and tension provided such that the pipe does not have a “wet” buckle. Rather than cap the end of the line, it is normally preferable to attach a blind flange with a “bleeder” valve. This permits the pipe to be flushed again, if necessary, and provides for future use of the pipeline should the need arise. When fitting a blind flange/bleed valve assembly, the valve should be at least a 2-inch nominal size. The “Orange Peel” method of capping a pipe (i.e., cutting the end of the pipe into triangles, bending the ends inside to the center to form a cap by welding) is not preferred, because it is not considered to be a reliable method of sealing a pipe. Furthermore, it requires extensive work to bring the pipeline back into service should the need arise. Alternatively, divers can cut the end of a pipeline, after it has been flushed, and insert a plug or install a flange. This method can be done without a lay barge or crane barge but requires a diving spread for the specified water depth. In the remote event that the pipe must be entirely removed from the sea floor, then abandonment can proceed in the reverse of installation using for example, the reverse lay method. For guidance on removing only sections of a line, see the pipeline repair methods described in Section 971 (also see Section 952).
980 Ultra-Deepwater Pipelaying This section is of interest when planning for upcoming deepwater lease sales or assessing previously acquired deepwater leases for possible development. The reader should contact the Offshore Systems Division of CPTC for the latest information when considering an ultra-deepwater pipelaying project.
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Planning for possible production from Shell’s ultra-deepwater Atlantic wells, which were drilled during 1983 and 1984, included studies of how to install, connect, and repair flowline bundles/pipelines to these wells in water depths to 7,500 feet [15]. The reel method, using the reel ship Apache and the J-Lay method, using a converted dynamically positioned (DP) drillship, were identified as the most promising methods of installing pipelines/flowlines in these great depths. Similar studies conducted by Gulf for OCS 59, in water depths to 6,000 feet, reached similar conclusions (see Figure 900-57 and Reference [16]). For Montanazo, Spain, in a water depth of 2,500 feet, the Company considered the use of threaded-connection pipe laid from a drillship in a “J” configuration [17]. Fig. 900-57 Summary of Deepwater Pipelaying Capability of Various Vessels [16] Name of Barge
Pipe O.D
Location
2,000
16
N.A.
3,000
12
N.A.
6,000
8
N.A.
6,000(1)
12
N.A.
1,200
36
N.A.
2,500(2)
24
N.A.
6,000(3)
16
N.A.
1,300
20
Messina Strait
2,300
20
Tunisia to Sicily
4,000(4)
20
N.A.
ARGEPIPE-J
6,500(5)
30
N.A.
Dynamically Positioned Drillship
6,500(5)
20
N.A.
Apache
BAR 347
Castoro SEI
Water Depth (ft)
(1) Would require new ramp. (2) Would require increased tension, new mooring system, and automatic winch control. (3) Would require increased tension, dynamic positioning and automatic winch control. Likely too expensive to operate. (4) Would require modifications to the mooring system. (5) Proposed Systems.
DEEPSTAR I Project - Technical Report - Transportation Options Study December 1992 (Texaco/INTEC) [64] Texaco’s subsea system conceptual design study addresses phased development of deepwater, extended reach subsea oil fields. This includes transportation of produced reservoir fluids over long distances through flowlines from deepwater subsea wells to a shallow water platform. The assumed length of these flowlines is from 25 to 60 miles. The intent would be to maximize the use of existing infrastructure. For the Gulf of Mexico, these flowlines would typically be one or two with a size of 12.75-inch O.D.
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The objective of this study is to evaluate flowline system options and recommend systems suitable for deepwater, extended reach subsea developments. Major technical criteria are addressed for a range of study parameters. Two reservoir types are considered: 1) water drive, i.e. typical of Marathon’s Ewing Bank 873, “Hercules” field and 2) gas cap drive, i.e. like Conoco’s Jolliet field. Multiphase flowlines are the selected, preferred option over single phase oil/gas flowlines. The study shows that pumping would be required in the later stages of development for the “Hercules” type reservoir.
DEEPSTAR I Project - Technical Report - Pipeline Design and Installation December 1992 (Texaco) [65] Texaco’s subsea system conceptual design study addresses phased development of deepwater, extended reach subsea oil fields. The intent would be to maximize the use of existing infrastructure. The objective of this study is to recommend the design, installation, tie-in, commissioning and protection measures for these deepwater lines. The evaluated installation methods are S-lay, reel ship, J-lay, bottom tow and offbottom tow in water depths from 400 to 6,000 ft. Cost estimates are presented for installation of a 40-mile line for 8, 12, 16 and 20-inch nominal pipe diameters. Recommended tie-in methods include: 1) Steel pipe spool-pieces, 2) Flexible pipe bundle jumpers, 3) Lateral deflection tie-ins, 4) horizontal direct pull-in, 5) vertical stab and hinge-over and 6) layaway. Bottom features found on the continental slope are likely to affect pipeline design, installation and routing. The principal concerns are spanning, subsidence and possibly large-scale displacement."
DEEPSTAR II PROJECT - Deepwater Gulf of Mexico - Platform and Pipeline Infrastructure Capacity Mapping Project (Texaco) [66] The report by Texaco includes a large Gulf of Mexico map inside the front cover. This allows one to locate those blocks in which a Profit Center may have an interest in considering the tie-back of a remote oil or gas potential field development in water depths to 6,000 ft at a maximum distance of 60 mi. The platform and pipeline data sheets are separated into MMS designated Areas. The platforms are in numeric order by their tract number. Following the platform data sheets are the MMS pipeline maps for the respective deepwater tracts in the area. A convenient computerized version of the map and data is also being developed by Texaco, but will not be available until late 1994.
Apache Reel Ship The Apache is one of the most likely candidates for laying up to NPS 16 pipelines/flowlines in water depths to 7,500 ft.
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Current Equipment. As currently equipped, the Apache is designed to install up to NPS 16 pipe at 2,000 feet and up to NPS 12 pipe at 3,000 feet. The vessel has installed 6-inch pipe for Petrobras, and 10- and 12-inch pipe for Exxon in 1,000foot water depths. The primary limitations of the Apache for laying deepwater flowlines/pipelines are: (1) the maximum tension limit of 200 kips, which is the capacity of the drive system on the main reel; and (2) the maximum lift-off angle of 60 degrees, which corresponds to the steepest position of the adjustable stern ramp. Also important for deepwater pipe laying are the relatively undersized abandonment and recovery (A and R) winch and the relatively small deck space aft of the main reel for placement of auxiliary reels, if required. Modifications for Laying Ultra-deepwater Pipelines/Flowlines. Various modification options that would enhance the Apache’s deepwater pipelaying capabilities were investigated in the Shell study [15]. The best of these options (Option 1) is described next. The Apache would be equipped with a curved stern ramp capable of releasing the pipe vertically as required for a stab-and-hingeover type connection. This ramp would ride on the existing level-wind structure and would include apparatus for temporarily heave-compensating the pipeline/flowlines, which also would help facilitate the stab-and-hingeover connections. (See Figure 900-58.) Fig. 900-58 Reel Vessel Apache Outfitted as Proposed for Ultra Deepwater Pipelaying
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Per Stena Offshore, the actual design and layout of the proposed system onboard the Apache would entail a comprehensive study, with emphasis on the specific project requirements. The modifications described as Option 1 [15] are more in line with the current onboard equipment configuration. Associated procedures for laying would also be more like those currently used in water depths to 1,000 feet. Fourth quarter 1987 costs for the Option 1 modifications to the Apache are shown in Figure 900-59. (See also Reference [13]) Sensitivity To Water Depth. The primary limit for laying pipelines using the Apache Reel Ship is the tension capability. The proposed modifications shown in Figure 900-58 permit a maximum tension of 550 kips. The estimated fourth quarter 1987 costs for laying lines at 6,000, 7,000, and 8,500 feet in a Gulf of Mexico location [13] are summarized in Figure 900-60. A 16-inch × 1.00-inch wall thickness line could not be laid at an 8,500 foot depth using the Apache as proposed in Figure 900-60. (We have not contacted Stena Offshore to determine whether additional modifications could be done to permit this.) This line could be laid using the converted Sedco 472 DP drillship [13]. See Figure 900-61 and discussion below. Fig. 900-59 Apache Modification Costs for Laying the Example Lines Item
Cost ($MM)
New Purchase Take-off for Reel
1.0
Stern Support Frame for Vertical Laying
2.5
New Abandonment/Recovery Winch
1.5
New Base Yard
1.5 Subtotal
$6.5MM
Mob/Demob - N. Sea to the GOM
2.0
Total
$8.5MM
Fig. 900-60 Fourth Quarter 1987 Line Laying Costs — Reel Vessel Apache Water Dept, ft
6,000
7,000
8,500
O.D., in
12.75
16.0
12.75
16.0
12.75
16.0
Wall Thickness, in.
0.688
0.875
0.75
1.00
0.812
1.0
Length, mi
107
107
103
103
109
N/A
Number of Lines
2
1
2
1
2
N/A
Cost ($MM)
115.2
85.5
117.9
90.4
130.5
N/A
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Fig. 900-61 Fourth Quarter 1987 Line Laying Costs — DP Drillship Costs for Example Lines Using DP Drillship Water Depth, ft
6,000
7,000
8,500
O.D., in
18.00
24.00
18.00
22.00
18.00
24.00
Wall Thickness, in.
1.00
1.25
1.125
1.375
1.125
1.50
Length, mi
140
140
136
136
142
N/A
Number of Lines
2
1
2
1
2
N/A
Cost ($ MM)
247.9
186.5
253.6
176.3
262.8
N/A
Dynamically Positioned (DP) Drillship Dynamically positioned (DP) drillships can be converted to laying pipelines/flowline bundles vertically through a central moonpool [15]. Alternatively, a converted DP semisubmersible could be used. This “J-Lay” technique is clearly the preferred method for laying larger size (greater than NPS 16) individual pipes in ultra-deep water, but is not as convenient as the reel method for laying pipe bundles. The Sedco 472 DP drillship is a typical candidate for conversion to ultra-deepwater vertical pipelaying. Sensitivity to Water Depth. The primary limit for laying pipelines using the Sedco 472 DP drillship is the tension capability. The rig has a hook load limit of 1,300 kips. A 24-inch × 1.50-inch wall thickness line could not be laid at an 8,500-foot depth using the converted (as proposed) Sedco 472. (We have not contacted Sedco to determine whether additional modifications could be done to permit this.) Estimated fourth quarter 1987 costs for laying lines at 6,000, 7,000, and 8,500 feet in a Gulf of Mexico location are summarized in Figure 900-60 [13].
DEEPSTAR II Project - Evaluation of Deepwater J-Pipelay (Texaco/Shell/Alan C. McClure) [67] The primary goal of this work is to provide a less costly means of laying deepwater pipelines, using a “Moonpool”, vertical J-lay technique than is currently available with conventional S-Lay, Type II or III or J-Lay pipelay vessels. The J-Lay equipment may be outfitted to a suitable dynamically-positioned workboat. The study determined methods for the installation of 6.625 to 18-inch diameter pipelines, typically long lines to a maximum 60-mi length between a pipeline laid down on the seafloor and a manifold for adjacent, jumpered subsea wells. Water depths from 1,000 to 6,000 ft are considered. Extension to deeper or shallower water depths and smaller diameter pipe is technically feasible. The Scope of Work included the performance of a pipe handling and ship selection study by Shell/Alan C. McClure Associates to satisfy the following minimum requirements: 1) work boat size and length, dynamically positioned, 2) candidate vessels, 3) procedures, 4) boat modification and fit-up requirements, including estimated costs, 5) pipe handling/laying (welded or threaded joints), 6) speed of laying, 7) monitoring of J-Lay system, 8) Crane requirements for pipe handling, 9) crew
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required, 10) cost for the mob/demob and the equipment/welding/vessel spread during installation, and 11) report documentation, see Volumes I & II. This technology has the potential to reduce offshore pipeline costs in deepwater."
Pipe Joining Techniques for Possible Application to the J-Lay Method. There are many single station pipe joining techniques that could be applied to the JLay method of pipelaying [15]. (Also see Section 964.) These are summarized in Figure 900-47. The “Flash Butt Welding” technique developed by McDermott Construction of New Orleans or the automatic welding technique by CRC of Houston could be used. These methods meet API Standard 1104 and have established welding times that permit a rapid cycle time. Because the Company has not used these methods previously, however, they would require acceptance testing.
990 References 1.
Final Phase Pipeline Design Summary for Point Arguello Oil & Gas Systems. Brown & Root, Inc., Chevron Pipe Line Co., Volumes I, II and III November 1985. (OFT Call No’s: PIPE-11,400; 11,500; and 11,600).
2.
SEAPIPE-PC Program User’s Manual, Applied Offshore Technology, Houston, TX, 12/01/88, OFT Library, San Ramon, CA, Call No: PIPE-15000.
3.
Mouselli, A.H. Offshore Pipeline Design, Analysis and Methods. Penn Well Books, Tulsa, Oklahoma. 1981.
4.
Submarine Pipeline Cost Estimating Guide. CRTC/INTEC, July 1990.
5.
Study of Deepwater Pipeline Riser Installations by J-Tube Pull Method (Phase II Technical Report & User’s Manual). Applied Offshore Technology, (OFT Call No: PIPE-4700). May 1979.
6.
Deepwater Pipelay Study, Phase II - Volume I. Shell Oil Company. (OFT Call No: PIPE-4800). November 1981.
7.
Deepwater Pipelay Study Phase II - Volume II. Shell Oil Company. (OFT Call No: PIPE-4900). October 1981.
8.
Information on Subsea Pipeline Valves. J. P. Kenny & Partners Ltd., CPUK, (OFT Call No: PIPE-10300). September 1987.
9.
Titus, P. E. Effect of Tensioner Stresses on Coating and Jacketing Integrity. Shell Oil Company. (Deep Water Pipeline Study, Section 35-2). 1977.
10. Archer, G. L., et.al. The Behavior of Concrete Over Thin Film Epoxy Coatings. British Gas Corp., (Offshore Technology Conference, paper no. 4453). 1983. 11. Design and Installation of Insulated Submarine Pipelines - Joint Industry Study - Intec No. H-053.1 (Vol. 1 and 2). Intec Engineering Inc., CRTC, (OFT Call No: PIPE-9600). June 1986.
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12. Insulated Pipeline Study - Santa Ynez Unit Development Project - Option A Hondo “B.” Pescado, Exxon, Brown & Root, Inc. January 1985. 13. Deepwater Gulf of Mexico Production System Study. (Prepared for Chevron USA - Eastern Region) OFT Division, CRTC, CUSA. December 1987. 14. Ali, M.A. Self Burial of Offshore Pipelines in Fine Grained Cohesive Sediment. Ph.D. Dissertation, Texas A&M University. May 1977. 15. Deepwater Pipeline, Flowline and Riser Installation - Concepts for Very Deep Water. Shell Development Company, Houston, Texas (OFT Library Abstract No: 864454, Call No: 86-1106). Circa 1984. 16. Production System Concepts and Economic Summary - Mid-Atlantic - OCS Sale 59. Gulf (OFT Library, Abstract No: 863507, Call No: QA002). January 1981. 17. Montanazo Flowline Project - Static Analysis of J-Lay, Aquatic. (Chevron Abstract No: 861146, Call No: 1 Flow-1400). July 1983. 18. Fortnum, R.T. “Hot Subsea Pipeline Coatings Disbonding Tests,” November 24, 1986, CRTC, Materials Division, File 6.55.30. 19. Pipeline Design—PC Program User’s Manual, Version 1.0. APTECH/Chevron, May 1989. 20. J-Tube Pull Installation Field Measurement Program, Garden Banks Block 236, Gulf of Mexico, Prepared for Columbia Gas System Service Corp., by Applied Offshore Technology, July 12, 1989, 38 pp. 21. Experimental Investigation of Pipeline Stability in Very Soft Clay, by O.I. Ghazzaly and S.J. Lim, OTC 2277, May 1975. 22. Safety and the Design of Submarine Pipelines, by Rolf Hestenes, J.P. Kenny. 23. OFFPIPE User’s Guide, Version 1.3, by Robert C. Malahy, Jr., February 1, 1989. 24. Alternate Stability Methods for Marine Pipelines, CRTC/Brown & Root U.S.A., October, 1990. 25. Takula 24-inch Export Pipeline, Corrosion Coatings Recommendation, Petromar, May 19, 1988, OFT Library, Abstract No. 880196 (OTIS), Call No: PIPE-14200. 26. Submarine Pipeline On-Bottom Stability, Volume 1: Analysis and Design Guidelines and Volume 2: Level 1, 2 & 3 – Software and Manuals, American Gas Association (AGA), Arlington, VA, 11/01/88. 27. Pipeline Anchor Study: Prepared for Zaire Gulf Oil Company, Smith, H.D. and Doyle, J.J., 9/1/89, OFT Library, Call No: PIPE-17900.
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28. Development of Vertical Pipe (2G) Girth Welding System for Tendons, Risers, and “J-Lay” Construction: Phase 1, Final Report, Microalloying, Inc, Houston, TX, 1/1/90, OFT Library, Call No: PIPE-18600. 29. Pipeline Pigging: A State-of-the-Art Study — Main Report, H.O. Mohr & Associates, Houston, TX, 8/1/89, OFT Library, Call No: PIPE-19300. 30. Wax/Hydrate Mitigation for Deepwater Flowlines, Intec Engineering, Inc, December 1, 1991, OFT Library, Call No: FLOW 1500." 31. Performance Survey of Flexible Pipe in Static & Dynamic Service, H. O. Mohr & Associates, 6/1/91, OFT Library, Call No: FLOW 1400, San Ramon, CA. 32. Offshore Pipeline Survey on Leak Detection Systems & Small Diameter Inspection Tools: Final Report & Appendix 1, H. O. Mohr & Associates, 12/1/90, OFT Library, Call No: PIPE 22700. 33. Offshore Pipeline Project - Leak Detection Systems & Small Diameter Inspection Tools, Phase II Study - Evaluation & Selection Procedures and Cost Estimates, Final Report and Appendix I, Prepared for Chevron, by H. O. Mohr Research & Engineering, February, 1992, OFT Library. 34. Tow Methods for Installation of Offshore Pipelines, Intec Engineering, Inc., September 1, 1987, OFT Library, Call No: PIPE 23900, San Ramon, CA. 35. Tow Methods Design Guide for the Installation of Offshore Pipelines, R. J. Brown & Associates for the American Gas Association (AGA), January 1, 1989, OFT Library, Call No: PIPE 23600, San Ramon , CA. 36. J-Tube Pipeline Riser Design Manual - J-Tube Pull Analysis - Program APJTUB-PC, Applied Offshore Technology, November 1, 1991, OFT Library, Call No: PIPE 25400, San Ramon, CA. 37. Platform Riser Inspection and Repair Methods; Volume 1: Study, Volume 2: Literature Search, Volume 3A: Vendor Data and Volume 3B: Vendor Data; Brown & Root, December 1, 1991, OFT Library, Call No: PIPE 26400, San Ramon, CA. 38. Risers and Tie-Ins Conceptual Design Study, Green Canyon Block 205, Phase 2C- Final Report; Appendices A, B, C and E; Appendix D, Volume 1 & 2; R. J. Brown & Associates, February 1, 1992, OFT Library, Call No: GC 820, San Ramon, CA. 39. COPI/CABGOC, Cabinda Areas B&C Project Specification Section 6.0 Pipeline Design and Construction Requirements, June 10, 1991 and Pipeline Specifications, CBC: Line Pipe 20.01; Pipeline Installation and Testing 20.02, February 15, 1991; Aluminum Alloy Anodes for Pipelines 20.03, Fusion Bonded Epoxy for External Pipeline Coating 20.04-COM-4042-A, Concrete Coating of Line Pipe 20.05-PPL- 4807 and Induction Bending 20.07-PPL4737. 40. State-of-the-Art Study of Subsea Hot Tapping Systems, H. O. Mohr Research & Engineering, Inc, “Draft”, June 1992.
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41. Green Canyon Block 205 Deepwater Pipeline Study, Intec Engineering, Inc, May 1, 1990, OFT Library, Call No: GC 410, San Ramon, CA. 42. Deepwater Pipeline Repair Methods - A JIP to Develop a Recommended Repair Method for Application in 1,000 to 4,000 WD, Summary Report and Volumes 1 & 2, Shell Development Company, January 1, 1990, OFT Library, Call No: PIPE 19100, San Ramon, CA." 43. Deepwater Pipeline Repair Methods - Phase 2, Summary Report, Shell Development Co., January 1, 1991, OFT Library, Call No: PIPE 25950, San Ramon, CA. 44. Investigation of March 19, 1989 Fire on South Pass Block 60 Platform B (Lease OCS-G 1608), Dept.of the Interior, MMS, April 1, 1990, OFT Library, Call No: PIPE 22000, San Ramon, CA. 45. MMS Investigation of Amoco Pipeline Company High Island Pipeline System Leak (Galveston Block A-2) in the Gulf of Mexico, Offshore Texas, Dept. of the Interior, MMS, June 1, 1990, OFT Library, Call No: PIPE 22,100, San Ramon, CA. 46. Development of Pipeline Stability Design Guidelines for Liquefaction and Scour - American Gas Association (AGA) Report. 47. Guidelines for Subsea Pipeline Repair and Tie-In Systems - Volumes 1 & 2 American Gas Association (AGA) - J P Kenny & Partners Ltd., March 1, 1987. 48. Subsea Isolation and Surface ESD Systems Study, J P Kenny, 1992. 49. Precision Gas Pipeline Location - A Technology Study, (PR-215-9130), Prepared for the Offshore and Onshore Design Applications Supervisory Committee of the Pipeline Research Committee at the American Gas Association, SRI International, SRI Project 3062, Final Report, January 1994, AGA, Catalog No: L51702. 50. The Technology of Submersible Remotely Operated Vehicles (PRC/AGA/Busby Associates, Inc), February 1991. 51. Submarine Pipeline On-bottom Stability (PR-178-9333), Volumes I and II, (computer program diskette), PRC/AGA/Brown & Root, September 1993, AGA Catalog No: L51698A. 52. Pipe Lift Analysis - PC Program (SEALIFT-PC), Chevron/Applied Offshore Technology, November 1993. 53. Pipe Span Analyses - PC Program (SEASPAN-PC), Chevron/Applied Offshore Technology, July 6, 1994. 54. Underwater Branch Connection Study, Final Report (PR-205-017) Prepared for Offshore Supervisory Committee of the Pipeline Research Committee at the American Gas Association, June 1992, Job No. 2567.01, R.J. Brown and Associates of America, Inc., Houston, TX, AGA Catalog No: L51670.
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55. Deepstar II Project, Introduction to Flexible Pipe (Report DSII CTR 422-1), Coflexip, 1994. 56. Submarine Pipeline Installation Using Coiled steel Tubing, Intec Engineering, April 1994. 57. Low Cost Flowline Installation Method: J-Lay Inclined Mast (JLIM) Concept Report, Chevron/Starmark Offshore, April 5, 1994. 58. Marsh/Swamp Pipeline Construction Manual, Chevron/Brown & Root Energy Services, December 1993. 59. State-of-the-Art Study of Subsea Hot Tapping Systems: Final Report, CPTC/H. O. Mohr & Associates, November 1992, OFT Library, PIPE 28300. 60. Subsea Repair of Gas Pipelines Without Water Flooding, Prepared for the Offshore Supervisory Committee of the Pipeline Research Committee at the American Gas Association, J. P. Kenny, Job No: 050028.01, August 1993, AGA Catalog No: L51687. 61. Diver Assisted Repair Manual, H. O. Mohr, June 1993, PR-209-9122 (three volumes in two binders), AGA Catalog No: L51679. 62. Determination of Clamp Repairable Leaks (PR-201-9114), Prepared for the Offshore and Onshore Design Applications Supervisory Committee of the Pipeline Research Committee at the American Gas Association, Stress Engineering Services, Inc, January, 1993, AGA, Catalog No: L51701. 63. Deepwater Pipeline Maintenance and Repair Manual, Minerals Management Service, MMS/R. J. Brown & Associates, June 1992. 64. DEEPSTAR I Project - Technical Report - Transportation Options Study, Texaco/Intech Engineering, Inc, December 22, 1992. 65. DEEPSTAR I Project - Technical Report - Pipeline Design and Installation, Texaco/Intec Engineering, Inc, December 22, 1992. 66. DEEPSTAR II PROJECT - Deepwater Gulf of Mexico - Platform and Pipeline Infrastructure Capacity Mapping Project, Texaco, December 29, 1993. 67. DEEPSTAR II Project - Evaluation of Deepwater J-Pipelay, Texaco/Shell Development Company, Masrch, 1994.
991 Jurisdiction of Outer Continental Shelf (OCS) Facilities The following memorandum, “Memorandum of Understanding Between the Department of Transportation and the Department of the Interior, Regarding Offshore Pipelines,” details the division of responsibility between the Department of Transportation (DOT) and the Department of the Interior (DOI) for petroleum production facilities on the outer continental shelf.
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Figure 900-62 shows the jurisdiction graphically. The memorandum is reproduced here in the format of the Code of Federal Regulations. MEMORANDUM OF UNDERSTANDING BETWEEN THE DEPARTMENT OF TRANSPORTATION AND THE DEPARTMENT OF THE INTERIOR REGARDING OFFSHORE PIPELINES I. Introduction The Department of Transportation (DOT) has the responsibility for promulgating and enforcing safety regulations for the transportation of gases and hazardous liquids by pipeline. The DOT regulatory responsibilities include all offshore pipelines both on State lands beneath navigable waters as that area is defined in the Submerged Lands Act (43 U.S.C. 1301 et seq.) and on the Outer Continental Shelf (OCS) as that area is defined in the Outer Continental Shelf Lands Act (OCS Act) (43 U.S.C. 1331 et seq.). The DOT administers the following laws as they relate to pipelines: (1) the Natural Gas Pipeline Safety Act of 1968, as amended (49 U.S.C. 1671 et seq.); (2) the Transportation of Explosives Act (18 U.S.C. 831-835); (3) section 28 of the Mineral Leasing Act, as amended (30 U.S.C. 185); (4) the Hazardous Materials Transportation Act (49 U.S.C. 1801 et seq.); and (5) the Deepwater Port Act of 1974 (33 U.S.C. 1501 et seq.). The Department of the Interior (DOI) has certain responsibilities under the OCS Act including issuing of rights-of-way and rights-of-use and easements for the construction of pipelines on the OCS and enforcing regulations necessary for the prevention of waste and conservation of natural resources of the OCS. In recognition of each of the parties’ respective regulatory responsibilities, the DOT and DOI agree that a memorandum of understanding is needed to avoid duplication of regulatory efforts regarding offshore pipelines and to maximize the exchange of relevant information. II. Responsibilities of the Parties For the foregoing reasons, the DOT and the DOI agree to the following division of offshore pipelines regulatory responsibilities:
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DOT Responsibilities 1. The DOT will establish and enforce design, construction, operation, and maintenance regulations for those pipelines extending to the shore from the outlet flange at— (i) each facility where hydrocarbons are produced, or (ii) each facility where produced hydrocarbons are first separated, dehydrated, or otherwise processed, whichever facility is farther downstream, including subsequent on-line transmission equipment but not including any subsequent production equipment. The diagram attached as an addendum illustrates the pipeline facilities regulated by DOT that are described in this paragraph. 2. The DOT will send copies of all contemplated Notices of Proposed Rule Making (NPRMs) concerning off- shore pipelines to the DOI, before they are published in the Federal Register, for review by the DOI. However, publication of NPRMs by the DOT is not contingent upon the receipt of comments from the DOI. DOI Responsibilities 1. The DOI will establish and enforce design, construction, operation, and maintenance regulations for offshore pipelines extending upstream from the outlet flange described in paragraph 1 of the “DOT Responsibilities” set forth in this Memorandum of Understanding into each production well on the OCS. 2. The DOI will send copies of all contemplated NPRMs and OCS Orders concerning offshore pipelines to the DOT before they are published in the Federal Register for review by the DOT. However, publication of NPRMs and OCS Orders in the Federal Register is not contingent upon the receipt of comments from the DOT. 3. The DOI, in issuing rights-of-way, rights-of-use, and easements on the OCS for offshore pipelines which are subject to DOT’s offshore pipeline regulations, will condition those rights and easements on the pipelines being designed, constructed, operated, and maintained in compliance with the applicable DOT regulations. 4. The DOI which receives, reviews, and as appropriate, approves operators’ plans for development of the OCS, including plans for construction of pipelines on the OCS, will provide copies of those plans to the DOT. 5. The DOI which receives and processes applications and prepares environmental assessments for rights-of-way, rights-of-use, and easements for pipelines to be constructed on the OCS, will provide copies of those applica-tions and assessments to the DOT. 6. The DOI which performs pipeline management studies as necessary in newly developing areas on the OCS where pipeline systems do not exist or are poorly developed, will provide copies of those studies to the DOT.
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Joint Responsibilities 1. The DOT and DOI will coordinate all of their respective research and development projects concerning off-shore pipelines. 2. The DOI will perform inspection and enforcement activities necessary to enforce its regulations and OCS Orders relating to pipelines on the OCS. With respect to other offshore pipelines originating on the OCS and sub-ject to DOT regulations, the DOT and DOI will coordinate and perform inspection activities. In the latter case, the DOT will perform enforcement activities and the DOI will provide the DOT with reports of DOI inspections for such further enforcement actions as may be appropriate. 3. At least once each calendar year, DOT and DOI will jointly review all existing standards, regulations, orders, and operating practices concerning pipelines on the OCS.
Chevron Corporation
FOR THE DEPARTMENT
FOR THE DEPARTMENT OF THE
OF TRANSPORTATION:
INTERIOR:
William T. Coleman
Thomas S. Kleppe
Secretary of Transportation
Secretary of the Interior
May 6, 1976
May 6, 1976
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Fig. 900-62 DOT/DOI Outer Continental Shelf Jurisdictions
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1000 Guidelines for Low Pressure Buried Fiberglass Pipe Abstract This section discusses low pressure buried fiberglass pipe for oilfield flow lines, gathering systems, etc. It is intended to provide the reader with the fundamentals required for design and installation. This section does not cover selection of high pressure fiberglass linepipe or installation of above ground fiberglass piping, although the remaining information does apply. Contents
Page
1010 Introduction
1000-3
1011 Background 1020 Selection Guidelines
1000-4
1021 Selecting a Resin System 1022 Molding Methods 1023 Other Additives 1024 Resin-Rich Liners 1025 API Spec 15LR 1026 Connections 1027 Thread Sealant 1030 Purchasing Guidelines
1000-9
1040 Design Guidelines
1000-9
1041 Fiberglass Properties 1042 Water Hammer 1043 Thrust Blocks 1044 Miscellaneous Design Details
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1060 Installation Guidelines
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1061 Hydrotesting 1062 Excavation and Backfilling 1070 Summary Guidelines
1000-21
1071 Selection 1072 Purchasing 1073 Design 1074 Handling 1075 Installation 1080 References
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1010 Introduction This section discusses low pressure buried fiberglass pipe for oilfield flowlines, gathering systems, etc. A low pressure line is defined as one with components covered by API Specification 15LR, Specification for Low Pressure Fiberglass Line Pipe, (last issued Sept. 1990) which covers pipe, fittings, and connections up to 1,000 psi cyclic and up to 16 inches in diameter. This range encompasses the majority of oilfield applications for low pressure fiberglass pipe. These guidelines also apply to the installation of high pressure fiberglass line pipe, pressures above 1,000 psi. Selection of high pressure fiberglass line pipe was omitted because no manufacturer has submitted test data qualifying their products under API 15HR, Specification for High Pressure Fiberglass Line Pipe, (last issued Sept. 1988). Use extra care when comparing high pressure fiberglass products. Fiberglass pipe pressure ratings from different vendors cannot be considered equal unless they are built to the API specifications. As of July 1992 a CSQIP (Chevron’s Supplier Quality Improvement Process) Commodity Action Team had completed its review of the major U.S. manufacturers of fiberglass line pipe and had negotiated an alliance with Smith Fiberglass. The five year renewable contract covers both low and high pressure pipe. Two preferred distributors for Smith products were also selected, Red Man and Jimsco. Purchasing pipe under the alliance contract will ensure not only a competitive price, but a lower total cost of ownership.
1011 Background Chevron’s domestic use of fiberglass line pipe in the oil patch is close to one million linear feet annually. Ninety-five percent of the pipe is in the 2 to 4 inch diameter range. Most of the applications are water handling, although a significant amount is dedicated to well flowlines. Fiberglass pipe is chemically resistant to all common oilfield production environments, including produced hydrocarbons, brine, and associated CO2, and H2S. This makes fiberglass an economically competitive pipe material, since it does not require additional corrosion mitigation measures. The product should provide a long trouble free service life as long as excessive temperature or strain is not imposed on the line. Other advantages of fiberglass include a high strength to weight ratio and light weight. The disadvantages of fiberglass include brittleness, temperature limitations, flammability, UV degradation, and susceptibility to damage from external forces. Chevron experience with fiberglass pipe tends to be extreme, either the installation has been a complete success and the system provides years of trouble free service or there were problems at installation and the system immediately failed. Fortunately, our successes with the product far outweigh the failures. Most of the problems associated with fiberglass pipe can be traced to improper design and installation or quality assurance factors. Some examples include:
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improper make-up of end connections, damage caused by excavation, defective material, poor piping design and layout, or operation beyond the design limits. It is the purpose of this guideline to provide enough information to properly select, purchase, design, handle, and install buried fiberglass pipe.
1020 Selection Guidelines These guidelines specifically address the use of fiberglass pipe in common oil field environments, i.e., produced hydrocarbons, produced brine, fresh or salt water, associated gases including CO2 (not super critical CO2) and H2S, or any combination of these. They do not apply to pipe intended for more specialized environments such as concentrated acid, liquid (supercritical) CO2, or plant piping which require a more case-by-case review. For guidance on use of fiberglass pipe in these environments, consult with the pipe manufacturers and/or with CRTC Materials and Equipment Engineering.
1021 Selecting a Resin System There are three resins commonly used for most industrial applications of fiberglass: 1.
epoxy
2.
polyester
3.
vinyl ester
Each has specific characteristics which make it suitable for specific applications. Most pipe used in the oilfield has an epoxy resin, which has a good combination of properties which make it suitable for this service. Epoxy resins start out as liquids. They are turned solid by adding a curing agent. There are three commonly used classes of curing agents which give rise to the three common classes of epoxy fiberglass pipe. These are: 1.
aromatic amine cured
2.
aliphatic amine cured
3.
anhydride cured
There are a number of different specific chemicals used in each of the three classes, and each can result in different properties of the final fiberglass pipe product. While there can always be exceptions, the following will, in general, hold true: •
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Aromatic amine cured epoxies have the best overall chemical and temperature resistance and should provide the best overall performance in oilfield environments. Aliphatic amine cured epoxies are a close second, and in common oilfield environments should perform about the same as the aromatic amine cured epoxies.
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•
Anhydride cured epoxies have been used successfully in a number of low temperature oilfield applications. This resin system is attractive because of lower cost, but it does have limitations. Anhydride cured epoxies degrade in water above 150°F and have less solvent resistance than amine and aliphatic cured epoxies.
Some vinyl ester pipe has also been used in the oilfield. Vinyl ester actually has better chemical resistance in a wider variety of environments than epoxy, especially in acid environments. For typical oilfield flow line environments this extra chemical resistance does not justify the higher cost. Epoxy resin pipe should be suitable for common oilfield services.
1022 Molding Methods Once the epoxy and the curing agent have been blended, the only major component remaining to be added is the reinforcing glass fibers. The resin and glass are brought together in the forming stage in one of two ways, filament winding or centrifugal casting. Both are equally suitable for low pressure oilfield applications. The most widely used method is filament winding. In this process continuous strands of glass fibers are wetted with the epoxy/curing agent mix and wound onto a spinning mandrel. Filament wound pipe has a smooth I.D. surface, because it is formed against the smooth metal mandrel. The second method is called centrifugal casting. This is where the glass fibers and the epoxy/curing agent mix are all loaded together into a hollow cylindrical barrel and then spun. The result is that centrifugally cast pipe has a smooth O.D. surface. Centrifugally cast pipe is not common in the oilfield.
1023 Other Additives In addition to the resin, curing agent, and glass fibers, fiberglass pipe may contain fillers, UV stabilizers, pigments, dyes, and/or accelerators. Normally these have no ill effects on the performance of the pipe. Fiberglass pipe that will be stored for long periods in the sunlight or installed above ground should be UV stabilized to protect it against degradation from exposure to ultra violet light. Alternatively, the pipe could be painted.
1024 Resin-Rich Liners Filament wound pipe deteriorates by cracking perpendicular to the continuous filament wound fibers. These transverse cracks develop with stress, time, and degradation. Surface and micro cracks develop on the ID, allowing ingress of process fluids which accelerates the process. When cracking is sufficiently developed, the pipe fails. A resin rich corrosion liner of adequate thickness on the ID will tend to remain intact even with damage or cracking within the filament winding. A resin rich lining can be important where transient surges, excess bending stresses, or severe environments (such as concentrated acids) occur. Experience to date shows
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that a resin-rich liner is not needed in common oilfield environments. There is no need to require a manufacturer to add a resin-rich liner to his pipe if it is not standard.
1025 API Spec 15LR Before the fifth edition of API Spec 15LR was issued in October 1986, there was no uniformity in the way manufacturers designed, rated, and tested their fiberglass pipe. Experience with some brands showed that it would not stand up to long term service at the manufacturer’s advertised pressure rating. Users commonly de-rated new fiberglass pipe 50% to 75%. Pressure derating is not necessary for fiberglass pipe that is monogrammed under API Spec 15LR. This spec requires manufacturers to test their pipe using long-term cyclic pressure tests for at least 10,000 hrs. Tests are run at a minimum of 150°F. In order to obtain a higher temperature rating the manufacturer must run the test accordingly. The test procedure, ASTM D 2992 Procedure A, results in a design pressure rating that is conservative enough to account for long term effects of stress, pressure, environment, and temperature. It is important to only purchase API monogrammed fiberglass pipe that meets Spec 15LR. This is the only way that you can be sure that you are getting a product that meets your service requirements. In addition to establishing the pressure rating of the pipe, Spec 15LR also covers fittings and end connections. Other parameters covered under Spec 15LR include quality control tests, inspection requirements, and dimensions. Figure 1000-1 lists the pipe that has been tested by Smith Fiberglass Products and qualified per API 15LR to wear the approval monogram. Any selection in Figure 1000-1 that satisfies the size, pressure, and temperature requirements and has the needed connections and fittings should be satisfactory for production fluids in most situations. In some cases, fittings may have a lower pressure rating than the matching pipe, so check with the manufacturer.
1026 Connections There are two categories of end connections used with low pressure, small diameter fiberglass pipe, adhesive bonded and mechanical joints. See Figure 1000-2 for a list of available connections. Connections that have been tested to API 15LR, unless otherwise specified. Not all connections are available for every size and product line. Adhesive bonded joints include tapered bell and spigot (the most common), threaded tapered bell and spigot, and bell and socket (i.e. no taper). These end connections are prone to problems caused by not following proper procedures. Examples include:
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dirt on the bonding surfaces
2.
not enough adhesive
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Fig. 1000-1 API 15LR Rated Pipe from Smith Fiberglass Products (SFP) (Cyclic Pressure Rating at Maximum Temperature) Red Thread II — Aromatic Amine Cured Epoxy Pipe Temperature
2"
3"
4"
6"
150oF
300
300
300
300
200oF
300
300
300
300
8"
10"
12"
14"
16"
150
150
150
150
150
Blue Streak — Vinyl Ester Pipe (Catalog Series 300-6", 400-4", 500-2.5" & 3", and 600-2". 300 psi cyclic rating available) Temperature
2"
2.5"
3"
4"
6"
8"
10"
150oF
277
247
231
167
112
115
115
Blue Streak — Anhydride Cured Epoxy Pipe (Catalog Series 310-6", 410-4", 510-2.5" & 3", and 610-2". 300 psi cyclic rating available) Temperature
2"
2.5"
3"
4"
6"
8"
10"
150oF
256
229
214
155
104
107
106
Threaded Blue Streak (TBS) —Anhydride Cured Epoxy Pipe (Catalog Series 1010) Temperature
2"
2.5"
3"
4"
6"
150oF
330
330
330
330
330
Threaded Blue Streak (TBS) —Anhydride Cured Epoxy Pipe (Catalog Series 1310) Temperature
2"
2.5"
3"
4"
6"
150oF
412
412
412
412
412
Threaded Blue Streak (TBS) —Anhydride Cured Epoxy Pipe (Catalog Series 1510) Temperature
2"
2.5"
3"
4"
6"
150oF
500
500
500
500
500
Threaded Blue Streak (TBS) —Anhydride Cured Epoxy Pipe (Catalog Series 2010) Temperature
2"
2.5"
3"
4"
6"
150oF
660
660
660
660
660
Note
Pressures listed are psig-cyclic. To obtain steady state pressure ratings multiply by 1.5
3.
moving the joint before the adhesive is fully cured
4.
improper curing temperature
Using an experienced, or specially trained installation crew is critical. Adhesive joints that combine mechanical locking (e.g., threading) with adhesive bonding are the most reliable of the adhesive connections. Mechanical connections are somewhat less susceptible to installation mistakes. These connections come in a wide variety of proprietary styles, often using large threads with or without O-rings, or other mechanical locking devices. Mechanical connections cost more than adhesive bonded connections, but they are also faster to install.
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Fig. 1000-2 Pipe Connections Mechanical Connections: API:
American Petroleum Institute 8rd/in Thread
NPT:
National Pipe Thread (fittings only)
Flange:
Bolted Flange Sets
Grove End:
Clam Type Clamp
(Not Tested to API 15LR)
Fast Thread:(1)
Coarse 2rd/in Thread
(Not Tested to API 15LR)
Kwik Key:(1)
Mechanical Push w/O-ring Seal & Key
(Not Tested to API 15LR)
Adhesive Connections: B X B:
Bell End X Bell End
B X S:
Bell End X Spigot End
TAB:(1)
Threaded and Bonded
(1) Smith Custom Connections
There are no industry standards for connections, so different manufacturers’ products are not interchangeable. Selection become more confusing because each manufacturer typically offers more than one different design. API Spec 15LR requires testing of all connections which the manufacturer plans to offer with an API monogram. The selection guide that follows will indicate which connections to choose from when ordering pipe to Spec 15LR. For each separate installation, all pipe and fittings need to come from a single manufacturer. Flanges are used for joining fiberglass pipe to dissimilar materials (as well as providing an additional method for joining fiberglass pipe to itself). Filament wound or hand laid up flanges are generally preferred over compression molded flanges at pressures above 200 psi, but any fabrication method is acceptable provided there is adequate shop QC testing. Lap joint (Van Stone) flanges, which consist of fiberglass stub ends with steel back-up rings, are sometimes used for dissimilar pipe joints, however they usually have lower pressure ratings than fullfaced fiberglass flanges.
1027 Thread Sealant Mechanical connections require a thread compound, usually Teflon based with or without Teflon tape. Each manufacturer supplies their own thread compound. It is important to use the compound supplied by the pipe manufacturer or any warranty may be voided. Smith is marketing a new two-part elastomeric thread compound for mechanical connections call Hi Pro. This product replaces the more common Teflon thread compounds. Hi Pro sets to form a soft flexible elastomer that provides for more reliable sealing, yet allows the pipe to be unscrewed and reconnected. Hi Pro should
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not be used on pipe that has been in service with thread dope or Teflon tape, but is highly recommended for new installations.
1030 Purchasing Guidelines Use API 15LR as the Purchase Specification for All Low Pressure Fiberglass Pipe and Fittings Whenever Possible.
1040 Design Guidelines If needed, detailed guidance on piping and pipeline design is available from the major suppliers. A detailed design guideline for buried fiberglass pipe is also available in the American Water Works Association Standard for Fiberglass Pressure Pipe, ANSI/AWWA C950-89. For most buried lines in the oilfield, detailed designs are not needed. The general guidelines given below point out factors that should be considered. Specific problem areas that have been encountered in the past are highlighted.
1041 Fiberglass Properties Fiberglass has a high thermal expansion coefficient, meaning it will elongate or shrink more than steel as a result of a given temperature change. It also has a low modulus of elasticity (it takes less stress to stretch it than for steel). Fiberglass will also develop less compressive stress when subject to thermal expansion while fixed at both ends. Figure 1000-3 presents some comparative properties of 1020 carbon steel and filament wound epoxy fiberglass. Fig. 1000-3 Comparative Properties of 1020 Carbon Steel and FRP Property
Units
Carbon Steel
FRP
Density
lb/ft3
491
115
Specific Gravity
g/cm3
7.9
1.85
in/inoF x 10-6
6.5
9-12
Modulus of Elasticity at 75oF in Tension
psi x 106
30
2
Axial Tensile Strength
psi x 103
66
12-15
Thermal Conductivity
BTU-in/(hr-ft2-oF)
336
1.7-2.9
Flow Factor
Hazen-Williams Coefficient
110
150
Coefficient of Thermal Expansion
Unlike steel, fiberglass does not yield when it is over stressed. It cracks. Fiberglass cannot deform to redistribute stress concentrations. So while it may develop less thermal expansion stress than steel for a given temperature change, fiberglass is less tolerant of that stress.
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In addition to causing purely mechanical damage, high stresses and strains can lead to chemical attack of the fiberglass, because it opens the interface between the resin and the glass and exposes it to the chemical environment. For both of these reasons, it is important to design the piping system in order to minimize stress concentrations. This includes preventing water hammer, utilizing thrust blocks, providing proper support, and anchoring as discussed below. For pipe purchased under the alliance agreement Smith Fiberglass Products will assist in pipe selection and system design considerations if required.
1042 Water Hammer Water hammer (fluid hammer) is a transient pressure caused by the sudden change of fluid velocity in a line, as by a quick closing valve or abrupt pump startup or shutdown. The resultant shock load is proportional to the mass and velocity of the fluid. The longer the line and the higher the fluid velocity, the greater the shock load will be. As mentioned earlier, fiberglass cannot deform to absorb these shock loads, so the result is often burst pipe and broken fittings. The best way to prevent damage to fiberglass pipe from water hammer is to minimize it. Use of surge tanks, accumulators, slow operating valves, and/or feedback loops around pumps will minimize water hammer. Any design methods which reduce the magnitude or rate of changes in flow velocity will help. In addition, pumps should not be started into empty discharge lines unless slow-opening, mechanically operated valves are used to gradually increase flow to the system. In a situation where fluid hammer is known or expected to be a problem and can’t be avoided, the fiberglass pipe can be built to withstand it. It is merely a matter of upgrading the pipe pressure rating to withstand the maximum shock load or pressure surge. The maximum pressure surge occurs when the change of fluid velocity is experienced within one wave cycle. It is calculated in psig by multiplying the change in fluid velocity in ft/sec times the fluid hammer constant listed in Figure 1000-4. The instantaneous maximum peak pressure for the system will equal the sum of the water hammer surge pressure plus the maximum operating pressure of the system. Instantaneous maximum peak pressure is the design pressure of the system to be used for selecting pipe and components.
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Fig. 1000-4 Fluid Hammer Constants
Note
Pipe Size (in.)
Fluid Hammer Constants-(1)
1
25
1.5
22
2
24
3
20
4
16
6
16
8
16
10
15
12
15
14
15
16
15
Applies only to Smith Fiberglass Products Inc. Red Thread II, Green Thread and Poly Thread pipe.
(1) Constants are valid for specific gravity of 1.0
The constants in Figure 1000-4 were calculated using the Talbot formula as follows: a aW∆V P = ----------------- = --- g 144g
S.G. ---------- ∆V 2.3 (Eq. 1000-1)
where: 12 a = --------------------------------------W 1 d 0.5 ----- ---- + -----g K Ee (Eq. 1000-2)
= Wave Velocity (ft/sec) P = Pressure surge deviation above normal (psig) ∆V = Change in Flow Velocity (ft/sec) W = Density of Fluid (water = 62.4 lb/ft3) S.G. = Specific Gravity of Fluid (water = 1.0) K = Bulk Modulus of Compressibility of Liquid (water = 300,000 psi) E = Modulus of Elasticity in Tension for Pipe Wall (about 3,000,000 psi)
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d = Inside Diameter of Pipe (inches) e = Pipe Wall Thickness (inches) g = Acceleration Due to Gravity (32.2 ft/sec 2)
1043 Thrust Blocks Thrust blocks are concrete encasement blocks that spread the thrust load over a large area of soil as well as anchor the pipe. Literature sources list several simple guidelines for their use to minimize pipe movement and bending stresses, (i.e. for six inches diameter / 1000 psig pipe and up). Thrust blocks are generally not needed for gravity flow pipe; they should be used when operating pressures/flow rates dictate. They are typically used at changes in direction, vertical or horizontal, (elbows, braces, tees, etc.), at reducers, and at dead ends. They can be simple, truncated triangle shaped blocks as illustrated in Figure 1000-5. Fig. 1000-5 Typical Encasement Type Thrust Blocks
Thrust blocks should be installed and cured for 48 hours prior to pressure testing. Thrust blocks must have adequate bearing surface area against undisturbed soil to resist the thrust caused by hydrostatic pressure and thermal expansion. The
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resultant thrust (force) vector should pass perpendicularly through the center of the bearing surface. The center of the thrust block should coincide with the horizontal centerline of the pipe. The minimum bearing surface area is calculated using the formula: R A t = -----Sp (Eq. 1000-3)
where: At = Minimum bearing surface area of thrust block in square feet R = Reaction force in pounds Sp = Allowable soil pressure bearing capacity in pounds per square foot. Guidance is available from the manufacturers for calculating the reaction force due to hydrostatic pressure and thermal expansion, and for estimating the allowable bearing pressures for various types of soil. Unfortunately, complete design of thrust blocks for any given installation is complex. It depends on the run length, fitting type, system pressure, system temperature differentials (i.e., between pipe laying temperature and pipe operating temperature), soil properties (modulus, density, friction), pipe properties and dimensions, and pipe stresses. Differential movement between the thrust block and the pipe can cause shear or bending failures in the pipe. This is especially true under freeze/thaw conditions or any other situation where significant ground movement occurs. A number of fiberglass pipe failures have been associated with thrust blocks. Thrust block design is not an exact science. Failures at thrust blocks have occurred even when they were designed by a design engineering firm specializing in fiberglass designs. Because of the complexity of proper thrust block design, it is not possible to give simple guidelines that can be universally applied. Each situation needs careful evaluation in collaboration with the manufacturer and/or design contractor. In areas with firm, compacted soil, no major ground freezing, little or no ground movement, and where operating pressure swings are moderate, thrust block design should be fairly routine. Areas with soft, shifting soil, severe freeze/thaw conditions, or where operating pressure swings will be significant, are more difficult to handle and will require more detailed engineering. However, there are a couple of techniques which can be used to mitigate the pipe damage caused by differential movement between the pipe and the thrust block. The first is to wrap a 1/2 inch thick, six inch wide band of soft neoprene rubber (4070 durometer hardness) around the pipe prior to placement of any concrete. The band should be placed so that it is flush with or slightly protruding from the point where the pipe enters and exits the thrust block. A band should be placed at each point of pipe entry into and exit from the thrust block.
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The second technique, which can be considered for use in more difficult situations (e.g., severe freeze/thaw conditions) is to use metal elbows, tees, etc., and short sections of metal pipe, at the thrust block. A proper metallurgy or coating should be selected to resist corrosion. Metal can absorb the shear and bending stresses better than fiberglass. Flanged connections would be used to connect the metal pipe to the fiberglass pipe. (Because fiberglass fittings are expensive, using a high alloy fittings might be a cost competitive alternative.) Thrust blocks should be poured after hydrotesting the pipe, to allow for visual inspection of all fitting joints during the test. They should be shaped with the design bearing area against virgin earth of the trench wall. Smaller blocks using a dry concrete mix may be shaped by hand, but larger blocks (2 square feet or greater bearing area) will require forms. The concrete should be worked thoroughly around the fitting for maximum surface contact. The entire area between the fitting and the freshly cut trench should be filled with concrete and free of voids.
1044 Miscellaneous Design Details Try to minimize the number of fittings and flanges called for in the layout because they are can amount to a significant portion of the total installed cost. The bend radii should not exceed the manufacturer’s recommendations. At Cased Crossings (e.g., Road Crossings, River Crossings) the Pipe Must be Supported Where it Enters and Exits the Encasement. Use Pipe Guides Within the Encasement to Limit Pipe Buckling from Thermal Expansion. Guides made of thermoplastic material are readily available. They should be installed around the outside of the pipe and fit the annulus between the pipe and the encasement or conduit. Guide spacing should be equal to the pipe manufacturer’s recommended support spacing for that size and grade of pipe in an above ground installation.
1050 Handling Guidelines The most important fact to remember is that fiberglass pipe is brittle and therefore more prone to mechanical damage. It needs to be handled more carefully than steel in order to avoid damage. Below are some specifics:
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When transporting or storing, nylon webbing, straps, or padded chains should be used for tie-downs. Do not over tighten tie-downs.
2.
When transporting, the pipe should be fully supported along its entire length. Do not use pole trailers or trailers which are too short (causing the pipe to overhang).
3.
When loading or unloading, each length or bundle should be handled individually or use a fork lift. Do not drop or roll the pipe off the truck.
4.
Use wide slings or straps for lifting (e.g., Woven cloth or nylon). Do not use chains or cable for lifting. Do not use hooks inside the pipe to lift bundles or joints.
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5.
Leave the end protectors in place until preparing to make up the connection.
6.
When laying out the pipe, the pin-end should point in the intended direction of flow.
7.
Immediately upon arrival at its destination the pipe should be inspected to ensure no damage occurred in shipment. Reject or discard damaged pipe.
Fiberglass pipe should be stored off the ground on four supports equally spaced along the length of the pipe and aligned perpendicular to the pipe. Supports should be a minimum of 4 inches wide. Each row of pipe should be separated by additional supports aligned vertically. This also applies to storage immediately prior to assembly and burial. However, when pipe must be stored directly on the ground prior to assembly, use a smooth, flat area free of rocks and other debris. Do not roll the pipe along the ground. Store fiberglass pipe out of direct sunlight to avoid UV damage when long term (6 week) periods are expected, cover if necessary. The bonding surfaces or threaded connections are most susceptible to UV damage.
1060 Installation Guidelines Follow the manufacturer’s instructions and guidelines. This above all else will keep you out of trouble most of the time. It applies to all aspects of the job including transportation, design and layout, joint make-up, and prevention of damage. Have the manufacturer’s rep on-site during installation. A pipe manufacturer’s rep should be on site, at least initially, to be certain the installers know what they are doing and to help the job go smoothly. Smith Fiberglass Products or their distributor will provide this service at a reasonable or no cost. It is always a good idea to maintain quality control checks throughout the installation process, including soil condition, backfill, compaction, etc. Inspect pipes inner and outer surfaces before installation. Do not use damaged pipe. Use an experienced crew or one that has been trained by a factory representative to ensure sound adhesive joints. As mentioned earlier, adhesive joints require skill and care to be done properly, and are the greatest source of leaks, problems, and headaches. Using mechanical joints is much more likely to keep you out of trouble. Where adhesive joints are used, the following procedure should be followed:
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Follow manufacturer’s instructions carefully.
2.
Avoid making field tapers as much as possible. Careful layout of pipe will help minimize the need for field tapers. If field tapers are required, follow manufacturer’s instructions and use manufacturer’s special tapering tools. Do not use hand grinders.
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3.
Prior to bonding, visually inspect all spigots and bells (or sockets) for damage.
4.
Bell and spigot surfaces must be clean and dry. Clean all dirt, moisture, and other foreign matter from both surfaces. (Moisture is likely to be present during early morning hours.)
5.
Spigot or bell bonding surfaces that are chalked from ultra violet exposure should be sanded first to remove the UV damaged material.
6.
A second person should be mixing the adhesive while the pipe is being cleaned. Adhesive must be thoroughly mixed. Mix all of the adhesive with all of the curing agent (hardener) in the kit. Never split a kit, because it is difficult to correctly proportion resin and hardener. Preferred mixing temperature is 70°F to 80°F. (Curing times are highly dependent on temperature.) Adhesives typically cure in less than 6 hours at 70°F. Use a wooden spatula for mixing. Be sure the adhesive shelf life has not been exceeded. Use only pipe manufacturer’s approved adhesives, which should match the pipe resin. Note: For major projects with experienced crews, resin can be purchased by the drum and hardener by the gallon.
7.
Threads can be molded onto the pipe in the field at transitions, etc. The manufacturer’s representative should be the only one allowed to do this, however.
8.
Do not touch bonding surfaces after cleaning, and do not allow dirt to fall onto bonding surfaces after cleaning.
9.
Immediately after cleaning, apply a smooth, thin coat of adhesive to both the bell and spigot bonding surfaces. Use a clean paint brush for application.
10. Do not apply adhesive if it has turned warm in the can. This indicates the resin is about to set. 11. Remove all paint brush bristles from applied adhesive with a sharp, clean tool. 12. Mark the spigot, or find factory-installed marks, to indicate appropriate insertion depth. 13. Push and twist the spigot into the bell to the appropriate insertion depth. Hammering with a rubber mallet on a wooden block placed across the bell on the opposite end of the pipe, or a come-along, may be used for joining larger pipe sizes. A good insertion has good alignment and should produce a small, even bead of adhesive both internally at the end of the spigot and externally at the bell end. 14. Allow joints to cure fully before moving or testing. Do not disturb unset joints when bonding the next joint. Electrical heat collars or chemically activated “Heat packs” can be used to accelerate cure times. This speeds up installation, but they must be used with care and in strict accordance with the manufacturer’s instructions. Mechanical joints are simple to install and are relatively foolproof. Mechanical joints come in a variety of proprietary manufacturer’s designs. Select one that has been tested and approved per API Spec 15LR. (See Figure 1000-1.)
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Follow the manufacturer’s instructions for mechanical joint assembly. Threaded connections should be cleaned and doped with a thread dope recommended by the pipe manufacturer. (Thread doping only applies to threaded connections which seal in the threads. For some proprietary mechanical connections, such as those where sealing is done by an o-ring, a lubricant may be used, but thread dope is not used. In these connections, thread dope could interfere with the seal.) Multiple lines in the same ditch should be separated by one pipe diameter or six inches, whichever is greater. The need for using only an experienced, qualified contractor cannot be over-emphasized, especially when using adhesively bonded connections. It is critical that the job foreman be experienced. Pre-qualify the installers (e.g. to ANSI B31.3 sections 327.1 and 327.2) before the job begins by having them make up a few joints of each size of pipe to be installed. (This is similar to the pre-qualification required of welders.) ANSI B31.3 requires the installer to make up a test assembly in accordance with a written Bonding Procedure Specification, and which contains at least one pipe-to-pipe joint and one pipeto-fitting joint. After the assembly cures, it is hydrotested to 4 times the assembly design pressure. It must hold pressure for at least 1 hour without any joint leaks or separation. The test is designed so that the hydrostatic pressure loads the joints in both the longitudinal and circumferential directions.
1061 Hydrotesting Hydrotest pressure should be based on the lowest rated component or section in the system, (e.g., a flange rating, side branch rating, etc.) which will also determines the design pressure rating of the system. Hydrotest pressure should be 125% of system design pressure rating (i.e., 125% of the lowest rated element in the system). Excessive pressure during hydrotest may damage the fiberglass pipe and components. The damage may not show up immediately but result in reduced service life. Do not hydrotest adhesive connections before the adhesive has set. Hydrotest the system in segments as small as practical and as soon as practical, so that leaks can be easily located and problems identified early and corrected. Before hydrotesting, backfill the trench to six inches above the pipe to anchor the pipe and keep it from moving when the pressure is applied. Leave the connections uncovered to detect leaks. (On 1000 psi pipe, cover the body between connections to the surface with a single pile of dirt.) See the following section on backfilling. Pressure test with water, not air or gas. (Pressure testing with air or gas is extremely dangerous.) The water should enter the line at a low point, with a means provided for bleeding the air at the highest point. All air must be removed from the line before pressuring, because entrapped air will be compressed and will give erroneous results. On straight runs of pipe, a soft pig can be used ahead of the water to displace the air while filling the line. The pressure will not remain constant over time if variations in ambient temperature occur. Caution: over pressurization can occur on hot days as the cooler water temperature rises.
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Once the system is filled with water and purged of air, it should be slowly brought up to test pressure being careful to avoid over-pressurization. Use slow closing valves and properly controlled booster pumps to prevent water hammer or overpressurization. When the desired hydrotest pressure has been reached and maintained, it should be held for a minimum of three hours. Prevent a vacuum from forming inside the pipe. High vacuums created inadvertently in sloped runs of fiberglass pipe can cause the pipe to collapse, especially when combined with overburden pressure or external pressure at river crossings. Deflected pipe is even more prone to vacuum collapse. A vacuum can be easily created by closing a valve at the top end of a sloped section of fiberglass pipe, so caution should be exercised.
1062 Excavation and Backfilling The bedding and backfill material, along with the trench walls, form the support system for buried fiberglass pipe. They protect it from loads acting on the pipe (e.g., backfill and vehicular traffic). Downward loads tend to oval the pipe. Properly compacted bedding will minimize pipe movement and ovalling. Proper bedding is also needed to provide uniform support of the pipe with no point contacts or unsupported sections which could lead to pipe damage or failure. For these reasons, proper trench construction and use of proper bedding and backfill material is important. (Cost considerations may out weight the benefits of special bedding material in some locations). Soil conditions vary widely, from soft, loose, or wet soils, to hard and rocky soils. While the guidelines given below will be generally useful for many applications, The pipe manufacturer should be consulted for detailed guidance on pipe burial requirements for a specific situation. Minimum depth of the trench should be pipe diameter plus 2 feet. Detailed calculation of burial depth, as described in AWWA C-950, depends on many factors, including soil properties, pipe properties, operating conditions, and expected loads. Detailed guidance for specific applications is available from manufacturers. Generally, however, minimum burial depth for off-highway vehicle loading will be pipe diameter plus 2 feet. The 2 feet allows for six inch of bedding below the pipe, six inch of bedding above the pipe, and 12 inches of fill on top. (Four inches of bedding (top, bottom, and sides) may be used for pipes of six inch diameter or less.) The width of the trench, for pipe up to 12 inches diameter, should be pipe diameter plus 12 inches. For 14 inch – 16 inch diameter pipe, trench width should be pipe diameter plus 16 inches. The trench should have vertical sides. If the soil is granular or loose, it will typically be necessary to shore the trench walls or increase the trench width. Always slope trench to OSHA guidelines.
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1000 Guidelines for Low Pressure Buried Fiberglass Pipe
Use a ditching machine for the excavation rather than a backhoe, if possible. Use a sand pad on the bottom of the ditch when digging with a backhoe, then rake level. Eight inch diameter and larger pipe may require that bell holes be dug at the connections to facilitate installation . Smaller diameters can be made up on the right-ofway and then lowered into the ditch. Avoid sharp bends or changes in elevation, and don’t make horizontal or vertical bends sharper than recommended by the manufacturer. Use fittings, i.e., elbows, where sharper bends are needed, and excavate the ditch accordingly. Keep water out of the trench, to allow for dry compaction of the bedding. In high water table areas, a de-watering system will be needed. After rain or water ingress, the trench will need to be pumped dry. The bottom of the trench must be prepared to provide smooth, uniform, continuous support of the pipe. Unevenness, high spots, rocks, or other sharp or abrasive material in the bottom of the trench will cause uneven bearing or point contact on the pipe and lead to damage from wear or shear of the pipe. Six inches of bedding should be placed beneath the pipe. A minimum six inch of bedding beneath the pipe is especially critical in rocky or shale areas. The bottom bedding should be tamped, with the resultant bedding six inch thick after tamping. Bedding material should be clean dirt, free from large objects or sharp rocks. Alternatives include sand, pea gravel with a maximum particle size of 3/4 inch, or crushed rock with a maximum particle size of 5/8 inch. Pea gravel or crushed rock in the 1/8 inch to 3/4 inch size is an ideal bedding and backfill material because it compacts to 90% density without compaction equipment, thus saving labor and equipment cost. There should be no sharp rocks, heavy boulders, large clods of dirt, organic matter, or frozen lumps in the bedding or backfill. Generally, organic or high plasticity soils are not suitable. For guidance on use of materials other than sand, pea gravel or crushed rock, consult the pipe manufacturer. Do not leave any voids beneath the pipe or in the haunch area. As illustrated in Figure 1000-6, ensure the pipe is firmly supported by bedding material around the bottom half of the pipe (haunch area). Add bedding/backfill material in six inch layers, and then compact it to the required density (80-95%). Do not use water flooding for compaction. Backfill to six inch above the pipe before hydrotesting, to hold the pipe in place during the hydrotest, but leave the fittings and joints exposed to check for leaks. Complete the backfilling as soon as possible after successful hydrotesting, to prevent damage to exposed pipe, floating from unexpected flooding, or shifting due to cave-ins. Add an additional 12 inches of cover over the pipe (or whatever it takes to fill the trench) in six inch layers. Any material can be used for the fill, because the bedding
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protects the pipe. Mound fill over ditch in lieu of compacting. The typical configuration of a buried pipe is summarized in Figure 1000-7. Fig. 1000-6 Proper Bedding Support in Launch Area Around Bottom Half of Pipe
Fig. 1000-7 Typical Configuration of Buried Pipe
Fiberglass pipe should be run through a conduit at road crossings. Pipe guides should be installed along the length of the conduit to limit buckling from thermal expansion. Guides made of thermoplastic material are readily available. They should be installed around the outside of the pipe and fit the annulus between the pipe and the conduit. Guide spacing should be equal to the pipe manufacturer’s recommended support spacing when that size and grade of pipe is used above ground. Properly compacted bedding is essential at each end of the conduit to provide the necessary support for the pipe, in order to prevent shear and wear damage. When making road bores, the depressions (bell holes) necessary at each end of the bore should be filled and compacted before backfilling to prevent the fiberglass pipe from sagging into these areas on backfilling.
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1000 Guidelines for Low Pressure Buried Fiberglass Pipe
Multiple runs of fiberglass pipe laid through a single road bore or conduit can cause leakage problems from the pipes rubbing against each other due to thermal expansion and contraction. Multiple lines should be separated from each other using centralizing devices. Use metallic backed tracer tape or communication cable to facilitate location of buried fiberglass lines. The tracer tape or cable should be run in the ditch on top of the buried fiberglass line to allow location with a metal detector. Provide at least six inch of separation between the marker tape and the top of the pipe. The separation will allow the maker tape to be spotted before contacting the fiberglass. Use visual marker posts at every turn. Ideally, marker posts should be within line of sight of one another. The marker posts should provide a warning that a fiberglass line is present and identify its contents. This is especially important if the line contains any H2S. For lines handling H2S, other warning or protective devices should also be considered, such as warning signs or full length encasement (in steel or concrete) of the fiberglass pipe. Factors such as H2S content and proximity to personnel will influence the measures needed.
1070 Summary Guidelines 1071 Selection •
Use epoxy resin fiberglass pipe. (Vinyl ester is also OK, but possibly more expensive.)
•
Aromatic amine cured epoxy has the highest temperature limit, about 200°F. Anhydride cured epoxy is adequate to 150°F.
•
A resin-rich liner is not needed.
•
Low pressure fiberglass pipe should be purchased to API spec 15LR.
•
Mechanical end connections are more expensive, but allow for faster installation and improve reliability with less experienced crews.
•
Select pipe from Figure 1000-1 and connections and fittings from Figure 1000-2.
1072 Purchasing Use API 15LR as the purchase specification for all low pressure fiberglass pipe and fittings.
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1073 Design •
Consider water hammer when selecting fiberglass pipe pressure rating.
•
Use thrust blocks at changes in direction to minimize pipe movement and bending stresses, where required. Not recommended in all cases.
•
Minimize the number of fittings to reduce cost.
1074 Handling •
When transporting or storing, woven cloth, straps, or padded chains should be used for tie-downs. Do not over tighten tie-downs.
•
When transporting, the pipe should be fully supported along its entire length. Don’t use pole trailers or trailers which are too short (causing the pipe to overhang).
•
When loading or unloading, each length or bundle should be handled individually. Don’t drop or roll the pipe off the truck.
•
Use wide slings or straps for lifting (e.g., Woven cloth or nylon). Don’t use chains or cable for lifting. Don’t use hooks inside the pipe to lift bundles or joints.
•
Leave the end protectors in place until preparing to make up the connection.
•
The pin-end should point in the intended direction of flow.
•
Store pipe on a rack with ample supports.
•
Store pipe out of direct sunlight for long exposures to avoid UV damage.
1075 Installation • • • • • • • • • • • •
May 1993
Follow the manufacturer’s instructions and guidelines. Have a manufacturer representative on-site during installation. Do not use damaged pipe. Use an experienced crew. Separate multiple lines by at least six inches. Hydrotest with water, not air or gas. Minimum depth of the trench should be the pipe diameter plus two feet. Avoid sharp bends. Do not leave voids during backfilling. Use a conductor pipe at road crossings. Always use a tracer tape to facilitate future location. Use visual marker posts at every turn.
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1080 References Specification for Low Pressure Fiberglass Pipe, API Specification 15LR, Sixth Edition, September 1, 1990 American Water Works Association Standard for Fiberglass Pressure Pipe, ANSI/AWWA C950-89 Oilfield FRP Technology, Chevron Materials Engineering report, File 70.50, J. R. Slining and E. H. Niccolls, January 31, 1989 Fibercast Piping Design Manual, Fibercast, Sand Springs, Oklahoma, May 1989 Recommended Practice for Care and Use Reinforced Thermosetting Resin Line Pipe (RTRP), API Recommended Practice 15L4, Second Edition, March 1976 Note When API RP 15TL4 1st Edition June 1991 is approved, it will combine and supersede both API 15A4 and 15L4. Fiberglass Pipe Handbook, The Composites Institute of the Society of the Plastics Industry (SPI), Inc., New York, NY, 1989 Smith Fiberglass Engineering and Design Guide, Smith Fiberglass Products Inc., Little Rock, Arkansas, February 1, 1992 Smith Fiberglass General Installation Instructions for Threaded Fiberglass Piping Systems, Smith Fiberglass Products Inc., Little Rock, Arkansas, April 1, 1991 Corrosion-Resistant Plastic Composites in Chemical Plant Design, John H. Mallinson, Published by Marcel Dekker, Inc., New York, 1988 Fiberglass Line Pipe Requires Special Care, C. L. Oney, in Petroleum Engineer International, November 1987, p.34 Chevron Corporation Piping Manual, Section 400, Non-metallic Piping FRP Line Pipe for Oil and Gas Production, A. S. Chiu and R. J. Franco, Paper No. 232 presented at NACE Corrosion 89, New Orleans, LA, April 1989 The Effect or 25 Years of Oil Field Flow Line Service on Epoxy Fiberglass Pipe, K. J. Oswald, Paper No. 167 presented at NACE Corrosion 88, St. Louis, MO, March 1988 Design and Performance Properties of Oilfield Fiberglass Tubulars, G. G. Huntoon and J. D. Alkire, SPE Paper No. 19728, 64th Annual SPE Conference, San Antonio, TX, October 1989 A New Look at the Use of Glass-Fiber Reinforced Plastic Piping, C. Robbe, in Materials Performance, June 1990, p.29 What Will Protect Plastic Piping from Water Hammer Damage? Power Magazine, January 1989.p.71 Minutes from the CSQIP Fiberglass Line Pipe CAT Meetings, June 1991 - January 1992.
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Smith Fiberglass, Fiberglass Reinforced Piping Systems for Petroleum Production Applications, Smith Fiberglass Product Inc., Little Rock, Arkansas, January 1992.
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Appendix A. Conversion Tables
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Appendix A
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A-2
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Appendix A
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Appendix A
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Appendix A
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Temperature Conversion Table
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Appendix B. Directional Drilling
Abstract This specification is included here as an example only. It was used by Chevron U.S.A. Inc. Eastern Division Construction Engineering to install an 8-inch pipeline by directional drilling beneath the Mississippi River. This example may provide you with the basis for producing a specification for a similar project. Beware: it is not necessarily complete or applicable to any other project without modification. Modifications that should be considered are: •
Verification of the governing codes
•
Verification of the governing jurisdictions (DOT, state, county, Corps of Engineers)
•
Restatement of the project particulars to precisely fit the individual case
•
Changes to clauses that may have been limited due to the permit or regulatory conditions imposed on the original specification
Note
The titles of some standards have been corrected.
Contents
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Page
I
Scope of Specifications
B-2
II
General Conditions
B-4
III
Regulations and Codes
B-5
IV
Payment
B-6
V
Insurance
B-6
VI
Safety
B-6
VII
Alterations, Modifications, Deletions and Extra Work
B-7
VIII
Subcontractors
B-8
IX
Materials
B-8
XI
Installation
B-9
XII
Welding Specifications
B-10
XIII
Non-Destructive Testing
B-11
XIV
Coating Specifications
B-11
XV
Pressure Testing Specifications
B-11
XVI
Protection of Existing Pipelines and Facilities
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Appendix B
Pipeline Manual
Part I.
Scope of Specifications
This set of specifications shall be included as a part of the contract entered into between Chevron U.S.A. Inc., hereinafter referred to as Company, and the successful bidder, hereinafter referred to as Contractor. Any exceptions to the contract or these specifications must be accepted by Company in writing and shall be listed as an addendum of Exhibit A; the Bid Form submitted by the Contractor. A. General These specifications cover work required for fabricating, installing, and testing 8inch pipeline to cross underneath Southwest Pass of the Mississippi River. 1.
8-inch Pipeline Installation a.
The following 8 inch pipeline shall be installed: 1.
b.
1 8-inch Sch. 80 API 5L Grade B Seamless
Coordinates 1.
Pipeline Entrance; West Bank X = 2,640,507.69 Y = 141,092.14
2.
Pipeline Exit; East Bank X = 2,644,149.83 Y = 140,932.75
2.
Lines and Grades a.
The horizontal distance between the entrance and exit points has been determined to be 3681 feet.
b.
The Contractor shall submit a bid for installation of the pipeline with top of pipe elevation of -90$ Mean Low Gulf in the appropriate sections of Exhibit A, Contractor’s Bid Form.
c.
The entrance and exit pipeline angles shown on the drawings are to be considered as minimum angles. The Contractor may steepen these angles, but the angles should be noted in his proposal.
d.
Tolerances - A twenty-five (25) feet shortage tolerance shall be allowed at the drill bit exit on the east bank of the river. No excess in length will be accepted. A twenty-five (25) feet tolerance will be allowed on the pipeline in a direction parallel to the canal bank.
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B. Location of Work This work will be performed in the vicinity of Mile 8.7 below the head of passes in Southwest Pass of the Mississippi River. The site is approximately seventeen miles south of Venice, Louisiana and is accessible by boat or helicopter only. The site is in Plaquemines Parish with state and local taxes applying to all work. An area aerial view is included in the bid proposal. The topography is typical of south Louisiana marshland locations. We propose to have the Contractor set-up the drilling rig on the west bank of the river near Chevron’s W-2 Tank Battery. We further propose to have the Contractor fabricate the pipeline on the east bank of the river with the pipeline stretched out on pipe rollers and mats in the march area northeast on the pipeline exit point. C. Work To Be Done By Contractor Except as is specifically provided herein to be furnished or performed by Company, Contractor shall perform all work required for installation of the pipeline. Performance of the work includes furnishing all labor, equipment, supervision, surveying, quartering facilities, catering facilities, material (except coated pipe), transportation (except crewboat), and supplies to start, prosecute, and complete the installation of the herein described pipeline. Contractor shall furnish as-built of the 8-inch pipeline crossing prior to final payment. Installation of the pipeline shall include but not be limited to materials handling; qualifying welding procedures and welders; preparing pipe for welding; welding and repairing defective welds; radiography; furnishing materials for and installing field joiners and repairing defective joints on pipeline; laying the pipeline on rollers and mats; designing, fabricating, and installing the pipeline pulling head; drilling the pilot hole; furnishing all surveying back the pipeline; conducting a scraper test on the pipeline after installation; and performing a hydrostatic test once the pipeline is in place under the river. Contractor shall furnish all field joint coating material to consist of shrink sleeves. The Contractor shall further provide the following services related to site preparation:
Chevron Corporation
1.
Purchase spoil material and build drilling fluid containment pits on the east and west banks of the River (permitted size of the pits are 60' by 60' with an elevation of approximately 4' above the surrounding ground elevation).
2.
Contractor’s drilling rig shall be barge mounted.
3.
Set up the drilling rig at the site.
4.
Quartering facilities shall be provided by the Contractor with the facilities to be barge mounted and set up near the W-2 Tank Battery in the access canal. Contractor shall furnish quarters and mess for two (2) Company representa-
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tives. The facilities shall be equipped with operable sewage treatment equipment. Installation and Schedule Sequence Contractor shall furnish Company a detailed installation schedule and sequence of installation before commencing work on this project. Contractor shall furnish Company with a written daily report stating footage of pipe installed and miscellaneous installations completed. Upon completion of the project, the Contractor shall level the pit walls. D. Work To Be Performed By Company 1.
A 47' crewboat for daily access to the facility will be provided by the Company. This crew-boat will return to Venice daily to pick up any required supplies. The crewboat will remain in the field during shift changes to transport personnel from the quartering facility to the east bank work location; an estimated thirty minute trip one way.
2.
Materials Pipe and Shop Coating Company will furnish all line pipe with shop-applied Scotchkote 206 coating, loaded on Contractor’s barges or trucks at Bayou Pipe Coating’s yard in New Iberia. It will be the responsibility of the Con- tractor upon receipt of materials furnished by Company, to tally all joints of pipe to the nearest one- hundredth of a foot. Particular care shall be taken by Contractor in distinguishing the tallied pipe as to size, grade, wall thickness, and type and thickness of coating if applicable. Contractor shall forward pipe tallies to Company’s engineer. a.
Joint Length: All pipe furnished will be in double random lengths.
b.
Pipe Damaged in Loading: Contractor shall refuse to accept any pipe or pipe coating damaged prior to or in loading on Contractor’s barge or truck. Any pipe or coating damaged after receipt of pipe by Contractor shall be repaired or replaced by Contractor at his expense.
3.
Company will perform tie-ins to the completed pipeline.
4.
Company shall furnish permits and right of ways for pipeline installations.
5.
Company shall provide a welding inspector of the project duration.
6.
Contractor shall return all excess pipe to Bayou Pipe Coating in New Iberia after the completion of the project.
Part II. General Conditions
November 1988
1.
Contractor shall provide a competent pipeline construction superintendent to directly supervise all phases of project at all time work is being performed.
2.
Contractor shall complete work on this project by the end of March, 1988. Once having commenced work on this project Contractor shall prosecute same
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to completion with all due effort and diligence in a good and workmanlike manner. 3.
Contractor shall assume all lost time due to inclement weather, high seas and/or strong currents.
4.
Company reserves the right to make minor changes in construction details without invalidating this agreement as long as the general scope of the project is maintained. If such changes or additions involve additional cost to Contractor payment shall be made in accordance with Sections IV and VII of this specification.
5.
Intent of Drawings and Specifications All work that may be called for in the written material and not shown on the drawings, or shown on the draw-ings and not called for in the written material shall be performed and furnished by the contractor as if described in both ways; and should any work or material be required which is not detailed in the written agreement or drawings, either directly or indirectly but which is nevertheless necessary for the proper carrying out of the intent thereof, the Contractor is to understand the same to be implied and required, and shall perform all such work and furnish any such material as fully as if they were particularly delineated or described.
6.
If the Contractor’s proposal is accepted, the Contractor will be required to execute Company’s standard contract, affixed hereto as Exhibit “F”.
Part III.
Chevron Corporation
Regulations and Codes
1.
It is the responsibility of Contractor to be in conformance with all applicable laws, ordinances, codes, regulations and orders of all governmental agencies whether federal, state or local during the life of this project.
2.
In the event Contractor is in noncompliance with a known law, ordinance, code, order or regulation Company will require property or leases until such time as Contractor is in conformance. In such case, Contractor is responsible for all costs incurred including but not limited to demobilization and remobilization of personnel and equipment.
3.
All industry accepted codes and federal regulations pertaining to pipeline installations that are referenced in this specification are hereby incorporated as if they were a part of the specification. Listed below are codes and regulations which may apply to this project. The latest edition that is published is the one that governs. a.
API STD 1104 Standard for Welding Pipeline and Related Facilities
b.
ANSI/ASME B31.4 Liquid Petroleum Transportation Piping Systems
c.
ANSI/ASME B31.8 Gas Transmission and Distribution Piping Systems
d.
49 CFR 192 Transportation of Natural and Other Gas by Pipeline
e.
49 CFR 195 Transportation of Liquids by Pipeline
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f. Part IV.
OCS Order 9 Oil and Gas Pipelines (Note: This order has been replaced by 30 CFR 250.) Payment
1.
Upon completion of the work described in Section I and acceptance of finished product by Company’s Project Engineer, including delivery of any required documentation, Company will pay Contractor the amount therefore.
2.
Partial payment (not to exceed actual percentage of work performed) will be authorized by Company for jobs extending beyond one month, provided extensions are not caused by procrastination, idleness, etc. on part of Contractor. A maximum of 85% payment will be allowed until absolute completion. Invoices for partial payments and payments for extra work and/or materials will be made at a minimum of monthly intervals.
Part V.
Insurance
1.
For all operations performed by Contractor hereunder, Contractor shall carry insurance such that the coverages and limits shall be acceptable to Company.
2.
All such insurance shall be obtained by Contractor from insurance companies which are acceptable to Company, and Contractor shall furnish to Company written evidence satisfactory to Company showing that such insurance is in effect and will not be cancelled for any cause whatsoever without 30 days written notice to Company.
3.
All such insurance shall be properly endorsed to afford full protection for all operations and services offshore to be performed hereunder by Contractor. Additional information concerning insurance requirements may be obtained by contacting Ms. J.T. Kyle at 925 Gravier Street, New Orleans, Louisiana 70112 (telephone: 504-592-6262).
Part VI.
Safety
The intent of these safety regulations is to outline procedures and should supplement, not replace, the Contractor’s safety program. The Company reserves the right of dismissal of Contractor’s personnel or termination of contract if a good safety program is not followed, or for deviation from the following:
November 1988
1.
All personnel shall wear OSHA approved safety hats and shoes.
2.
Smoking will be permitted in designated areas only.
3.
Possession or use of alcoholic beverages or illegal drugs is prohibited.
4.
Proper eye protection shall be worn when performing work which involves a recognized hazard to the eyes.
5.
Coast Guard approved work vest or life jacket, furnished by Contractor to his personnel shall be worn during all over-water transfers and when working near or over water where there are no handrails.
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6.
Horseplay, wrestling or practical jokes are prohibited.
7.
Crane shall be operated only by capable and qualified personnel.
8.
All power tools shall be grounded and in good condition.
9.
Before welding work is authorized and started on any structure or well jacket, there shall be thorough communication between Company representative and Con- tractor’s personnel. The nature of work to be done and all possible hazards shall be discussed in detail so all concerned will be aware of what is going on. The same care shall be taken each day so that any situation change can be evaluated.
10. All persons shall become familiar with the functions and locations of all the structure’s emergency shut-ins and fire stations. 11. No cutting, welding, or sandblasting shall be performed on structures or well jackets unless authorized in writing by Company Area Production Supervisor. This authorization will be secured by the Company Supervisor in charge. 12. Never use flame to detect a gas leak. Use soapy water. 13. There shall be a Company-furnished fire watch established on the structure before the work is started. The fire watchman’s only duty will be that of fire watch. The fire watch orders will be to know how to operate the fire extinguisher properly and have an extinguisher on the site near the work to be done. 14. All welding machines utilized on any structure or well jacket shall be equipped with spark arresting muffler. Part VII.
Chevron Corporation
Alterations, Modifications, Deletions and Extra Work
1.
Work not covered elsewhere in these specifications or attachments resulting from requests by Company and for which a mutually agreed upon price cannot be determined shall be performed under this section.
2.
Company shall have the right at any time or times before or during the actual performance of work hereunder to require additions, alterations, or deletions in contract work hereunder to require additions, alterations, or deletions in contract work by notifying the Contractor thereof in writing. If such additions, alterations or deletions materially increase the amount of work to be performed, Contractor shall not be bound to undertake same until a mutually agreeable price shall have been arrived at between Contractor and Company, or the Company Project Engineer has authorized such work to be performed on a time and materials basis. If such alterations or deletions materially decrease the amount of work to be performed, Company will be credited with an amount mutually agreeable to Company and Contractor.
3.
Payments for extra work requested by Company will be made according to hours actually worked as approved by an authorized representative of Company. Hourly rates approved prior to commencement of work shall govern amount to be paid for such work. No claims for extras will be allowed unless
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Pipeline Manual
agreed upon in advance by Company’s authorized representative requesting such services on that same day that those services occur. 4.
Extra items performed on an hourly basis will be covered by job ticket issued by Contractor and approved by Company representative requesting such services on that same day that those services occur.
5.
Job tickets must contain a complete description of work, type of equipment used and the hours and signature of personnel whose time is charged against the job.
Part VIII. 1.
Subcontractors
This agreement shall not be assigned, sublet or transferred in whole or in part by Contractor, except with prior written consent of Company. If any subcontractors are utilized, Contractor shall be fully responsible to Company for the work performed as though Contractor had performed said work himself.
Part IX.
Materials
1.
Contractor shall furnish any and all material not specifically stated as Company furnished.
2.
All materials furnished by Contractor shall be new, unused, undamaged and of domestic manufacture.
3.
Fittings, flanges, studs, bolts, nuts and pipe shall conform to the following specifications unless otherwise stated herein: Materials
Specifications
Welded fittings and flanges
WPB 234, ASTM A105 Grade B
Studs and Bolts
ASTM A193 Grade B7, Cadmium Plated
Nuts
ASTM A194 Grade 2H, Cadmium Plated
Pipe
API 5L, ASTM A53 or ASTM A106 Grade B
Ring Gaskets
November 1988
4.
Contractor shall furnish to Company documented proof of compliance with an acceptable specification for all items to be permanently installed in this project. This must include but is not limited to mill certificates for manufactured steel items.
5.
Substitution of equivalent materials, parts or equipment must be approved by Company. Should Contractor substitute and Company approve materials, parts or equipment of greater size, strength or working pressure than is required, payment shall be made as if the specified item was used.
6.
Company may substitute materials, parts and/or equipment at its discretion to expedite construction.
7.
It shall be Contractor’s responsibility to inspect all Company furnished material and to sign delivery tickets attesting to the undamaged condition and proper quantity of same. Contractor shall refuse to accept any Company
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furnished material damaged prior to receipt by Contractor. Any material or equipment furnished by Company found damaged after receipt of contractor shall be repaired or replaced by Contractor at his expense. Copies of all delivery tickets shall be given by Company. 8.
After completion of project, Contractor shall transport excess Company furnished pipe to Bayou Pipe Coating’s yard in New Iberia and unload. All excess pipe shall be tallied and a copy submitted to Company. Contractor shall also furnish Company a tally of pipe installed.
Part X. Equipment 1.
Contractor shall furnish all tugs, lay barges, material barges and any other equipment necessary for the timely completion of project.
2.
All tugs and lay barges must be equipped with operational two-way radios.
3.
Crewboats furnished by Company will standby on jobsite and be available to work on a 24-hour basis. Crewboats are to make a minimum of one scheduled run from Venice Base to jobsite each 24 hours.
4.
Company representatives shall have access to crewboats continent upon such use not interfering with progress of the project.
Part XI.
Chevron Corporation
Installation
1.
Contractor shall furnish all labor, transportation, equipment and superintendence necessary to complete the project including quarters and mess for all personnel. Contractor shall be responsible for all materials at the jobsite. Company shall not be responsible for any material lost or left on the job.
2.
Pipeline shall be routed as per attached drawing(s).
3.
The method of installation chosen by the Contractor shall be such that during construction deviation of the pipeline from the alignment shall be kept to a minimum at all times.
4.
Each length of pipe shall be examined to ascertain that it is free from dirt or objects which may cause obstruction. If the pipe is obstructed in any way or it has an excessive amount of dirt, rust and/or scale then it shall be cleaned out before being installed in the pipeline.
5.
When unattended, the pipeline shall be effectively closed or plugged.
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Part XII.
Welding Specifications
Company has one pre-qualified welding procedure which utilizes E6010 electrodes for the stringer bead/ hot pass and E7018 electrodes for filler metal/capping. It is preferred that Contractor use this procedure, however, Contractor may submit other procedures for Company approval contingent upon the procedure being proven through destructive tests at an independent testing laboratory approved by Company. All qualifying welds and tests must be witnessed by, and a copy of the certification presented to the Company representative. Contractor shall bear all costs for qualifying welding procedures, welders and welding operators. All qualification and production welds meet the requirements of API STD 1104 and the following Company specifications.
November 1988
1.
All welds must have complete joint penetration at the stringer bead around the entire circumference of the pipe. No inadequate penetration is allowed under this specification.
2.
The maximum time lapse between completion of the stringer bead and the start of the hot pass shall not exceed 10 minutes.
3.
Welds which contain unacceptable discontinuities (except cracks) may be repaired at the discretion of the Company representative. Each weld which contains a crack of has been repaired twice and is still unacceptable shall be cut from the pipeline and a new weld shall replace it.
4.
The cost of repairing or replacing any defective weld, including re-examination by non-destructive testing, shall be borne by Contractor.
5.
Welding must be protected from weather conditions that could impair the quality of the completed weld. Wind screens and tarps shall be used at the discretion of the Company representative if it is deemed necessary so that weather will not impair the quality of the welding. Company reserves the right to halt welding by Contractor on this project at the discretion of the Company representative if the seas, wind, rain, temperature of any other weather conditions are adversely affecting the quality of the welds.
6.
Either external or internal line-up clamps shall be used for all production welds. When using an internal line-up clamp the stringer bead must be welded around the entire circumference of the pipe before it is removed. When the pipe is stationary, external line-up clamps are permitted providing the stringer bead is welded in at least two areas 180° opposite each other for a minimum 50% of the pipe circumference prior to the line-up clamp being removed. At the discretion of the Company representative an external line-up clamp may be used on pipe that is moving on the lay barge providing that the stringer bead is welded in at least four areas 90° from each other for a minimum of 75% of the pipe circumference prior to the line-up clamp being removed.
7.
All welds must be allowed to cool to a temperature allowing the touch of the hand prior to being placed in water.
B-10
Chevron Corporation
Pipeline Manual
Appendix B
8.
Minimum acceptability standards for welds shall be in accordance with API STD 1104 modified such that no discontinuities will be allowed in the root pass.
Part XIII. 1.
Non-destructive testing shall be employed to inspect welds. The cost of such inspection shall be borne by Contractor. The expense of retesting welds after repair or replacement shall also be borne by Contractor.
2.
The primary testing method is radiography. Where radiography is utilized the procedures shall conform to API STD 1104.
3.
Company has the right to view radiographs of welds during construction.
4.
In the event that an unresolved difference of opinion exists between Company and Contractor over the disposition of a repair to a weld, the weld in question shall be cut from the line and subjected to destructive tests as if it were a procedure qualification weld in accordance with API STD 1104. If the weld passes the destructive tests Company will bear the cost of replacement. In the event the weld fails the test Contractor will bear the cost of replacement.
5.
When radiography is employed the standards of acceptability shall be the same as stated in API STD 1104 except that no inadequate penetration of the stringer bead will be allowed.
Part XIV.
Coating Specifications
1.
Contractor shall provide all necessary materials, of a type suitable to Company, to coat all field joints and make repairs to holidays in existing coating systems. All coating materials furnished by Contractor must be compatible with the primary pipe coating and applied in accordance with the manufacturers recommended procedure.
2.
Contractor shall remove all foreign particles, weld slag, loose mill scale, grease, etc. from pipe prior to coating joints or repairing damaged coating.
3.
Coating must be applied in such a manner, and allowed to harden to a state, whereby there is no damage caused by transporting the pipe over rollers, tensioning devices, stringers, etc. off the end of the lay barge.
4.
Contractor shall furnish a suitable company approved holiday detector and shall test the coating system for the entire length of the pipeline. All coating defects or damage shall be repaired by Contractor at this expense.
Part XV.
Chevron Corporation
Non-Destructive Testing
Pressure Testing Specifications
1.
Contractor shall furnish all necessary labor, supervision, tools, pumps, temporary piping, calibrated pressure and temperature recorders, calibrated gauges, fittings hoses, dead weight tester and all other equipment and materials for cleaning and pressure testing each section of pipeline installed by Contractor.
2.
Pressure tests shall be performed to 2160 psig for 24 hours unless otherwise directed by Company.
B-11
November 1988
Appendix B
Pipeline Manual
3.
Pressure testing instruments furnished by Contractor are to be a brand and model acceptable to Company. Proof of calibration within the last 6 months shall be supplied to Company by Contractor.
4.
Contractor shall submit pressure testing procedures and schedules for review and acceptance by Company prior to implementation.
5.
No pressure testing shall be preformed unless a Company representative is on site to witness same. Company shall be notified a minimum of 24 hours prior to test.
6.
Upon completion of laying and burying lines and installing test heads and scraper receiver/launchers Contractor shall run a gauging scraper acceptable to Company to determine if line is free of all debris. The outside diameter of the gauge plate shall be the same as the inside diameter of the pipe less one/half inch.
7.
After completely filling the lines to be hydrostatically tested with water, the pressure in the pipeline will be brought to the specified test pressure. Pressure shall be monitored with calibrated recording pressure and temperature gauges. Contractor shall furnish a dead weight tester along with all necessary fittings, etc. to monitor test. Contractor shall record the time of day, line pressure and the temperature at 30 minute intervals throughout the entire 2 hour test.
8.
After acceptance of hydrostatic test by Company, Contractor shall furnish Company with a test report in a form acceptable to Company. This report shall include the test charts, dated and certified by the Contractor and Company representative, descriptions, serial numbers and calibration certificates for the instruments, dead weight logs, the reason for the failure during a test, the name of the person responsible for the test, the name of the test company, date and time of the test, the minimum test pressure, the test medium, a description of the pipeline tested and an explanation of any pressure discontinuities that appear on any chart.
9.
Any repairs necessary as a result of the tests on lines installed by Contractor shall be made at Contractor’s expense and the line shall be retested.
10. Contractor shall remove water from pipeline after the acceptance of the hydrostatic test by Company. Part XVI.
Protection of Existing Pipelines and Facilities
1.
Contractor shall take necessary precautions so as not to damage any existing pipelines or facilities. The proposed 8 inch pipeline will cross underneath Chevron’s W-2 & S.P.27 Tank Batteries.
2.
Pipelines on the East Bank that Could Affect Steering Tool Several flowlines run parallel the east bank of the river and might affect the steering tool accuracy. The flowlines are two and three inches in size with one of two feet cover.
November 1988
B-12
Chevron Corporation
Appendix C. Offshore Pipelines
Abstract This specification is included here as an example only. It is based on a specification used by CUSA-Eastern Region to install subsea pipelines in the Gulf of Mexico. It is the “general specification” portion of a project specification and does not contain any detailed project information. A similar “General Specification” is used by COPI for pipelines outside the U.S.A. This example may provide you with the basis for producing a specification for a similar project.
☞
Warning Beware: it is not necessarily complete or applicable to any other project without modification. Modifications that should be considered are: •
Verification of the governing codes
•
Verification of the governing jurisdictions (DOI, DOT, state, county)
•
Restatement of the project particulars to precisely fit the individual case
•
Changes to clauses that may have been limited due to the permit or regulatory conditions imposed on the original specification
Contents
Chevron Corporation
Page
C1.0
General
C-2
C2.0
Materials
C-8
C3.0
Installation
C-11
C4.0
Welding
C-13
C5.0
Pipeline Coating and Other Coated Material
C-15
C6.0
Testing
C-17
C7.0
Zinc Anode Bracelet Installation
C-19
C8.0
Facilities for Company Personnel and Equipment
C-19
C9.0
Acceptance and Guarantee
C-19
C-1
November 1988
Appendix C
C1.0
Pipeline Manual
General C1.1
Scope of Work These specifications cover the necessary labor, equipment and materials necessary to install offshore pipelines and perform associated tie-in work in the Eastern Production Division. The term Company refers to Chevron U.S.A. Inc. or its authorized representatives and the term Contractor refers to the successful bidder. All work shall be performed in accordance with these and attached specifications and attached drawings which are made a part of these specifications.
C1.2
C1.3
November 1988
General Conditions 1.
Contractor shall maintain a Construction Representative in the field at all times who shall act in full charge of Contractor’s work and maintain field liaison between Contractor and Company’s Construction Representative.
2.
Contractor shall commence work on the project at the time stipulated on the bid form. Once having commenced work on this project Contractor shall prosecute same to completion with all due effort and diligence in a good and workmanlike manner.
3.
Contractor shall assume all lost time due to inclement weather conditions, high seas and/or strong currents.
4.
Company reserves the right to make minor changes in construction details without invalidating this agreement as long as the general scope of the project is maintained. If such changes or additions involve additional cost to Contractor payment shall be made in accordance with Section C1.1 and C1.3 of this specification.
5.
The successful Contractor shall be required to sign and enter into agreement with Company’s Service Order Agreement. A sample of this agreement is attached as Exhibit “C”.
6.
The Environmental Compliance Certification set out in an attachment hereto as Exhibit “D” is part of this agreement.
Company Shall Furnish 1.
Load-out facilities at Company’s Venice Shore Base.
2.
Radiography services for inspecting welds.
3.
Inspection services, including but not limited to, visual inspection and diving inspection supported from Company furnished vessels.
4.
All applicable permits to install the pipelines.
C-2
Chevron Corporation
Pipeline Manual
C1.4
Appendix C
Contractor Shall Furnish Except as specifically provided herein to be furnished or performed by Company, Contractor shall furnish all labor crews, divers, diving equipment, supervision, equipment, fuel, power, supplies, boats, tugs, tools and material, necessary to start, prosecute and complete the installation of the pipelines and associated work. Installation of the pipelines and performance of the associated work includes, but is not limited to, the following: 1.
materials handling
2.
transporting equipment, fuel, labor, tools, and materials to and from location of work
3.
qualifying welding procedures and welders
4.
preparing pipe for welding
5.
welding and repairing defective welds
6.
furnishing materials for and installing field joints and repairing defective joints on the pipelines
7.
laying the pipelines
8.
furnishing materials for and installing anodes on the pipelines
9.
all burial work
10. furnishing materials for and preparing and executing all pipeline crossings 11. furnishing riser clamps for and installing and securing pipeline risers 12. painting all bare pipe and furnishing paint 13. installing all required bends 14. fabricating and installing all pipe spools required for tie-in work 15. conducting hydrostatic and scraper tests on pipelines installed 16. dewatering the pipelines 17. removing and disposing of existing flowline 18. furnishing radio communication 19. furnishing quartering facilities for Contractor’s and Company personnel and equipment and meals for same
C1.5
Intent of Drawings and Specifications The specifications consist of the written material contained herein and the detailed drawings attached hereto.
Chevron Corporation
C-3
November 1988
Appendix C
Pipeline Manual
All work that may be called for in the written material and not shown on the drawings, or shown on the drawings and not called for in the written material shall be performed and furnished by the Contractor as if described in both ways and should any work or material be required which is not detailed in the written material or drawings, either directly or indirectly, but which is nevertheless necessary for the proper carrying out of the intent thereof, the Contractor is to understand the same to be implied and required, and shall perform all such work and furnish any such material as fully as if they were particularly delineated or described.
C1.6
C1.7
Permits 1.
Company will furnish all permits that are applicable to the work to be performed.
2.
Contractor shall familiarize himself with the terms and conditions of all Company furnished permits, and Contractor shall perform the work in strict compliance with said terms and conditions.
Precedence In the event of a conflict between any of the following items, they shall take precedence in the order listed:
C1.8
November 1988
1.
Construction Service Order Agreement (sample attached as Exhibit “C”).
2.
The text of this Specification.
3.
Construction drawings incorporated into this Specification.
4.
Piping standards incorporated into this Specification, if any.
5.
Standard Specifications incorporated into this Specification.
6.
Reference drawings and specifications, engineering instructions, and plant instructions incorporated into this Specification.
7.
American Society for Testing Materials Specifications or other similar publications referred to in this Specification but not attached hereto, if any.
Regulations and Codes 1.
It is the responsibility of Contractor to be in compliance with all applicable laws, ordinances, codes, regulations, and orders of all governmental agencies, whether federal, state, or local, during the life of this project.
2.
In the event Contractor is in noncompliance with a known law, ordinance, code, order, or regulation, Company will require Contractor to remove all personnel and equipment from Company property or leases until such time as Contractor is in compliance. In such case, Contractor is responsible for all costs incurred including, but not limited to, demobilization and remobilization of personnel and equipment.
C-4
Chevron Corporation
Pipeline Manual
Appendix C
3.
C1.9
C1.10
The latest edition of all industry accepted codes and federal regulations pertaining to pipeline installations that are referenced in this specification are hereby incorporated as if they were a part of the specification. Listed below are codes and regulations which may apply to this project. a.
API RP 1104 Standard for Welding Pipelines and Related Facilities
b.
AWS D1.1 Structural Welding Code
c.
ANSI/ASME B31.4 Liquid Petroleum Transportation Piping Systems
d.
ANSI/ASME B31.8 Gas Transmission and Distribution Piping Systems
e.
ANSI/ASME B31.3 Petroleum Piping
f.
49 CFR 192 Transportation of Natural and Other Gas by Pipeline
g.
49 CFR 195 Transportation of Liquids by Pipeline
h.
OCS Order 9 Oil and Gas Pipelines (Note: This order has been replaced by 30 CFR 250)
Payment 1.
Upon completion of the work described herein and acceptance of finished product by Company’s Project Engineer, including delivery of any required documentation, Company will pay Contractor the amount due therefore.
2.
Partial payment (not to exceed actual percentage of work performed) will be authorized by Company for jobs extending beyond one month, provided extensions are not caused by procrastination, idleness, etc. on part of Contractor. A maximum of 85% payment will be allowed until absolute completion. Invoices for partial payments and payments for extra work and/or materials will be made at a minimum of monthly intervals.
Insurance 1.
For all operations performed by Contractor hereunder, Contractor shall carry insurance such that the coverages and limits shall be acceptable to Company.
2.
All such insurance shall be obtained by Contractor from insurance companies which are acceptable to Company, and Contractor shall furnish to Company written evidence satisfactory to Company showing that such insurance is in effect and will not be cancelled for any cause whatsoever without 30 days written advance notice to Company.
3.
All such insurance shall be properly endorsed to afford full protection for all operations and services offshore to be performed hereunder by Contractor. Additional information concerning insurance requirements may be obtained by contacting Ms. Julie Kyle at 935 Gravier Street, New Orleans, Louisiana 70112 (telephone: 504-521-6262).
Chevron Corporation
C-5
November 1988
Appendix C
C1.11
Pipeline Manual
Safety The intent of these safety regulations is to outline procedures and should supplement, not replace, the Contractor’s safety program. The Company reserves the right of dismissal of Contractor’s personnel or termination of contract if a good safety program is not followed, or for deviation from the following: 1.
All personnel shall wear OSHA approved safety hats and shoes.
2.
Smoking will be permitted in designated areas only.
3.
Possession or use of alcoholic beverages or illegal drugs is prohibited.
4.
Proper eye protection shall be worn when performing work which involves a recognized hazard to the eyes.
5.
Coast Guard approved work vest or life jacket, furnished by Contractor to his personnel shall be worn during all over-water transfers and when working near or over water where there are no handrails.
6.
Horseplay, wrestling or practical jokes are prohibited.
7.
Crane shall be operated only by capable and qualified personnel.
8.
All power tools shall be grounded and in good condition.
9.
Before welding work is authorized and started on any structure or well jacket, there shall be thorough communication between Company representative and Contractor’s personnel. The nature of work to be done and all possible hazards shall be discussed in detail so all concerned will be aware of what is going on. The same care shall be taken each day so that any situation change can be evaluated.
10. All persons shall become familiar with the functions and locations of all the structure’s emergency shut-ins and fire stations. 11. No cutting, welding, or sandblasting shall be performed on structures or well jackets unless authorized in writing by Company Area Production Supervisor. This authorization will be secured by the Company Supervisor in charge. 12. Never use flame to detect a gas leak. Use soapy water. 13. There shall be a Company-furnished fire watch established on the structure before the work is started. The fire watchman’s only duty will be that of fire watch. The fire watch orders will be to know how to operate the fire extinguisher properly and have an extinguisher on the site near the work to be done. 14. All welding machines utilized on any structure or well jacket shall be equipped with spark arresting muffler. 15. Contractor agrees that it will notify all employees and related subcontract personnel, in writing, of Company’s policy prohibiting illegal drugs, intoxicating beverages, pyrotechnics, firearms, dangerous weapons, and other contraband on premises and/or work locations controlled by Company.
November 1988
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Chevron Corporation
Pipeline Manual
Appendix C
16. In the event that any damage, loss of property, or injury to any person is caused by or arises out of the failure of Contractor to notify its employees, and related subcontract personnel of Company’s policies, Contractor shall be liable and bear all costs, including attorneys’ fees, for all damages, loss of property or injury to any person.
C1.12
C1.13
Alterations, Modifications, Deletions and Extra Work 1.
Work not covered elsewhere in these specifications or attachments resulting from requests by Company and for which a mutually agreed upon price cannot be determined shall be performed under this section.
2.
Company shall have the right at any time or times before or during the actual performance of work hereunder to require additions, alterations, or deletions in contract work by notifying the Contractor thereof in writing. If such additions, alterations or deletions materially increase the amount of work to be performed, Contractor shall not be bound to undertake same until a mutually agreeable price shall have been arrived at between Contractor and Company, or the Company Project Engineer has authorized such work to be performed on a time and materials basis. If such alterations or deletions materially decrease the amount of work to be performed, Company will be credited with an amount mutually agreeable to Company and Contractor.
3.
Payments for extra work requested by Company will be made according to hours actually worked as approved by an authorized representative of Company. Hourly rates approved prior to commencement of work shall govern amount to be paid for such work. No claims for extras will be allowed unless agreed upon in advance by Company’s authorized representative requesting such services on that same day that those services occur.
4.
Extra items performed on an hourly basis will be covered by job ticket issued by Contractor and approved by Company representative requesting such services on that same day that those services occur.
5.
Job tickets must contain a complete description of work, type of equipment used and the hours and signature of personnel whose time is charged against the job.
Subcontractors This agreement shall not be assigned, sublet or transferred in whole or in part by Contractor, except with prior written consent of Company. If any subcontractors are utilized, Contractor shall be fully responsible to Company for the work performed as though Contractor had performed said work himself.
Chevron Corporation
C-7
November 1988
Appendix C
C2.0
Pipeline Manual
Materials C2.1
General 1.
Contractor shall furnish any and all material not specifically stated as Company-furnished in this Specification and attached drawings.
2.
All materials furnished by Contractor shall be new, unused, undamaged and of domestic manufacture.
3.
Fittings, flanges, studs, bolts, nuts and pipe shall conform to the following specifications unless otherwise stated herein: Materials
Specifications
Welded fittings and flanges ASTM A-234 Grade WPB
November 1988
Studs and Bolts
ASTM A-193 Grade B7, Cadmium Plated
Nuts
ASTM A-194 Grade 2H, Cadmium Plated
Pipe
API 5L Grade B Seamless or ASTM A106 Grade B Seamless
Ring Gaskets
Mild Steel, Cadmium Plated
4.
Contractor shall furnish to Company documented proof of compliance with an acceptable specification for all items to be permanently installed in this project. This must include but is not limited to mill certificates for manufactured steel items.
5.
Substitution of equivalent materials, parts or equipment must be approved by Company. Should Contractor substitute and Company approve materials, parts or equipment of greater size, strength or working pressure than is required, payment shall be made as if the specified item was used.
6.
Company may substitute materials, parts and/or equipment at its discretion to expedite construction.
7.
It shall be Contractor’s responsibility to inspect all Company furnished material and to sign delivery tickets attesting to the undamaged condition and proper quantity of same. Contractor shall refuse to accept any Company furnished material damaged prior to receipt by Contractor. Any material or equipment furnished by Company found damaged after receipt of contractor shall be repaired or replaced by Contractor at his expense. Copies of all delivery tickets shall be given by Company.
8.
Contractor shall be responsible for delivering all Contractor-fabricated or furnished material and all Company-furnished material or equipment delivered to him to the jobsite.
9.
Upon receipt, Contractor will be responsible for any loss of, or damage to, Company-furnished material.
C-8
Chevron Corporation
Pipeline Manual
C2.2
Appendix C
Line Pipe and Shop-Coating Company will furnish all line pipe. All line pipe to be installed will be API 5L, Grade B, seamless line pipe with 10-12 mils of thin-film epoxy coating, furnished in double random lengths. Company will furnish all line pipe loaded onto Contractor’s barges at Company’s Venice Shore Base.
C2.3
Risers Contractor will furnish risers. Risers will be API 5L, Grade B line pipe with 1/2inch Splashtron coating. Company will load riser on Contractor’s barges at Company’s Venice Shore Base.
C2.4
Other Pipe and Miscellaneous Materials All bare pipe and materials, such as flanges, fittings, studs and nuts, etc., shall be supplied by the Contractor.
C2.5
Field Joint Coating Materials Contractor shall furnish all field joint coating material for field joints. All material furnished by Contractor shall be approved by Company before work is commenced and shall be in accordance with Section C5.3 of this Specification.
C2.6
Anodes Contractor shall furnish all anodes for lines to be installed. See Figure C-1 for anode spacing. Anodes shall be zinc alloy bracelets.
Chevron Corporation
C-9
November 1988
Appendix C
Pipeline Manual
Zinc Alloy Bracelets
Fig. C-1
PIPE NOM. SIZE, in.
PIPE OD, in.
20 YR. SYSTEM, ft.
30 YR. SYSTEMS, ft.
2 1/2
2-7/8
24 lb. @ 530
24 lb. @ 350
3
3-1/2
36 lb. @ 650
36 lb. @ 435
4
4-1/2
36 lb. @ 505
36 lb. @ 335
4
4-1/2
48 lb. @ 675
48 lb. @ 450
6
6-5/8
60 lb. @ 575
60 lb. @ 380
6
6-5/8
72 lb. @ 690
72 lb. @ 460
6
6-5/8
84 lb. @ 805
84 lb. @ 535
8
8-5/8
72 lb. @ 530
72 lb. @ 350
8
8-5/8
96 lb. @ 705
96 lb. @ 470
8
8-5/8
108 lb. @ 795
108 lb. @ 530
10
10-3/4
84 lb. @ 495
84 lb. @ 330
10
10-3/4
120 lb. @ 710
120 lb. @ 470
10
10-3/4
132 lb. @ 780
132 lb. @ 520
12
12-3/4
108 lb. @ 535
156 lb. @ 355
12
12-3/4
144 lb. @ 715
144 lb. @ 475
12
12-3/4
156 lb. @ 775
156 lb. @ 515
14
14
120 lb. @ 545
120 lb. @ 360
14
14
168 lb. @ 760
168 lb. @ 505
Notes:
1. 2. 3. 4.
Weights are net alloy - based on available size bracelets) Ambient temperature Zinc bracelets - Based on current density of 6 MA/sq. ft. and zinc consumption rate of 25 lb./amp.yr. and 2% holidays. When surface temperature of the pipeline exceeds 140°F, aluminum bracelets must be used. Above 170°F temperature, the polarity of zinc alloy reverses, so it is cathodic instead of anodic relative to steel pipe. 5. Bracelet anodes for weight coated pipelines must be individually calculated due to wide range of coating thicknesses. 6. Variations in soil resistivity due to varying moisture and/or salinity necessitate specific calculations for the individual circumstances.
C2.7
November 1988
Paint and Surface Preparation 1.
Contractor shall supply all paint, paint equipment, and any materials necessary to prepare surface and coat all bare pipe, fittings, flanges, braces, etc., in accordance with the attached Coating Specifications, marked Exhibit “E”. The Glidden 5-Coat Vinyl System shall be applied, Section 7.3.A, with top coat black.
2.
All field welds, other than those to receive shrink sleeves, shall receive proper surface preparation and the Nupon 3-Coat System, Section 7.3.D of Exhibit “E”.
C-10
Chevron Corporation
Pipeline Manual
Appendix C
3.
C2.8
All surface preparation and coatings shall be inspected and accepted by the Company’s Project Engineer.
Materials Handling Contractor shall handle materials as required to perform and complete work. The term “handle” shall mean to collect, receive, transport, unload and load, store, uncrate, and warehouse, unless otherwise provided for under this specification. 2.8.1 Control of Company Furnished Material. Contractor shall be responsible for proper control and care of materials furnished by Company and shall perform necessary warehouse administrative duties. 2.8.2 Responsibility for Materials. All Company furnished material not permanently installed, shall be returned to Company, or be replaced or paid for at Company cost by Contractor, including any required load-out and transportation, at no additional cost to Company. 2.8.3 Surplus Consolidation. Contractor shall tally all surplus materials. Pipe shall be tallied to the nearest one-hundredth of a foot. All surplus material will be returned to Company’s Harvey Terminal, Harvey, Louisiana by Contractor. A copy of said tallies shall be forwarded to Company’s engineer.
C3.0
Installation C3.1
Chevron Corporation
General 1.
Contractor shall furnish tugs, crewboats, laybarges, spud barges, and pull barges capable of operation in depth available at the proposed location of work. Tugs and crewboats shall be equipped with radar. Tugs, crewboats and lay barges shall be equipped with operational two-way radios. Crewboats shall stand by during all hours Contractor is working in the area.
2.
It is called to the attention of the Contractor that pipelines and electric cables may be present along the pipeline routes and at existing structures. Care must be taken when moving equipment and excavating so that there shall be no damage to the above mentioned facilities.
3.
Open end of sections of pipeline, when unattended, shall be effectively closed or plugged.
4.
At start of work, Contractor shall have a procedure, with necessary material and equipment to put it into effect, for handling the lines during storm conditions when normal laying operations cannot be done. Procedure shall provide means for sealing and securing the pipelines, and relocating the pipeline when work again commences.
5.
Contractor shall be prepared to work a minimum of 12 hours per day, 7 days per week from the time this project commences until all of the work described in this specification is termed complete.
C-11
November 1988
Appendix C
C3.2
Pipeline Manual
6.
It is the intent of the aforementioned drawings and specifications to receive facilities which are complete in every respect, constructed in accordance with generally accepted, current good practices of the trades involved and ready to operate in the manner expressed or implied herein, regardless of whether or not full details of such completeness or practices are contained herein.
7.
All welding within 50 feet of any Company facility shall first be approved by Company.
Pipelines Installations 3.2.1 Laying 1.
Installation of the pipelines shall be performed in accordance with the attached drawings, and these and attached specifications.
2.
The method of installation chosen by the Contractor shall be such that, during construction, deviation of the pipeline from the permitted route shall be kept to a minimum at all times.
3.
Company may inspect the lines as laid at any point regardless of Contractor’s method of installation. Should inspection indicate improper installation or damage to either the pipe or its coating, Contractor shall repair same at his own expense.
4.
Each length of pipe shall be examined to ascertain that it is free from dirt or objects which may cause obstruction. If the pipe is obstructed in any way or has an excessive amount of dirt, rust and/or scale then it shall be cleaned out before being installed in the pipeline.
5.
Contractor shall furnish any and all shop-made pipe bends which may be required to lay the pipelines along their designated routes. These bends shall be coated prior to delivery.
3.2.2 Burial Contractor shall bury only the pipelines installed by Contractor. The lines shall be buried three feet below the mudline in all areas with depths less than 200 feet. This may be performed by a jet barge if Contractor so desires. 3.2.3 Pipeline Crossings 1.
It is shall be the Contractor’s responsibility to locate any existing pipelines as shown in the drawing.
2.
Where the pipeline crosses existing, lines, Contractor shall locate and expose these existing lines by hand excavation prior to performing any other work at that location, if any.
3.2.4 Testing Following completion of the pipelines installation, Contractor shall hydrostaically and scraper test lines according to Section C6.0 of these specifications.
November 1988
C-12
Chevron Corporation
Pipeline Manual
C4.0
Appendix C
Welding C4.1
General The purpose and intent of these specifications is to obtain 100% welds as to ductility, tensile strength, good workmanship, fusion, and penetration for the entire circumference of the welds. Contractor shall conform to API Standard 1104, latest edition, “Standard for Field Welding of Pipelines”, except as modified herein. Contractor shall have copies of this specification on the job at all times for reference.
C4.2
Tests for Welders Welding procedures, welders, and welding operators to be employed on this job shall be qualified in accordance with API Standard 1104, “Standard for Welding Pipelines and Related Facilities”, latest edition, and further qualified herein. Welding procedures shall be submitted to Company for approval before testing commences. All tests shall be witnessed by Company Engineer and/or Inspector. Procedure qualification tests shall be sent to an independent testing laboratory for testing and evaluation. The testing laboratory shall meet Company approval. Contractor shall pay for the costs of the tests. Further qualifications to API Standard 1104 are as follows:
C4.3
1.
The root bead shall have 100% penetration.
2.
Test will be performed on 2-7/8" Sch. 80, API 5L Gr. B pipe in the “5G” position.
3.
Electrodes and pipe specimens used in the tests shall conform to those listed in 4.3 herein. Contractor shall furnish the pipe for the tests.
4.
Preparation of bevel surface and cleaning of weld between passes will conform to actual line work.
5.
Welder will be assigned a qualification card after successfully completing qualification test and will be required to keep it on his person at all times while working on this job.
6.
If ASTM Specifications do not require minimum Charpy V-Notch impact properties for the electrodes and fluxes that are to be used for procedure qualification, the Charpy V-Notch test specimen shall be removed and tested according to ASTM A-370 and E23. The as-welded deposited weld metal is required to have a minimum impact strength of 20 foot-pounds at 0$F.
Line Welding 1.
Chevron Corporation
The manual electric arc welding process shall be used for all welding except where another type is authorized by Company. The current and voltage recommended by the manufacturer of the electrodes used shall be maintained throughout the welding process. Equipment in poor repair and without gauges
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November 1988
Appendix C
Pipeline Manual
showing voltage and amperage will not be permitted. The following details apply to the electric process: a.
November 1988
The welding procedure shall be as follows: Root E 60 10
1/8" electrodes
Hot Pass E 60 10
1/8" electrodes
Fill and Cap E 70 10
3/32" electrodes
b.
The root bead shall have 100% complete penetration.
c.
Weld slag shall be removed by power wire brushing before making succeeding passes.
d.
The hot pass shall follow stringer pass immediately or weld will be cut and rewelded. Once started, a weld will be completed before the end of the work day.
e.
Full penetration shall be secured without allowing the metal to run inside the pipe. The inside of the pipe shall be left smooth. Each bead shall be applied completely around the pipe.
f.
Company shall condemn any weld that has not been properly made. Condemned welds shall be plainly marked if Contractor wishes. All condemned welds shall be immediately cut out and new welds made. Whenever cutting out welds leaves the two ends of the pipe so that they cannot be properly spaced without damaging the line, they shall be joined by welding in a short piece of pipe not less than five (5) feet in length.
g.
Any weld calked or tampered with before being accepted by Company will be condemned whether or not it leaks; “doctoring” the surface of defective welds with a torch will not be permitted.
h.
Cost of repairing any defective weld shall be borne by Contractor.
i.
No welding will be permitted in inclement weather, unless Company approves shelter provided for welder and pipe.
j.
A ground may not be welded to the pipe or fitting that is being welded.
2.
Internal line-up clamps shall be used for all welded joints on pipe. Line-up clamps shall be left in place until the stringer bead has been completed around the circumference of the pipe. The stringer bead shall be completed before starting hot pass.
3.
Joints shall be placed together in correct alignment and positioned with the proper root opening. Each length shall be properly supported on rollers, so that when the pipe is rolled there will not be excessive stress on partly finished welds.
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Appendix C
4.
5.
C4.4
C5.0
Pipe condition and inspection prior to welding any joint of pipe will include, but is not limited to: a.
Each length of pipe shall be thoroughly examined inside to make sure that there is no evidence of internal damage and that it is free from dirt, animals or other obstructions, that might clog the line or contaminate the commodities to be transported. Any evidence of internal damage shall be made as authorized. If obstructed in any way, the pipe shall be swabbed out before being incorporated in the line. The complete absence of foreign matter from the completed line will be a condition precedent to the acceptance of the pipeline. If directed by Company, all joints will be swabbed before welded into the line.
b.
The ends of the pipe will be thoroughly cleaned of rust, scale, dirt, grease, protective coating or other foreign matter which might affect the quality of the welds. Beveling shall be done by using any oxygen cutting, mechanically operated beveling band. Cleaning shall be done with mechanical power tools.
After completion of each weld the uncoated section of pipe and weld at each joint will be thoroughly cleaned of slag, mill scale, dirt, grease, or other foreign matter by mechanical means to assure proper bond of thermal fit sleeves.
Inspection 1.
Company shall supply such inspectors as are necessary to observe work done by Contractor, and insure that all requirements of this Specification are being met. Inspector will function as the liaison between Contractor and Company for reporting progress and quality of work. Inspectors shall have the authority to enforce the terms of this Specification.
2.
Company will engage the services of an independent radiographer and pay the costs except as provided by Section C4.3 above.
Pipeline Coating and Other Coated Material C5.1
General Contractor shall follow procedures for handling of thin film epoxy coated pipe, application of field joints, repair of defective coating, and testing of coating in accordance with the following sections of this specification and with the manufacturer’s specifications and recommendations.
C5.2
Protection of Coating Against Damage Contractor shall take specific care in handling coated pipe to avoid injury to the coating by excessive bearing pressure or impact.
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November 1988
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Contractor shall provide adequate positive measures to prevent damage to coating during installation, launching, and lowering-in operations. These measures include, but are not limited to, such arrangements as wide non-abrasive belt slings, sawdust sacks or other padding at skids or fixed supports, rubber-wheel rollers under moving pipe, etc. Pipe supports must be spaced so that damage to coating is not caused by excessive weight at points of support.
C5.3
C5.4
C5.5
Coating Field Joints 1.
Contractor shall furnish field joint and patch materials and shall apply field joints and patches. Field coating work shall be in accordance with manufacturer’s specifications and recommendations.
2.
Contractor shall provide or arrange for use of necessary equipment required to properly apply the field joints and repair damaged pipe coating.
3.
Material for field joints shall be Canusa or Raychem Brand Thermal Shrink Sleeves applied according to manufacturer’s specifications.
4.
All bare pipe adjoining field welds shall be thoroughly cleaned of dirt, rust, or any other material except unburned coating.
Test For Defects 1.
Contractor shall inspect visually and test the quality of all coating immediately prior to launching or lowering any section of pipe into water or ditch with a Stearns, or Tinker and Raor holiday detector or an equivalent machine approved by Company. Detectors shall be set at voltage recommended by the detector manufacturer for the coating thickness used. Contractor shall furnish all holiday detectors and shall maintain them in satisfactory operating condition at all times. Any flaws detected shall be repaired by Contractor to Company’s satisfaction as specified in 5.5 of this Specification.
2.
Any field joint considered defective for any reason by Company shall be replaced or repaired at Contractor’s expense as directed by Company representative.
Patched and Repairs All holidays shall be repaired according to the coating manufacturer’s specifications. All repaired holidays shall be retested.
C5.6
Responsibility Contractor shall be solely responsible for both pipe and coating and any damage incurred by either from the time he received the pipe until all of the work described in this Specification is termed complete.
November 1988
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C6.0
Appendix C
Testing C6.1
General Following completion of the pipeline installation, Contractor shall test the completed pipelines hydrostatically, and shall run a gauging scraper through the lines. Contractor shall use water for testing that it is free from dirt, silt, or foreign matter. Contractor shall furnish pumps, piping, settling tanks, 8-mesh or finer strainer, and equipment for properly testing the pipelines. No pressure testing will be performed unless a Company representative is on site to witness same. Company shall be notified a minimum of 24 hours prior to test.
C6.2
Hydrostatic Test Pipelines and associated piping shall be hydrostaically tested to 1-1/2 times the working pressure of the line by the procedure specified below. The Company engineer will provide the Contractor with the test pressures for any lines to be tested. Contractor shall provide a safety relief valve at the pump end of the line during the test to insure relief before over-stressing the pipe. 6.2.1 Test Procedure The line shall hold the specified test pressure without loss of pressure and without any further pumping for a minimum period of four hours. Line pressure and quantity of water used in pressuring shall be recorded at intervals of approximately 100 psi while pressuring. After reaching the specified test pressure, line pressures and temperatures shall be recorded at intervals of 30 minutes, or at longer intervals as approved by Company. While pressuring the line, Contractor shall patrol accessible sections of the line where leakage would be likely to cause extreme damage or hazard to others. Contractor shall remove temporary testing facilities on completion of satisfactory test. 6.2.2 Repair and Retest If there is leakage, Contractor shall locate the leak and shall make repairs to the satisfaction of Company, after which the test shall be repeated or the line accepted, at the option of Company. Contractor shall bear the expense of repairs or retests necessitated by his faulty workmanship and materials; Company will bear the expense of repairs and retests occasioned by the use of faulty material supplied by Company provided the faulty material removed is returned to Chevron U.S.A. Inc. 6.2.3 Pressure Gauges Contractor shall furnish chart recorder and dead weight tester for use in hydrostatic tests. Pressure testing instruments furnished by Contractor are to be of a brand and model acceptable to Company. Proof of calibration within the last 6 months shall be supplied to Company by Contractor.
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6.3.4 Records A record of this test shall be compiled which includes the recording gauge charts, dead weight tester data, data compiled in 6.2.1 as outlined previously, ant the reasons for any failure during a test. Each recording chart must contain: 1.
Company name, name of person responsible for making test, name of company making test
2.
Date and time of test
3.
Minimum test pressure
4.
Test medium
5.
Description of the facility tested.
6.
Explanation of any pressure discontinuities that appear on chart.
6.2.5 Dewatering On completion of satisfactory hydrostatic test, Contractor shall remove all temporary testing facilities. Contractor shall purge the tested lines of all water.
C6.3
November 1988
Scraper Test 1.
Contractor shall test each completed pipeline by pumping water through the line and running a pipeline gauging scraper through the entire length of the line. Scraper of a design approved by Company shall be furnished by Contractor. Pumping equipment for running scrapers shall have sufficient capacity to move scrapers at a speed of not less than one (1) mile per hour. While running scrapers, Contractor shall measure the volume of water pumped so as to have data for calculating the progress of the scraper. Contractor shall provide adequate facilities for draining water at the end of each line. If the scraper fails to pass through the line, Contractor shall locate and remove the obstruction and the stuck scraper and shall promptly repair the line at Contractor’s expense. Repairs shall be inspected and approved by Company, and at Company’s option the line shall be retested hydrostatically.
2.
If the scraper test fails to pass through the existing 2-7/8 inch O.D. line, Contractor shall locate and remove the obstruction and the stuck scraper and shall promptly repair the line at Company’s expense.
3.
On completion of satisfactory scraper and hydrostatic test, Contractor shall remove all temporary testing facilities.
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C7.0
C8.0
Appendix C
Zinc Anode Bracelet Installation 1.
Contractor shall provide all labor, equipment and material to install bracelet anodes in accordance with these Specifications.
2.
Anode bracelets will be supplied by Contractor. Anodes shall install per the spacing shown in Section C2.6 - Figure C-1.
3.
At all times utmost care should be taken to protect the pipeline coating during anode installation. All coating damage and the coating around the bracelet grounds shall be repaired in accordance with Section C5.0 of this specification.
Facilities for Company Personnel and Equipment 1.
Contractor shall furnish suitable lodging, sanitary facilities, meals, transportation and assistance, as required, for Company personnel (engineers, inspectors, and visitors). It is anticipated that up to four (4) persons will be on the job during one (1) shift.
2.
Contractor shall furnish suitable space and utilities for Company as follows:
3.
C9.0
a.
Office space with desk, chair, and lamp.
b.
Quarters provided for Company personnel shall be solely for the use of Company personnel and no others.
Company representative shall have access to crewboats or workboats contingent upon such use not interfering with the progress of the project.
Acceptance and Guarantee 1.
Upon completion of the work, Contractor shall remove all leftover material from work site and clean all debris and trash from the structure for disposition as directed by the Company’s representative.
2.
Prior to release of construction equipment and labor from work area in the field, the jobsite will be inspected by the Contractor and Company representative jointly for the final acceptance by the Company.
3.
The Contractor shall guarantee that all work installed by him is free from any defects in workman- ship and material and that all apparatuses will develop the capacities and characteristics specified. Contractor further guarantees that, if, during the period of one year from the date of the certificate of completion and acceptance of his work, any such defects in workmanship, material or performance appear, such defects will be remedied by him without cost to the Company. Should the Contractor fail to remedy the defects, as outlines above, within a reasonable length of time, to be specified in a notice from the Company to the Contractor, the Company may have such work done and charge the cost to the Contractor.
Chevron Corporation
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November 1988
Appendix D. Operating Plan Guidelines
The material in this appendix is intended as an example only. It describes some of the information required in pipeline operating plans. The information may be useful in developing an operating plan for your project. Part I is extracted from a Chevron Pipeline Company pipeline operating procedure and covers Abnormal and Emergency Situations. Part II is extracted from a CUSA Eastern Region operation and maintenance plan guideline for DOT regulated pipelines. It consists of the table of contents for the entire plan and the text of the General section. Contents
Chevron Corporation
Page
I
Chevron Pipeline Company, New Orleans Division, Standard No. 4.2, Pipeline Operating Procedures D-2
II
Chevron USA Inc., Eastern Region, Operations and Maintenance Plan Guidelines for DOT Regulated Gas Pipelines D-7
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Appendix D
Pipeline Manual
Part I. Chevron Pipeline Company, New Orleans Division, Standard No. 4.2, Pipeline Operating Procedures
Abnormal and Emergency Situations Scope 1.
This standard established procedures and responsibilities in the event that an emergency or an abnormal situation develops and will apply whether the system is controlled remotely by SCADA or locally.
Abnormal Conditions 2.
It is the responsibility of the appropriate Senior Operator, Operations Supervisor and/or operations personnel to respond to, investigate and take steps to correct any abnormal problem. a.
Unintended closure of a valve.
b.
Unintended shutdown.
c.
Increase or decrease in pressure flow rate outside normal operating limits.
d.
Loss of communications.
e.
Operation of any safety device.
f.
Any other malfunction of a component, deviation from normal operation or operational error which could cause a hazard to persons or property.
Unintended Closure of Valves 3.
Should a valve close without a command the line shall be shut-down and the valve reopened. If no apparent damage to the line, restart the line and monitor closely. If a person erroneously closes a main block valve, the valve shall be reopened and the line closely observed for a two hour period.
Unintended Station Shutdown 4.
Should a station shut-down without a command, the Senior Operator or Operations Supervisor should check for the cause of the shutdown and attempt to restart the station at his own discretion. If the station cannot be restarted the Terminal Supervisor, Operations Supervisor, or District Supervisor/Superintendent shall be notified.
5.
November 1988
Each trunk line has a maximum working pressure. Each station is equipped with a high pressure shutdown system, and if the pressure does exceed this limit, the automatic system should shut the station down. However, if it does fail, the station operator should shut the line down himself and contact the Operations Supervisor.
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Appendix D
When any change in pressure of 15 pounds or greater occurs which is not attribute to rate change, temperature or other normal condition, or when any increase in flow rate accompanied by a decrease in pressure occurs, the operator will shut down the affected system immediately. Communications 6.
Without communication the Supervisory Control and Data Acquisition (SCADA) systems cannot operate. Loss of communication shall be reported to Chevron Communication within fifteen minutes. Any station that has lost communication and needs assistance from local personnel to monitor meter readings, tank gauges, etc., shall call the District Operations Supervisor/Terminal Supervisor who will furnish the personnel.
Other Malfunctions 7. a.
Field operating personnel (gaugers, etc.) are to immediately notify the pipeline station operatorsregarding any abnormal or emergency conditions which they observe.
b.
Any malfunction that is a deviation from normal operation or operational error that could cause a hazard to persons or property shall be reported to the District Operations Supervisor/Terminal Supervisor immediately.
c.
Any abnormal operation that activated the SCADA leak detection shall be investigated immediately to determine the cause. If no cause can be determined, the line will be shutdown until the cause can be found and repaired.
d.
A locking device allows the Senior Operator or Operations Supervisor to make the decision to restart.
Obvious Emergencies 8.
Chevron Corporation
Emergencies requiring immediate line shutdown: a.
A serious leak on the line.
b.
Overflowing receiving tank.
c.
High level alarm on any tank.
d.
Fire, explosion, massive spill, or other occurrence endangering operating facilities.
e.
Disabling injury of responsible operating employee on the job.
f.
Accidental damage to critical Company facility.
g.
Unscheduled shipment into or from the station.
h.
Unexplained decrease or increase in operating pressure, flow, or tank level.
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November 1988
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i.
Any other situation that arises which presents an immediate serious hazard.
Emergency Procedure 9.
Refer to the Emergency Shutdown Procedure found in each system Standard for expediting shutdown of individual lines or sections.
Appropriate Action — Senior Operator 10. The Senior Operator or Operations Supervisor will immediately call supervisor, other companies involved, emergency services (fire department, police, ambulance, doctor, etc.) as required, explain the problem, and direct them to the scene. Senior Operators or Senior Operations Supervisor may also direct operating or other personnel to make emergency call where more direct or convenient, and to speed-up action. The Senior Operator or Operations Supervisor is responsible for making sure that messages get through to the necessary parties and that corrective action is being taken. a.
The Senior Operator or Operations Supervisor will stay on top of the situation until the emergency is under control of the proper Company personnel at the scene.
b.
Telephone numbers for most emergency situations will be found in the Emergency Response Book.
c.
The time to wait before calling for a line shut-down is dependent upon the seriousness of the condition and calls for good judgement by the Operator after consulting with the Terminal Supervisor/ Operations Supervisor or District Supervisor/Superintendent. Generally, it is best to be conservative. The Senior Operator/Operations Supervisor should first contact operating people at or near the scene of the problem to investigate and/or explain the unusual occurrence. Also, always call the Terminal Supervisor/District Supervisor of the area and discuss the problem and possible corrective actions. After the above, if any doubts still remain, shut down the section of line involved.
Appropriate Action — Operators 11. General procedure to be followed in the event of emergencies by Station Operators, Gaugers, and other operating personnel are:
November 1988
a.
Operating people are guided by emergency situations listed in Paragraph 7 and are expected to take immediate action to shut-down and/or investigate all facilities operated under their jurisdiction.
b.
Any emergency or unusual situation is reported to the Senior Operator/Operations Supervisor at the earliest convenient opportunity. Where abnormal situations are not of the magnitude to require immediate steps, notify the Operator first and discuss remedial measures. Also report occurrences to the District Terminal Supervisor/Operations Supervisor.
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Appendix D
c.
Most emergency situations require operators, etc. to take immediate corrective measures such as: 1.
Shutting down pumps.
2.
Switching streams.
3.
Switching tanks.
4.
Controlling immediate or primary fires.
5.
Calling fire department, police, ambulance, doctors, or other emergency services.
6.
Administering first aid.
7.
Removing the source of ignition.
8.
Shutting off fuel.
9.
Building primary dams.
10. Repairing small leaks. 11. Adjusting small leaks. 12. Correcting other situations where malfunctions can present a serious hazard. Appropriate Action — District Supervisors/Superintendent 12. It shall be the responsibility of the Terminal Supervisor/Operations Supervisor involved (and/or his representatives) to immediately investigate the emergency and to take appropriate steps.
Chevron Corporation
a.
Respond promptly and effectively to each emergency.
b.
Know of sufficient personnel, equipment, instruments, tools and material to handle each emergency. (Supplemental people and equipment are available from listings in the Emergency Response Book.)
c.
Control and minimize the hazard of released petroleum at the scene of the emergency including intentional or accidental ignition.
d.
Minimize public exposure to injury and probability of accidental ignition, by evacuating residents and by halting traffic on roads and waterways in the affected area.
e.
Notify fire, police, Coast Guard and other appropriate public officials of a liquid pipeline emergency and coordinate their response including necessary precautions for the particular type of emergency.
f.
Conduct a post accident review.
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Emergency Reports 13. In any emergency situation - leak, oil spill, fire, or injury, it is extremely important for the person receiving the first contact to get the precise physical location and description. To this end, a standard procedure is very helpful in receiving and recording information which might be otherwise omitted or unreported. The following should be noted: a.
Name, company, and phone number of the person reporting so that he may contacted later for more specific information.
b.
Location of Emergency - in addition to the general area, get a Loran or known landmarks.
c.
Type of leak - large, small, running, crude, natural gas, etc. Any information will help identify the type of leak.
d.
Amount of Oil Out - or area engulfed.
e.
Immediate Danger of the situation - establish what public/private facilities are affected and endangered or about to be.
f.
Other pertinent information which might be helpful to persons investigating the emergency or to the repair/cleanup crews in determining equipment needed.
Air-patrol 14. Another valuable tool for use in emergency situations by operating personnel is the Air Patrol. In any situation deemed appropriate by the Terminal Supervisor, Operations Supervisor, or District Supervisor/ Superintendent, the air patrol plane can cover large areas of pipeline quickly. This information could save valuable time during investigation of possible leaks or locating actual leaks.
November 1988
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Appendix D
Part II. Chevron USA Inc., Eastern Region, Operations and Maintenance Plan Guidelines for DOT Regulated Gas Pipelines The following table of contents is included to show the scope of the entire document. Only Section I, General, is excerpted in the following pages. Contents
Page
I. A. B.
GENERAL Introduction Documents Incorporated by Reference
II.
OPERATION, MAINTENANCE AND REPAIR
A. B. C. D. E. F. G. H. I. J. K. L. M. N.
Operation, Maintenance and Repair Instructions Provisions for Periodic Inspections to Verify Class Location Continuing Surveillance and Inspection of Failures Installation and Evacuation of Gas Pipelines Maximum Allowable Operating Pressure Hot Tapping Pipeline Purging Pipeline Patrol and Leak Surveys Pipeline Leak Records Line Markers Repair and Testing of Lines Valve and Pressure Limiting Device Inspections Corrosion Control Pipeline Inactivation or Abandonment
III.
REPORTING PROCEDURES
A. B.
Gas Pipeline Incident Reporting Annual Report
APPENDIX: REPORT FORMS A. B. C. D. E. F. G. H. I. J. K.
Chevron Corporation
Class Location Survey Gas Pipeline Qualification Record (4 pages) Incident Report - Gas Transmission and Gathering Systems - Form RSPA F 7100.2 Instructions for Completing form RSPA F 7100.2 (7 pages) Pipeline Aerial Patrol Report Pipeline Leak and Repair Report Valve Inspection Report Pressure Control Device Inspection External Corrosion Report Annual Report, Gas Transmission and Gathering Systems - Form RSPA F 7100.21 Instructions for Completing RSPA F 7100.2-1 (4 pages)
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November 1988
Appendix D
Pipeline Manual
General Section A. Introduction 1.
Purposes and Applicability These guidelines are provided for Chevron’s Eastern Divisions to follow in preparing and updating Operation and Maintenance Plans for all Department of Transportation (DOT) regulated gas pipelines as required by 49 CFR, Subchapter D: Pipeline Safety. The guidelines describe inspection, operation, maintenance, recordkeeping and reporting requirements necessary for compliance. Each Operation and Maintenance Plan should include the essentials listed herein as well as in 49 CFR 192.605. Individual plans must be tailored to specific pipeline systems and therefore, may include additional information or instruction other than that described in these guidelines or in 49 CFR Subchapter D. With this in mind, the plans should be prepared and updated with an understanding of the intent of 49 CFR i.e., to safely operate and maintain pipeline systems.
2.
Responsibility Each Division Manager is responsible for preparing and updating an Operation and Maintenance Plan for DOT regulated gas pipelines operated and maintained by the respective Division. In addition, Division Manager should ensure that:
3.
a.
Copies of the plan and any updates are available to personnel operating and maintaining DOT regulated pipelines.
b.
The pipe in implemented to include establishing report and recordkeeping requirements.
c.
The plan is reviewed and updated at least annually.
Overview of Regulatory Requirements a.
49 CFR 192 Applicability 49 CFR Part 192 applies to gathering of gas by pipeline in or affecting interstate commerce, including within the limits of the outer continental shelf, but does not apply to:
November 1988
1.
Offshore gathering of gas upstream from the outlet flange of each facility on the continental shelf where hydrocarbons are produced of where produced hydrocarbons are first separated, dehydrated, or otherwise processed, whichever facility is farther downstream; and
2.
Onshore gathering of gas outside the following areas: a.
An area within the limits of any incorporated or unincorporated city, town, or village.
b.
Any designated residential or commercial area such as a subdivision, business or shopping center, or community development.
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Appendix D
b.
49 CFR Subpart L: Operations Subpart L prescribes the minimum requirements for the operation of pipeline facilities. Section 192.603 cautions that no person may operate a segment of a pipeline unless it is operated in accordance with Subpart L, and that each operator shall establish a written Operation and Maintenance Plan meeting the requirements of Subpart L and keep records necessary to administer the plan.
c.
49 CFR Subpart M: Maintenance Subpart M prescribes minimum requirements for maintenance of pipeline facilities. Section 192.703 cautions that no person may operate a segment of pipeline unless it is maintained in accordance with Subpart M; that each segment of a pipeline that before unsafe must be replace, repaired or removed from service; and that hazardous leaks must be repaired promptly.
4.
Report Forms All forms, referenced herein, are included in this Appendix.
B. Documents Incorporated by Reference The following list of publications incorporated herein by reference should be available in the office if the Division Manager and Operations Superintendent. These documents support the intent of the Operations Superintendent. These documents support the intent of the Operations and Maintenance Plan. Then contain programs, instructions, practices and operational procedures to ensure a safe work environment and to minimize the possibilities for accidents and/or pollution. 1.
General Plan For Conducting Simultaneous Operations Prescribes rules that must be observed where multiple operations are in progress on an offshore platform or other congested areas in the OCT. Emphasis that a single person must be in charge of all operations and that proper communications must be established between all involved personnel. The guidelines obtain a list of specific precautions for specified operations.
2.
Electrical Construction Standards For Offshore and Marshland Locations Prescribes construction practices for making repairs, changes, or additions to electrical installations.
3.
Oct Order No. 9 From The Mms Outlines the approval procedures for oil and gas pipelines in the OCT. Requires semiannual reports of the past history, details and dates of inspection, testing, repairs, adjustment and reinstallation or pipeline safety devices such as high-low pressure sensors, automatic shut-in valves, etc., leakage inspection,; and protection of pipelines from water currents, storm scouring, soft bottoms and other environmental factors.
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4.
Welding, Burning, And Hot Tapping Safe Practices and Procedures Plan Prescribes safe practices and procedures that must be followed while performing any type of “hot work” on an offshore facility in the OCT.
5.
Hurricane Action Plan Contains a methodical set of procedures to follow to shut-in facilities and evacuate personnel from offshore during impending hurricanes.
6.
Oil Spill Contingency Plan a.
Prescribes procedures to be followed when an oil spill occurs. Lists applicable regulations; alert, reporting, action, containment, and clean-up procedures; co-op agreements for sharing equipment and materials; and Company owned equipment, etc. Each Division Manager shall have a specific emergency plan prepared in the event a spill occurs from a DOT regulated line. As a minimum, the plan should include: 1.
Responsibility and procedure for notifying the company personnel who are concerned and will be involved.
2.
Responsibility and procedure for notifying any appropriate Federal of state of local government agencies.
3.
Organization or repair and pollution control group and delegation of responsibilities. Group might include Project Manager, communication and supply personnel, repair personnel and pollution control personnel.
4.
Daily reporting and information required by Project Manager.
5.
Government reporting.
6.
The communication equipment needed and location where it is available.
7.
Lists of applicable drawings and maps and locations where they are available.
8.
Specify base of operation and dock for work on various pipeline segments.
9.
List approved contractors for various types of work.
10. List materials in stock and its location that may be needed for the work. 11. Draft scenario of response procedures for a typical emergency, such as a pipeline rupture. b.
November 1988
These procedures can either be incorporated in an Oil Spill Contingency Plan or be incorporated in the Emergency Plan for Gas Pipelines (see paragraph 7, below)
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7.
Emergency Plan for Gas Pipeline This plan is required by 49 CFR Section 192.615 and contains written procedures to follow to minimize the hazard resulting from a gas pipeline emergency. Minimum plan requirements are specified in 49 CFR Section 192.615.
Chevron Corporation
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November 1988
Appendix E. Field Inspection Guidelines
Abstract This appendix contains portions of the Inspection Manual for the 1987-1989 Mesquite Pipeline Project in Texas. It was prepared by Chevron Pipe Line Company. It is included here as a guide to the duties of field inspectors, the makeup of a field organization, and the preparation of a manual for your project. For most projects several inspection functions described in the Inspection Procedures would be handled by one inspector or field engineer, so that the Company field team would have considerably fewer members than the separate Procedures seem to suggest. The Mesquite Project involved construction of new pipelines, and repair and replacement of existing products pipelines. Total length was approximately 200 miles of NPS 8,10,12 pipeline. Contents
Chevron Corporation
Page
E1.0
Safety Requirements - Preliminary
E-3
E2.0
Construction Emergency Procedures
E-6
E3.0
Phone Directory & Emergency Call Out List
E-7
E4.0
Fire Fighting Procedure
E-7
E5.0
Bomb and Extortion Threats
E-10
E6.0
Independent Contractors Safety Practices Guide
E-10
E7.0
Inspection Procedures
E-10
E7.1
Inspection General Guidelines — All Crafts — Procedure No. 1
E7.2
Utility Inspector — Procedure No. 2
E7.3
Front End Inspector — Procedure No. 3
E7.4
Daylight Inspector — Procedure No. 4
E7.5
Clearing Inspector — Procedure No. 5
E7.6
String and Bending Inspector — Procedure No. 6
E7.7
Trenching Inspector — Procedure No. 7
E7.8
Bore Inspector — Procedure No. 8
E7.9
Welding Inspector — Procedure No. 9
E7.10
Tie-in Inspector — Procedure No. 10
E7.11
Coating Inspector — Procedure No. 11
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E7.12
Lowering-in Inspector — Procedure No. 12
E7.13
Backfill Inspector — Procedure No. 13
E7.14
Restoration And Revegetation Inspector — Procedure No. 14
E7.15
Lead Inspector — Procedure No. 15
E8.0
Inspection Audit Forms — Mesquite Pipeline Project
E-33
E9.0
Welding Procedures
E-54
E10.0
Welder Qualifications
E-54
E11.0
Line Pipe Summary
E-54
E12.0
Codes and Specifications
E-54
Note Section E3.0, E6.0, E9.0, E10.0, E11.0, and E12.0 were included in the original manual but are not reproduced here.
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E1.0
Appendix E
Safety Requirements - Preliminary
Chevron Corporation
1.
THERE IS NO INCENTIVE (INCLUDING POTENTIAL PROPERTY DAMAGE) LARGE ENOUGH TO JUSTIFY A PERSON TAKING A RISK WHICH WILL ENDANGER THE HEALTH OF ANY HUMAN BEING DURING CONSTRUCTION OF THE MESQUITE PIPELINE PROJECT.
2.
This procedure outlines the minimum safety program to be followed during field construction as required by SF-87084. Safety is a vital part of the performance of any job, and the safety program shall not be considered as an extracurricular function. Inspectors will be expected to set the example to other inspectors and to all contractors by working safe, wearing protective equipment and enforcing safety rules.
3.
The Construction Representative is responsible for the overall coordination of the safety program; however, Supervisory Personnel (Engineers, Surveyors, Inspectors, etc.) all are key men in any accident prevention program and must participate actively in the program. These key people must acquaint all local hires with Company safety practices upon starting work with the Company. It is important that proper instructions are given for the performance of work and that any unsafe practice by Company personnel is promptly corrected. All supervisory personnel must realize that they are directly responsible for the safety of the men they supervise.
4.
The Construction Representative shall arrange periodic safety meetings to be held at least once each month and more often if special hazards exist. The meetings shall be held so that all Company personnel and contract personnel working directly for company can attend.
5.
Working close to an existing pipeline or high voltage buried powerline with heavy ditching and pipelaying equipment calls for special measures to prevent a break in the existing lines. Every opportunity must be used to keep the Contractor’s personnel aware of the importance of safety. Seriousness of a break in the line cannot be over-emphasized. See Construction Emergency Procedures. a.
The Clearing and Ditching Inspector - on each spread is responsible for checking the Contractor’s survey crew. This may be done by use of a pipe or powerline locator. The location must be checked by Company’s personnel before right-of-way or other work is to be done by Contractor’s equipment. Appropriate Contractor’s pipe-locating signs will be set over the centerline of the existing line. These signs shall be left in place until after trenching and backfilling has been completed.
b.
Danger of breaking the existing line is expected to be greatest during the following operations: 1.
Right-of-way clearing.
2.
Ripping.
3.
Blasting or drilling of rock.
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4.
Back hoe excavation for casing bores, valve boxes, or bell holes.
5.
Backfilling in soft material.
Company Inspectors shall pay close attention to all of the above operations. Any time dangerous conditions are present, the Company Inspector on the spot is responsible to see that the Contractor conducts his operations with complete safety to the existing line. In cases where the Contractor is negligent, any Company Inspector near the work has authority to shut down the operations until the hazard is rectified per SF87084 Section 18.01.
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c.
Blasting adjacent to the existing line shall be supervised very carefully by Company Inspectors. Short period delay blasting caps should be used to stagger detonations in any one string and minimize peak shock transmitted to existing line. The determination of a safe charge should include consideration of type of formation (granite, shale, lava, etc.) depth of drill hole, and proximity to existing line.
d.
At places where the new line will cross an existing line in changing position, from one side of the right-of-way to the other side, the existing line must be uncovered by hand to the point of crossing before ditching equipment approaches and machine ditching must be stopped not closer than 3 feet from each side of No. 1 line, measured at right angles.
e.
The Company Inspector shall review with the Contractor’s Foreman each day the location of block valves, access roads, and communications facilities for the location of the work during that day’s work.
6.
The Construction Engineer shall prepare a periodic safety bulletin to be distributed to all Company personnel. This publication should be brief and distributed frequently (at least monthly). It should include resumes of any accidents during the period, safety slogans and particular cautions, and safety suggestions by Company personnel, a statistical score of safety record to date, etc. Wide use should be made of safety posters.
7.
The Construction representative shall prepare a list of names, addresses and telephone numbers of the physicians, hospitals, and ambulances to be called in the event of an injury. A copy of this list and adequate first-aid material, and fire extinguishers shall be maintained in all construction vehicles and field offices. See Section 3.0 Attached.
8.
All engineers, supervisory personnel or inspectors who are in charge of activities around existing facilities which are in oil or gas service shall become familiar with established operating standards for such facilities and shall insure that operations are conducted in accordance with these established standards.
9.
Extremely hazardous conditions may exist along the right-of-way, such as dry grass or hydrocarbon spills. Engineers, inspectors, and other supervisory personnel should develop special measures to reduce such hazards, to control sources of ignition, and to ensure that the Contractor provides adequate firefighting equipment near the job. See Fire Fighting Procedure.
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10. Special emphasis must be placed on the safety program during excavation, tiein welding to existing pipeline(s), hydrostatic test, scraper runs and dewatering because of the greater activity and variety of work required at the time. The Construction Representative shall insure that personnel assignments are scheduled so as to avoid long hours and over work. He shall arrange for experienced operating personnel to instruct construction personnel and assist in operating pumps, valves, scrapers, etc. He shall also insure that all Company personnel are informed of the hazards due to the contents or pressure of the lines and equipment and that they are instructed as to the necessary precautions to be taken. 11. The Company is very interested in promoting safe practices by the contractor’s forces as required by SF-98084. However, because of the necessity of maintaining the proper contractual relationships, Company personnel should give no direct instructions to Contractor’s employees, even though such men may be working unsafely at the time. Engineers and Inspectors shall promptly discuss unsafe practices with the Contractor’s supervisory personnel and make suggestions for correction. If such suggestions are not complied with they should be brought to the attention of the Company representative. 12. The Construction Engineer is responsible for preparing and submitting accident reports to State and Company, such as GO-42 “Supervisor’s Report of Industrial Injury”, and Motor Vehicle accident reports. Contractor shall report to Company, injuries that occurred on the job site as required by SF-8708414.00. 13. All facilities of the Company shall follow procedures which will be implemented in the event of a bomb threat. See Bomb and Extortion Threats Procedure. 14. For Additional Safety and conditions please refer to the attached Exhibit I “Independent Contractor Safety Practices”. All Inspectors will be expected to observe and follow these guidelines during the course of the project. 15. No illegal or unauthorized drugs, intoxicating beverages, firearms or weapons, or persons under the influence of drugs, stimulants or alcohol are allowed on Company’s premise or work locations. 16. From time to time and without prior announcement, searches by authorized Construction Representatives may be made of anyone entering on or leaving the premises of the Company including Company employees and employees of Contractors doing business with the Company. Persons refusing to submit to searches will be denied access to Company premises.
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Appendix E
E2.0
Pipeline Manual
Construction Emergency Procedures A. General 1.
Scope This standard establishes the procedures and responsibilities for reporting pipeline accidents, fires, leaks and petroleum spills in compliance with:
2.
a.
Environmental Protection Agency, 40 CFR 110 — Discharge of Oil
b.
Railroad Commission of Texas — Hazardous Liquids Pipeline Safety Rules
c.
Materials Transportation, Department of Transportation (DOT), 49 CFR 195 — Accident Reporting
d.
Comprehensive Environmental Response Compensation & Liability Act (CERCLA) Section 16.510 — Superfund
Penalties The Federal Water Quality Control Act imposes requirements for reporting oil spills under penalty of fines up to $10,000 and/or imprisonment up to one year (33CFR153.205)
3.
Management to Local Telephone Reporting a.
4.
If an Inspector has knowledge of any discharge of oil from a pipeline facility he shall immediately notify the Company Representative of such discharge by telephone or radio. 1.
A spill which affects or threatens to affect surface waters (oceans, rivers, creeks, canals, etc.) or underground water supplies).
2.
A spill of 100 barrels or more regardless of its locations.
3.
Any spill affecting roadways.
4.
Any spill resulting in fire, explosion, death, injury, or $5000 property damage.
5.
A release of a reportable quantity of a hazardous chemical.
6.
A spill where the public or media is involved.
To Gov’t Agencies Any oil spill, or failure in the pipeline system, described in paragraph 3 shall be reported by telephone (within four (4) hours) by the Company Representative. a.
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Federal
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National Response Center, Washington D.C., U.S. Coast Guard Service 24 hours — 800-424-8802 b.
State Texas Emergency Response Center 24 hours — 512-463-7727
c.
Other In addition to the above Federal and State one call numbers, it may be advisable for good local relationships to also advise the local agency representatives responsible for on scene inspections such as the USCG, RWCB, Fish and Game Commission, or Texas Railroad Commission.
5.
Information When reporting a Discharge of Oil, or a pipeline accident, by telephone to the Company Representative the following information should be included. a.
Company Name (Include address & phone number)
b.
Location (Station number)
c.
Barrels out (If known)
d.
Nature of spill (Crude or products)
e.
Distance to nearest Water course — (If known)
f.
Status of control and containment
g.
Other significant facts known by the reporter
Report only information that has been established and verified by Company personnel at the leak site. 6.
E3.0
Because of the growing public sensitivity to any type of oil spill or pipeline accident, it is imperative that appropriate public relations be maintained at leak sites. Full cooperation should be representative. Sensitive questions should be forwarded to the proper Supervisor for answers.
Phone Directory & Emergency Call Out List Note
E4.0
Section not reproduced for this appendix.
Fire Fighting Procedure A. Natural Cover - Grass, Brush 1.
GENERAL Natural cover fires involve ordinary combustibles, but their characteristics of continual movement and usual remoteness from sources of water supply
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require an approach somewhat different from most other fires. The only control methods suitable for this type of fire consist of removing the fuel supply (firebreaks) and quenching with water. Full advantage should be taken of the services of any Federal or State Forestry officials or of County fire-fighting organizations in this type of fire since they are usually specialists who can give valuable assistance. 2.
Wind has a marked influence on the direction and speed of spread of natural cover fires. Spread will be most rapid with the wind, with less tendency to spread sideways. Fires travel uphill considerably faster than downhill. Therefore, fire fighters should never be permitted to approach a natural cover fire from the front as it is progressing up a hill. Escape may be too difficult.
3.
Attack The safest method of attack is to approach from the windward, controlling the fire along the sides working toward the head or front of the fire. In some cases the speed of the fire may be so great that the head cannot be overtaken, so that a head on approach must be made. This will usually involve some type of firebreak as discussed below. Advantage should be taken of any natural or ready made firebreaks, such as streams and roads. The top of a ridge is usually a good place to make an attempted stop. Under any of these conditions, plans should be made in advance to evacuate people and equipment should their position become hazardous.
4.
Type of Fuel Fires involving brush do not ordinarily lend themselves to control by the direct method of extinguishment of the burning material. They must almost always be controlled by surrounding the fire with firebreaks and letting the controlled fire burn out. Small grass fires can usually be approached closely enough to actually extinguish the perimeter fire with water, beaters, shovels, wet sacks, etc. Larger grass fires must be handled with firebreaks.
5.
Equipment Available The attack will, to some extent, have to be adapted to the equipment available. Grass and brush, being ordinary combustibles, can be controlled with water, if it is available in sufficient quantity along with means to get it to the burning area. Special nozzles to conserve water are available from equipment suppliers. In the absence of sufficient water, which is usually the case, axes, shovels, picks, hoes, etc. are usually the most effective. Motorized earth moving equipment, if available, can usually be used to good advantage if the terrain permits.
6.
Firebreaks Where adequate water supply and equipment are lacking to the extent that direct extinguishment is impractical, construction of firebreaks is generally the only effective method of control. They involve removing all combustible material from a trip across the path of the fire. This can be done by cutting out any brush and discarding it away from the fire and then digging up the ground, and turning dirt over toward the fire. Bulldozers can be particularly helpful in
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preparing a firebreak through brush. A disc harrow can be effective in preparing a firebreak in grass. A road grader might also be used. The firebreak should be widened as time allows, making certain there is always time to evacuate all people and equipment if necessary. Any available water, from back pack water cans or hoses from fire trucks, can be used to wet the area on both sides of the break; but it is most effective while patrolling the fire line for extinguishment of any small fires that might be started by flames or burning brands that get across the firebreak. In some cases the firebreak can be made by controlled burning of the combustible material in the path of the main fire. These “backfires” can be dangerous and should normally be undertaken only under the supervision of someone experienced in this type of work. 7.
Use of Water and Chemicals Since the amount of water available for fighting natural cover fires is generally limited by the capacity of truck tanks used for hauling water to the scene of the fire, it is important to make it go as far as possible. Chemical wetting agents have been developed which, when added to water in low concentration (0.3% to 2%), decrease surface tension, permitting the water to penetrate combustible materials more readily thus reducing tendency to run off and be largely wasted. Water treated with such a “wetting agent” is particularly effective in direct quenching of grass fire, as well as fires involving such hard-to-wet materials as cotton, hay, overstuffed furniture, etc. It has also been used to establish a barrier strip and position from which backfires can be set. By wetting a strip 10 to 15 feet wide with “wet water,” as from two small hose streams directed from a moving fire truck, a backfire can be started almost immediately, with this strip as a barrier behind it. Although the line should be continuously patrolled, this wetted area should prevent a backfire from getting out of control even under adverse wind conditions. Wetting agents are an added cost and their effective use quite limited, so that they are ordinarily used only by public fire departments, usually county and forestry that have frequent calls to fight fires of the type discussed in this section. Use of wetting agents within the Company is justified only in special and unusual cases where many grass and similar fires are expected. Wetting agents should not be used along with any type of foam, as it tends to break up the bubbles. “Wet water” is not considered of any particular value over plain water in the control of fires.
8.
Flame Retardant Chemicals There are on the market certain other chemicals such as those containing borax which act as flame retardants. Ordinarily, use of these chemical cannot be economically justified, except under special conditions.
9.
Grass fires are the most significant fire threat during construction of onshore pipelines. A section of the Corporate Fire Protection Manual on fighting grass fires is attached and should be used to guide Company personnel in dealing with grass fires. The following priorities should be used to direct manpower during a fire:
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E5.0
Pipeline Manual
a.
Protection and safety of personnel.
b.
Protection of dwellings, buildings, and livestock.
c.
Protection of crops and grasslands.
d.
Notify Company Representative or Chief Inspector as soon as possible.
Bomb and Extortion Threats A. Bomb and Extortion Threats There will be occasions when the Company may be faced with various types of emergency situations which are security related, but cannot be handled by normal security procedures. It is necessary to develop special security plans to handle situations of this nature. 1.
Bomb Threats The following procedures should be implemented in the event of a bomb threat. The primary goal in dealing with bomb threats will be the maximum safety for personnel and facilities. a.
E6.0
1.
Record time the call was received.
2.
Exact wording (activate recorder if available).
Independent Contractors Safety Practices Guide Note
E7.0
The person receiving the call should remain calm and deal with the caller in a confident manner and should use a prepared outline to record pertinent data (Figure 1 attached).
Section not reproduced for this appendix.
Inspection Procedures E7.1
Inspection General Guidelines — All Crafts — Procedure No. 1 A. Responsibilities This procedure outlines the general duties and responsibilities of all Pipeline Inspectors during the various operations performed by the pipeline spread. For detailed job descriptions refer to the specific job inspection title. B. Authority The Inspector has the authority to enforce the technical provisions of the specifications. The Inspector is authorized to stop work, however discretion should be applied and only when work being performed is in conflict with applicable
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specifications and procedures should the work be stopped. The Lead Inspector or Construction Representative should be notified after exercising this option. C. Requirements of a Pipeline Inspector 1.
General Requirements Pipeline Inspectors will:
2.
a.
Observe the work of individual craftsmen to ensure that they are qualified for the work that they are performing. Inform the Construction Representative of any individuals whose work is not acceptable.
b.
Ensure that the Contractor(s) and Subcontractor(s) fulfill each requirement in complete accordance with the specifications.
c.
Inspect the Contractor’s construction operations to ensure that materials and equipment used and performance of work are in accordance with specifications, applicable codes, and accepted company and trade practices. Ensure that the final product is acceptable in regard to workmanship and suitability for intended use.
Essential Requirements a.
The Pipeline Inspector’s function is to represent Chevron Pipe Line Company, in overseeing the quality of the pipeline construction. It is his responsibility to judge the quality of construction in relation to the written specifications, drawings and instructions. Although he must strive for the highest quality, he must not delay completion and delivery of the pipeline without proper cause. All of the following are essentials which require thorough study and careful application. They cannot be treated lightly by the Inspector who wishes to do his job conscientiously.
b.
Physical Condition The pipeline Inspector’s physical condition must be sufficiently good to permit him to fulfill his duties. Proper inspection requires examination before, during, and after construction. He must be able to climb in and out of trenches, around and under the pipe.
c.
Vision Good vision is vital to a Pipeline Inspector, who must look closely at the welds, radiographic film, drawings, and other construction activity as necessary. Corrective aids such as glasses shall be used, if prescribed, during the inspection process.
d.
Knowledge of Specifications Since the Inspector must be familiar with specifications that apply to the pipeline construction, he must read and thoroughly understand these specifications. When decisions must be made, his knowledge of the standards
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and specifications must be comprehensive. A good defense against poor workmanship and aggressive Contractor Supervisors, is to know the job specifications better than they do, and to be able to quote chapter and verse. e.
Attitude The importance of a Pipeline Inspector’s attitude cannot be over-emphasized. It determines the degree of his success or failure. For success, he is very much dependent upon the cooperation of the field, office and Contractor personnel, and he must command their respect in order to obtain it. His attitude plays an important part in gaining this respect. A definite policy of inspection procedures and standards should be adopted and followed faithfully. A Pipeline Inspector can neither be stubborn nor swayed by persuasive arguments and, under no circumstances shall he seek favor or incur obligation through his decisions. The most difficult period for a Pipeline Inspector is during his first few days on any new pipeline project. During that time, those with whom he must deal will be testing him for weakness in policy. If he is well informed, fair and consistent and follows the intent of the Contract specifications he will earn respect and cooperation.
3.
Desirable Characteristics a.
Experience and training are highly desirable, and Inspectors lacking any of them should remedy the deficiency through study and observation. The most important of these desirable characteristics follow:
b.
Pipeline Experience Without question, actual pipeline experience is the most desirable characteristic of a pipeline Inspector . It effectively broadens his knowledge, and gives his opinion more authority if he is requested to offer constructive criticism when rejecting poor quality workmanship.
c.
Education and Training The Pipeline Inspector with formal training in basic engineering and metallurgy is exceedingly fortunate, although many Inspectors lack this formality and manage to become excellent Inspectors. The more knowledge and experience an Inspector possesses, the more he can contribute toward making intelligent decisions. He will be more aware of critical points, and better able to emphasize quality control in important areas. It is therefore important that the Inspector continue to study and learn all aspects of his job whenever the opportunity presents itself. You will not be criticized for studying specifications on the job during slack moments, nor for asking questions concerning welding, metallurgy and engineering.
d.
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Knowledge of Welding
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A Pipeline Welding Inspector must have enough knowledge of the various welding processes used for pipeline welding to know what defects are most likely to occur, and where he should look for them. He should be familiar with all the procedures and specifications that apply, as well as with the characteristic weaknesses of the welders in terms of following procedure details. The Inspector should know the essential variables of the particular welding procedure, and should monitor these variables during the pipeline welding operation. e.
Inspection Experience The attitude and point of view of a good Pipeline Inspector is acquired only through inspection experience. Any of this experience will be extremely helpful in the inspection of a pipeline, since a good Inspector has developed a distinct way of thinking and working. Those without such experience should observe the behavior of experienced Inspectors.
f.
Records A Pipeline Inspector must be able to maintain adequate records, which includes writing clear and concise reports so that his superiors will have no difficulty understanding his meaning. Also, he, upon re-reading, must be able to recall the reasons for his decisions after they are several months old. The inspection report should be concise, yet complete enough to be understood by a reader who may be unfamiliar with pipeline construction. In preparing the record, it must be kept in mind that facts that are well known at the time of writing must be included, since they may not be remembered so definitely later. Good records not only protect the Inspector, but they also help adhere to a policy of uniform standards. Remember, your records could one day be required to stand up in a court of law.
D. As Built Drawings Alignment drawings will be supplied to Inspectors and shall be used for markups of construction progress. A master set of alignment drawings will be kept by the Chevron Pipe Line Company engineer who will consolidate data received from inspectors. E. Material Handling Pipe, fittings and other materials shall be loaded/unloaded with adequately sized equipment. Hook ends shall be rubber or brass coated to prevent damage to bevels or pipe wall. Matched chokers and tag lines shall also be used. Slings shall be constructed in such a manner as to prevent damage to pipe or coatings. Chains shall not be used to handle pipe. When transporting pipe, fittings and other materials, boomers, tie-downs or equivalent shall always be used. A company approved bedding shall be used to underlay the bottom tier. Use cradles, padding or other strapping as necessary to protect materials form shifting loads during transportation. Support pipe to prevent deformation or damage to coating.
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F. Work Relations 1.
The Inspector shall understand that he must not interfere with the Contractor’s methods of performing work. Such interference could release the Contractor from his responsibility under the Contract. Action by the Inspector is limited to the rejection or acceptance of the work as it is completed. Should the Contractor’s methods become obviously unsafe, inadequate, or fail to comply with established construction practices, the Inspector will point out to the Contractor’s Representative the results which may be expected with the continued use of such unsatisfactory practices. If the Contractor persists in unsatisfactory practices, the matter will be promptly brought to the attention of Construction Representative or Lead Inspector for further action.
2.
The Inspector shall always do business with the Contractor’s supervisor on the job, and shall not issue any work directions to the Contractor’s workmen. At no time shall an Inspector take action which could be interpreted as providing supervision or as giving direction to the Contractor workmen.
3.
The Inspector shall cooperate at all times with the Contractor to expedite progress. Inspectors shall look ahead and be alert in order to catch error and questionable practices in time to avoid future rejection or slowdown of work, to observe the Contractor’s methods of operating equipment from a safety standpoint, and to assist in correction of unsafe practices. The Inspector shall maintain friendly relations with the Contractor at all times, and shall cooperate with the Contractor in every way, short of compromising the construction schedule or quality of the work required by the plans, specifications, and contract.
G. Providing Assistance To Contractor 1.
Explaining the procedure for obtaining and receiving permanent pipeline materials furnished by the owner.
2.
Advising as to standards of safety practices by Company.
3.
Interpreting plans and specifications.
H. Favoritism And Discrimination Actions of the Inspector shall never indicate favoritism toward nor discrimination against the Contractor or his workman. I. Disagreements Any dispute or disagreement between the Contractor and the Inspector shall be reported immediately to the Construction Representative or Lead Inspector for such action as may be required, and shall be documented on the Daily Inspection Report. J. Unusual Events
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The Inspector shall be particularly vigilant in observing any action by any person or any activity that is out of the ordinary pertaining to pipeline construction practice. K. Daily Inspection Reports 1.
The progress of individual crew operations shall be reported daily to the Lead Inspector on the daily progress report form.
2.
Progress reporting shall be according to station numbers and will include all extra work performed by Contractor, This report will be used as the direct control over Contractor’s compensation for extra work, so it is imperative that progress reported be as exact as possible.
3.
The Daily Inspection shall also include the following: a.
Date
b.
Project Name
c.
Daily weather conditions including changes in weather patterns.
d.
Contractors field force 1.
Name of Contractors and Subcontractors on site.
2.
Number of craftsmen on site and job descriptions.
e.
Visitors on site (names if possible).
f.
Identification and number of major pieces of motorized equipment.
g.
Status of all work in progress. Note location of the work and which Contractor and Subcontractor are performing it.
h.
Record in detail any work performed or materials used that does not correspond with construction drawings or specifications.
i.
Note all unforeseen conditions encountered that hampered construction progress (weather, fog, bog, etc).
j.
Record the content of all substantive conversation with Contractors, visitors or landowners. Record names.
k.
Record all field errors made by any party on site.
l.
All daily reports shall be considered as Chevron Pipe Line Company property and shall be given to the Lead Inspector daily, who will maintain a file on them.
L. Code of Ethics Be aware at all times that you are representing Chevron Pipe Line Company and that your actions, attitudes and integrity will be a direct reflection upon the company. The acceptance of goods, services, or gifts from the Contractor or his representative will be grounds for immediate termination.
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E7.2
Pipeline Manual
Utility Inspector — Procedure No. 2 A. Job Requirements The Utility Inspector will be under the direct supervision of the Lead Inspector. The Utility Inspector may be required to assist the Lead Inspector in all of his duties and shall be in charge of the inspection group when the Lead Inspector is absent. The Utility Inspector may also be required to perform the duties of his Company’s Construction Representative as required by paragraphs 1.0 and 3.1 of SF-87094. He will also be responsible for but not limited to the following duties. B. Responsibilities Assure that the pipeline Contractor(s) and Subcontractor(s) fulfill each requirement in complete accor-dance with the Contract documents. 1.
To be thoroughly familiar and ensure compliance with all of the contraction contract specifications consisting of the following: a.
Alignment Sheets
b.
Construction Drawings
c.
Construction Line List
d.
Permit Drawings
e.
X-Ray Specifications SR-87104
f.
Pipe Unloading Specification
g.
D.O.T Part 192
h.
API 1104 — Applicable Edition
i.
Texas Railroad Commission Part 49 - CFR - 195
j.
Welding Procedure and Qualification Tests
k.
ANSI - B 31.4
l.
ASNI SNT-TC-1A
m. State of Texas Health Department Radiation Safety Requirements Part 31
November 1988
2.
Coordinate and schedule all activities of the radiographers. Read and interpret radiograph films, audit radiographer performance, review all X-Rays and sign off “shooter” sheets daily. Enforce and document the 100% radiographic requirement for all welds.
3.
In the absence of the Lead Inspector, approve Craft Inspector’s expense sheets, and all daily, weekly or monthly construction reports.
4.
To cooperate with the pipeline contractor’s personnel, and to immediately report comments or requests to the Lead Inspector.
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5.
Perform other functions as directed by the Lead Inspector.
C. Radiography 1.
Each morning, review the previous day’s X-Ray film. Any welds which do not meet project specifications acceptance requirements will be repaired or cut out. Ensure that all welds that are to be cut out will be marked by the Radiographer on the pipe. The weld location will be entered in the daily welding record. All repair welds shall be X-Rayed.
2.
Notify radiographic Contractor when welds are ready for inspection. Coordinate between Pipeline Contractor, Radiographer and As Built Surveyor to avoid lost time for either Company, Contractor, Radiographer, or Surveyor.
3.
Review every X-Ray film and direct Contractor to repair defects. With regard to reading radiography the general consensus is that it is preferable to interpret the radiographs dry; however, for the lesser restrictive defects allowed by API 1104 it is acceptable to read the radiographs wet. a.
Witness the penetrameter shimming (thickness and material makeup).
b.
Observe that penetrameters are proper (identifiable by size), hole dimensions are correct, “wipe” the inside of the penny holes with a toothpick or other non-metallic device to check for presence of lead).
c.
Observe film archivability test.
d.
Observe film life factors (unclean water, chemical temps.).
e.
Ensure that radiographs are not substituted which do not represent the weld which was to be examined.
f.
Observe as many welds being radiographed as possible [(verify that the proper weld designation number appears on the radiograph; each weld has some unique surface feature (finger print) that can be correlated with the radiographic image)].
g.
Maintain film quality throughout the job duration.
4.
Witness all the procedure and technician testing and determine the acceptance of the technicians and the procedures.
5.
Obtain and file all radiographic procedures and technicians certification papers.
6.
Enforce weld joint identification.
D. Hydrotesting
Chevron Corporation
1.
Witness and verify hydrostatic testing per SF 87025.
2.
Check to ensure that fill pumps are of sufficient capacity to fill the pipeline on schedule.
3.
Verify the calibration of recorders with a dead weight tester. Check that recorders have the correct charts and that recording pens are operable.
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4.
Ensure that the Contractor has arranged for appropriate records of the test, of dead weight readings, and failure reports.
5.
Scrapers (pigs) and spheres inserted in the line should be number, recorded and identified, and logged in and out of the pipeline.
6.
Where the pipe coating is broken to install a temperature probe for hydrotesting, ensure that the coating is completely repaired.
7.
Check to see that flanges are left uncovered during the hydrotest. Valves should be serviced prior to the test. If lock-o-rings are present in the test section, the blind should be removed while the line is under pressure to assure that the plug is properly installed.
8.
Where temporary drain lines are installed, precautions will be taken to see that these lines are anchored and properly designed to withstand pressures and velocities anticipated, and removed after hydrotest.
9.
Temporary manifolds to be used for air or gas service are not to be placed in service without prior approval by the Construction Representative.
10. Caution should always be exercised when air or gas is pressurized in piping. With air/gas in lines serious injuries may occur when servicing valves, cracking flanges, or operating new piping unless caution is exercised. E. Documentation and Daily Reports
E7.3
1.
Record the number of welds found defective per welder. Notify Contractor foreman if a welder has a high rejection rate.
2.
Maintain a record of each Radiographer’s (or radiographer X-Rayed), number of acceptable radiographs, number of reshots, and number of miscalls.
3.
Insure that radiographers maintain neat, detailed and accurate “shooter” sheets. Sign shooter sheets off daily to “certify” that data is accurate and complete and that technicians have worked the hours shown. Forward to Lead Inspector.
4.
Maintain detailed records of Radiographic Contractors performance. Payment for services will be based on shooter sheets and the film counts from those sheets. Remember — the Contractor will not be paid for reshots or in inaccurate or incomplete records. Your records will be used in this accounting for payment.
Front End Inspector — Procedure No. 3 A. Job Requirements The Front End Inspector shall be under the direct supervision of the Lead Inspector. He will be responsible for but not limited to the following duties:
November 1988
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B. Responsibilities
E7.4
1.
To make any field decisions requiring interpretation of Specifications after clearing same with the Lead Inspector. Any change or deviation to a specification or the contract requires prior approval by Company Construction Representative.
2.
To determine and report quantity of completed work daily.
3.
To ensure that Contractor’s personnel and equipment comply with safety precautions and all restrictions and conditions listed on the line list.
4.
Contact Landowners immediately prior to clearing operations and notify of impending activity.
5.
Assist Contractor in the location of exclusion fencing, temporary gates, etc. All existing fences must be replaced. Construction of all temporary fences will be 4-strand, 12-1/2 gauge barbed wire fence with treated wooded posts. Posts shall be set 2’6" below natural grade and shall extend 5’0" above finished grade. The fence shall follow the land contours so that the lowest wire is a maximum of 16" above grade. In addition, all fences shall be constructed to meet the requirements of the “Standard Specification for Construction of Highways, Streets and Bridges, 1982" from the Texas State Dept. of Highways and Public Transportation.
6.
Assist/supplement Clearing Inspector in plant protection (See Clearing Inspector Section 4.0).
7.
Photograph private roads used for access to the right-of-way. Labels with location, direction and R.O.W station.
8.
Coordinate with and monitor survey crew activities.
9.
Submit daily report to Lead Inspector.
Daylight Inspector — Procedure No. 4 A. Job Requirements The Daylight Inspector shall be under the direct supervision of the Lead Inspector. He will be responsible for but not limited to the following duties: B. Responsibilities
Chevron Corporation
1.
To make any field decisions requiring interpretation of Specifications after clearing same with the Lead Inspector. Any change or deviation to a specification or the contract requires prior approval by Company Construction Representative.
2.
To ensure that Contractor’s personnel and equipment comply with safety precautions and all restrictions and conditions listed of the line list.
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E7.5
Pipeline Manual
3.
Witness the identification and locating of all foreign, pipeline and utility crossings. Look for markers showing existing utilities and mark up field prints. Ensure (48) hours notification to Texas Excavation Safety Service (800-3448377), and all owners individually, when substructures are to be exposed during excavation or crossed by a new line. See also, Utilities section of the Mesquite Pipeline Telephone List.
4.
Verify that restrictions and/or special requests made by landowners as noted on the line list are followed.
5.
Assist Contractor in location, staking and excavation of pipelines and pipeline crossings within right-of-way. Be present at all times when excavation is being done near the active Chevron pipeline.
6.
Witness the excavation of all live pipelines. Expose nearest active pipeline every 500 ft., flagging 5 feet from the active pipeline to establish the nonencroachment boundary. Place stakes and flags on this boundary every 200 ft. A Company Inspector must be present at all work exposing active pipelines.
7.
Expose top half of pipe at all horizontal PI’s greater than 3 degrees, all foreign pipeline crossings and at a maximum spacing of 1/4 mile. Expose by hand unless pipeline is greater than 2 ft. deep. Company Agent or Inspector must be present during exposure.
8.
Work in conjunction with survey crew(s). To ensure all foreign pipeline crossings are correctly located and numbered.
9.
Submit daily reports to the Lead Inspector.
Clearing Inspector — Procedure No. 5 A. Job Requirements The Clearing Inspector will be under the direct supervision of the Lead Inspector. He will be responsible for, but no limited to the following. B. Responsibilities 1.
To make any field decisions requiring interpretation of Specifications after clearing same with the Lead Inspector. Any change or deviation to a specification or the contract requires prior approval by Company Construction Representative.
2.
To ensure that Contractor’s personnel and equipment comply with safety precautions and all restrictions and conditions listed on the line list.
C. Prior To Clearing
November 1988
1.
The Inspector is to familiarize himself with the route location and boundaries of the pipeline right-of-way.
2.
He should read all Federal, State and County permit conditions and ensure that the conditions of the permits, and special requirements are carried out.
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3.
Ensure that the contractor has documented the undisturbed right-of-way conditions and photographed same as required by SF-87086.
D. Plant Protection 1.
Create a color code system if needed and flag the following: a.
Trees and shrubs which require preservation and protective snow fencing.
b.
Trees to be cut down. All oak trees and trees larger than 2" in diameter shall not be disturbed without prior written approval from Company.
c.
Plants to be transplanted, if any.
d.
Vegetation to be avoided.
e.
If required, ensure that all plants marked for transplanting are carefully potted in appropriately sized plastic containers, using soil from the same area.
f.
Check to make sure that transplanted vegetation is tended and watered on a regular basis until the time arrives to replant.
E. Clearing Operations
Chevron Corporation
1.
Ditch centerline stakes, right-of-way boundary stakes, and all survey monuments are to be preserved. In the event that Contractor’s activities damage or destroy any survey stakes, the Construction Representative is to be advised. Permanent monuments or bench marks shall be replaced by a Registered Land Surveyor acting under Company’s instructions per SF-87086.
2.
During clearing operations, check to see that the right-of-way width cleared is as specified per SF-87086.
3.
Ensure that all necessary grading is carried out at road, stream, and river crossings and that grading remains on right-of-way.
4.
Line pipe shall not be used for temporary flumes, culverts, etc.
5.
Assure that access to the right-of-way is limited to intersections, roads and access roads or per SF-87086.
6.
Ensure that the right-of-way is completely cleared of grass and small brush, mix these with topsoil and place to the edge of right-of-way.
7.
Trees, brush, stumps or other material shall not be pushed from the construction right-of-way.
8.
Contractor shall dispose of merchantable timer per attachment B, Landowner Line List.
9.
Non-merchantable material shall be properly disposed of offsite. Contractor may chip unmerchantable timber, brush, stumps, etc. and stockpile along rightof-way for use in restoration. Check to make sure all stumps are grubbed from ditchline.
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10. Ensure the removal of any and all man made junk and debris off site. 11. Herbicides are not to be used along pipeline corridor. 12. Off site disposable of trash must be done only at Company approved disposal sites. 13. Monitor and maintain dust control, containment of sidecast materials and proper excavation of paved roads if permitted. F. Reports And Documentation 1.
Note any off right-of-way damage or land used by Contractor, and report to Lead Inspector.
2.
Prepare notification to affected landowner 96 hours prior to the start of each stage of construction (staking, clearing) and give to Lead Inspector.
3.
E7.6
a.
Description of vehicles intending to use roads and proposed times of entry and departure.
b.
Description of construction schedule across property when activity will occur within 1000 feet of any residence.
c.
Description of road closures on property.
d.
Description of any probable hazard or other unsafe condition.
e.
Description of schedule or interruption of telephone, electrical power, water or other utility service.
f.
Description of schedule for cutting any fences or similar barriers.
Report right-of-way, grading and clearing progress on your Daily Report. Turn forms in daily to the Lead Inspector.
String and Bending Inspector — Procedure No. 6 A. Job Requirements The Pipe Stringing Inspector will be under the direct supervision of the Lead Inspector. He will be responsible for, but not limited to the following. B. Responsibilities
November 1988
1.
To ensure that survey stakes and right-of-way markers are left intact.
2.
Report in detail, to the Lead Inspector and in your daily reports, any right-ofway damages to private property and roads, straying animals, etc.
3.
Assure that pipe or coatings are not damaged during stringing or unloading operations.
4.
Insure that all fence gaps are closed when completing stringing operations or at the end of the day.
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5.
Report and document any shipping damage to pipe or coatings. Mark clearly all damage for repairs or rejection.
6.
Ensure that Company’s safety requirements are complied with.
C. Stringing 1.
Assure that Contractor’s stringing crews have the proper machinery and equipment to complete the work in full accordance with the contract documents.
2.
Confirm the condition, number and identification of the pipe when received by the Contractor at the construction right-of-way. Note any damage and report the damage per joint number and diameter as required.
3.
Pipe must not be allowed to be dropped or strike objects. Lifting hooks must be rubber coated or designed to ensure no bevel, pipe or coating damage occurs. Proper slings or belts shall be used to prevent damage to coating.
4.
Assure proper laydown and cushioning of pipe on the right-of-way.
5.
Assure that Contractor strings the pipe in such a manner as to leave gaps across the right-of-way to allow passage of farm equipment and livestock.
6.
Check to ensure that the Contractor has staked out where changes in wall thickness and coating are to take place.
7.
Check to see that the correct wall thickness of pipe is being used at the correct location. Note on a copy of the alignment sheet, by stationing where changes in wall thickness actually occur.
8.
Documentation of each joint or partial joint should note pipe number, diameter, wall thickness and pre-sent location. Insist that the Contractor or As Built Surveyor transfers all identification to any cut off pieces of pipe.
9.
Particular notice must be taken to assure that short pieces and “pups” are correctly identified using a color coded paint stripe and moved ahead and uniformly distributed in the line construction.
D. Cold Bending Inspection 1.
Chevron Corporation
Witness and audit the bending operation to insure the following are correct: a.
Longitudinal seams are bent only on or near their neutral axis.
b.
Longitudinal seams are rotated 30 degrees offset from each other and are placed along the top of the pipeline.
c.
No wrinkles or miter bends are permitted.
d.
Maximum out of roundness is less than 4% of the original diameter.
e.
Maximum allowable bend (degrees) per SF 87-86 is not exceeded.
f.
Pipe diameter is not reduced by more than 2-1/2% of the nominal diameter.
g.
Cutting and welding torches are not used without prior Company approval.
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E7.7
Pipeline Manual
h.
No field bends (only shop bends) allowed within 200 ft. of a mainline valve.
i.
All cold bends have been checked (before welding) with a sizing plate. Verify sizing plates are of the Company approved OD with no excessive wear or distortion. Witness sizing of cold bends whenever possible, but no less than 25% of the total cold bends.
j.
Submit written daily report to Lead Inspector.
Trenching Inspector — Procedure No. 7 A. Job Responsibilities The Trenching Inspector will be under the direct supervision of the Lead Inspector. He will be responsible for, but not limited to the following. B. Responsibilities 1.
Determine from the construction line sheet, survey stakes, and or alignment drawings when top soil has to be conserved or extra trench depth is required.
2.
Ensure that the Contractor uncovers all telephone lines, electrical cables, and underground pipelines prior to ditching, and that all are clearly marked.
3.
Ensure that Contractor personnel are familiar with safe blasting techniques and applicable state law requirements for rock trench.
C. Trenching
November 1988
1.
The job at all times when trenching is being done, to insure that Contractor does not damage or break any lines.
2.
Verify that the ditch line staked by the Contractor is positioned correctly in regard to the easement and in accord with the alignment sheets.
3.
Ensure that the survey stakes are preserved and call for restaking where survey stakes are damaged or destroyed.
4.
Check that excavations are made true to line and grade. Discourage ditches wider or deeper than necessary to lay pipe. Unstable soil shall be removed as required, but not to exceed a depth of two feet below trench bottom.
5.
Ensure that minimum depth of cover requirements have been provided for and that the ditch is wide enough to allow lowering in of the pipe without injuring the pipe coating per SF 87101.
6.
Ensure that the trench is graded and bedded so that it will afford uniform bearing to the pipe throughout its entire length. A bedding of 3 or more inches of loose backfill or sand shall be used. Rocks larger than 1/4" in diameter and stockpiled topsoil shall not be used.
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7.
Trenches should be dewatered and kept reasonably dry. Insist on a firm trench floor.
8.
Ensure that the bottom of the ditch is free of debris or any foreign material, welding rods, boards, etc., which damage protective coatings.
9.
Open ditches within 20 feet of paved roads may required flagmen and/or signs to alert and control traffic.
10. Ensure (48) hour notification to Texas Excavation Safety Service (800) 3448377 when any substructures are to be exposed during excavation. Also see Utilities section of the Mesquite Pipeline Project Telephone Book. 11. When underground structures not shown on alignment sheets are located, ensure Contractor marks the position of the structure by staking. Mark location and nature of object on alignment sheet. 12. Be present during the uncovering of known underground structures and ensure advance notification of owners of foreign structures of work being performed adjacent to their structure. 13. If damage should occur to underground structures notify the Lead Inspector and document in daily report. Take photographs, if possible. Ensure that the Contractor submits a written report detailing damage and repairs made. The owner of the damaged structure will be contacted by Company’s Land Agent and repairs will be made by Contractor to the owner’s satisfaction. 14. Ensure proper precautions are taken where blasting is necessary. Any loose rock scattered over the right-of-way or adjacent lands is to be cleared by Contractor to the satisfaction of the landowners. 15. Ensure that hand excavation is done at all pipeline crossings and in locations where the use of trenching equipment may result in unnecessary damage or injury to property per SF 87086. 16. Ensure that minimum clearance of 12" be maintained between any pipeline crossing. 17. Ensure shoring and bracing of excavation are safely constructed. Follow Chevron Safety in Design guidelines for shoring and proper angles of repose for unshored ditches. Also see Safety in Designs Manual. 18. Submit daily report to Lead Inspector.
E7.8
Bore Inspector — Procedure No. 8 A. Job Requirements The Bore Inspector will be under the direct supervision of the Lead Inspector. He will be responsible for, but not limited to the following responsibilities.
Chevron Corporation
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B. Responsibilities 1.
To make any field decisions requiring interpretation of specifications after clearing same with the Lead Inspector. Any change or deviation to a specification or the contract requires prior approval by Company Construction Representative.
2.
To determine quantities of completed work.
3.
To perform the duties of Welding Inspector on all welding on carrier pipe installed in cased crossings.
4.
To perform the duties of Welding Inspector on all welding on pipe installed in slick bores.
5.
Ensure that longitudinal seams are rotated 30 degree offset from each other along top of pipeline when pipe is installed in casing or slick bore.
6.
To carefully review and become knowledgeable on the duties and responsibilities of the Welding Inspector.
7.
To carefully review and become knowledgeable on the duties and responsibilities of the Coating Inspector, pertaining to installation of shrink sleeves and repair to damaged coating.
8.
Ensure that all crossings are executed in accordance to specifications and drawings.
9.
On cased crossings check to see that there are no long spans between the end of the casing and where the pipe rests in the bottom of the trench. If there is a long span, then earth filled sacks should be placed under the span section at intervals for proper support of pipe.
10. Ensure that proper depth is maintained in accordance to permits and construction drawings. 11. Submit daily report to Lead Inspector.
E7.9
Welding Inspector — Procedure No. 9 A. Job Requirements The Welding Inspector will be under the direct supervision of the Lead Inspector. He will be responsible for, but not limited to the following. B. Responsibilities 1.
Perform and document procedure and qualification tests of welders and welding procedures. To requirements of API-1104.
2.
He will examine each pipe before welding and check that: a.
November 1988
The pipe is in good condition and free from defects.
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b.
Cold bends have been made in the proper manner, without damage to the pipe.
c.
Pipe bevels are properly cleaned, free of moisture, grease or other foreign matter and without dents or gouges.
d.
Each joint of pipe has been properly swabbed before it is placed in the line.
e.
All internal pipe identification has been transferred to the outside by the As Built Surveyor.
3.
Ensure that the Contractor provides an adequate number of skids, of the right type and properly placed to keep the pipe secure.
4.
Verify proper alignment of joints, placement of longitudinal seams and line up clamp fit. Longitudinal seams are rotated 30 degrees offset from each other and are placed along the top of the pipeline.
5.
Assure that all dirt, sand, rocks and other debris is removed prior to lineup.
6.
Verify welder qualification(s).
7.
Verify that all welding is in strict accordance with qualified and approved procedures.
8.
Verify proper application of welding procedures and that good welding practice is followed. Ensure the following:
9.
a.
Fit up is as detailed in the procedure. Root gap and hi/low are within acceptable tolerances.
b.
Preheat/postheat is maintained (if required).
c.
Welding passes (stringer, hot, etc.) are performed as specified.
d.
Bevels/welds are power tool cleaned before successive passes.
e.
Starts and stops, porosity or high points in the bead are ground.
f.
Maximum/minimum interpass times are observed.
g.
Stringer beads are not left overnight without hot pass.
h.
Hot pass is left clean and ready for successive passes.
i.
Check welding machines periodically to verify current/voltage settings. Assure that machines, grounds, and leads are maintained properly.
j.
Proper storage and handling of consumables.
k.
It is the primary responsibility of the Welding Inspector to visually inspect all welds and have all surface defects repaired prior to X-Raying.
Verify/authorize repair of defects. Do not authorize repair of cracks (repair of cracks shall not be permitted).
10. Verify proper identification of each welder’s work.
Chevron Corporation
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11. Monitor weather conditions and halt welding, if weather will adversely affect the quality of the weld, until conditions are satisfactory or the Contractor has taken adequate measures to protect the work. 12. Ensure removal of all welding rod stubs, grinder discs, etc. from the trench and right-of-way. 13. Confirm that Contractor uses night caps and covers pipe ends at the end of shift or when work is suspended. 14. To ensure that all short sections of piping (6 ft and longer) are correctly identified and are carried forward to be incorporated into the pipeline. Verify that the Contractor maintains accurate records of the identity of each joint or partial joint (pipe number, diameter, pipe grade, specification grade and location). Verify transfer when mill markings are damaged or cut off. Lengths shorter than 6 feet are to be used for weld cut outs (pups). C. Daily Reports And Documentation 1.
Keep notes on welder performance and report to the Lead Inspector if any welder consistently performs poor work.
2.
Be prepared to interpret radiographic film or witness other NDE tests, as required, in absence of Utility Inspector .
D. Reference Manual 1.
E7.10
Familiarize himself with the GUIDE TO WELD INSPECTION, attached.
Tie-in Inspector — Procedure No. 10 A. Job Requirements The Tie-In Inspector will be under the direct supervision of the Lead Inspector. He will be responsible for, but not limited to the following: B. Responsibilities
November 1988
1.
To make any field decisions requiring interpretation of Specifications after clearing same with the Lead Inspector. Any change or deviation to a specification or the contract requires prior approval by Company Construction Representative.
2.
To determine quantities of completed work.
3.
Ensure that all short sections of pipe which are longer than the minimum length specified are correctly identified and carried ahead to be incorporated into the pipeline.
4.
Inspect the line-up before welding begins and the welding of tie-in welds. Read X-Rays (if not done by the Utility Inspector) of such welds and reject same if the welds do not meet the project requirements.
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E7.11
Appendix E
5.
To carefully review and become knowledgeable on the duties and responsibilities of the Welding Inspector, and to apply all requirements pertaining to welding inspection to this job.
6.
To carefully review and become knowledgeable on the duties and responsibilities of the Coating Inspector, pertaining to installation of shrink sleeves and repair to damaged coating.
7.
Submit daily reports to the Lead Inspector.
Coating Inspector — Procedure No. 11 A. Job Requirements The Coating Inspector will be under the direct supervision of the Lead Inspector. He will be responsible for, but not limited to the following: B. Responsibilities 1.
Ensure that pipe is strung or stacked so as to prevent damage to coatings by rocks, equipment, etc.
2.
Ensure proper padding while pipe is resting on skids.
3.
Ensure that proper field coating is used in accordance with specifications. PL110 “Field Joint Corrosion Coatings and Corrosion Coating Repairs”.
4.
Verify twice daily that the jeeper is calibrated and proper voltage settings, battery charge, correct speed and grounding of holiday detector.
5.
Monitor mixing of epoxy components. Verify proper surface preparation before application of patch stick or shrink sleeve. Specification PL 110 Section 3 Field Joint Corrosion Coating and Corrosion Coating Repairs.
6.
Verify that all damaged areas in coating are properly repaired.
7.
Do not allow coating repairs in weather conditions which are adverse to proper curing or adhesion of patching materials.
8.
Record total footage of pipe jeeped and coating repaired daily.
9.
Submit daily report to the Lead Inspector.
C. Shrink Sleeves
Chevron Corporation
1.
Inspection of heat shrinkable field joint protection sleeve - Canusa Wrapped (KLS).
2.
Ensure strict adherence to application procedure. a.
Ensure that all welding inspection and X-Ray has been performed prior to installation of shrink sleeves. Record joint identification.
b.
Wire Brush (power tool) clean field joint per SSPC-SP-3.
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E7.12
Pipeline Manual
c.
Verify correct, uniform preheat of pipe using a contact pyrometer or temperature crayon.
d.
Ensure correct overlap (min. 3").
e.
Ensure even heat application until adhesive trail appears at both ends of sleeves and backing turns a uniform pink-orange color.
f.
Witness jeeping of shrink sleeve and verify that there are no damaged areas or holidays.
Lowering-in Inspector — Procedure No. 12 A. Job Requirements The Lowering-In Inspector will be under the direct supervision of the Lead Inspector. He will be responsible for, but not limited to the following. B. Responsibilities 1.
Inspect the ditch to insure proper depth and sufficient width so as to provide cover and clearance after lowering in is complete.
2.
Insure that contractors lowering in machinery is of sufficient size to handle the pipe load.
3.
Insure that a “catch-off” tractor is used if necessary to prevent a spiral effect.
4.
Insure that cradles or belts are in good condition and proper size and durable.
5.
When padding or rockshield are used in trench, ensure that pipe is placed on padding or rockshield when lowered in trench. If rockshield is the encirclement type, ensure that it is correctly installed.
6.
Insure that all rocks, skids, roots, weld rods and other damaging material are removed from the ditch.
7.
Coordinate with the Coating Inspector or in his absence, insure that all field joint coating and line pipe is free of holidays or torn material.
8.
Ensure that catholic protection and test leads are installed according to specification.
9.
Ensure that the overall safety of personnel, material, and equipment used in the lowering-in operation is followed.
10. Witness 100% of the final jeeping. 11. Verify twice daily that the jeeper is calibrated and proper voltage settings, battery charge, correct speed and grounding of holiday detector. 12. Verify that all damaged areas in coating are properly repaired. 13. Record total footage of pipe jeeped and coating repaired daily.
November 1988
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14. Submit daily written reports to the Lead Inspector.
E7.13
Backfill Inspector — Procedure No. 13 A. Job Requirements The Backfill Inspector will be under the direct supervision of the Lead Inspector. He will be responsible for, but not limited to the following. B. Responsibilities 1.
Responsible for overall safety of personnel, material, and equipment used in the backfill operation.
2.
See that backfill material has no large rock, hard dirt, limbs, etc., that may damage coating.
3.
Designate location of sack breakers (trench plugs and leave ditch open at these points). Inventory and document location type and amount of trench plugs used.
4.
Protect and ensure that vent pipes are properly aligned during backfill.
5.
Ensure that mechanical equipment does not damage the pipe during backfill operation.
6.
Verify that casing and seals, vent pipe, test leads, etc. are properly installed before backfilling begins.
7.
After areas to receive fill or backfill have been properly prepared, material shall be placed and spread in loose 9" lifts, unless specified otherwise, across the entire section. Lesser thickness shall be used if necessary to achieve specified compacted density. Material may then be disked and manipulated to achieve a homogeneous mixture of proper moisture content free of large, hard lumps of soil.
8.
Require tamping and compaction when called for by specifications. Review compaction reports and sign off areas requiring compaction.
9.
Verify that ditch crown is adequate to assure that future settlement will not leave a furrow over the pipeline.
10. Submit daily reports to the Lead Inspector.
E7.14
Restoration And Revegetation Inspector — Procedure No. 14 A. Job Responsibilities The Restoration and Revegetation Inspector will be under the direct supervision of the Lead Inspector. He will be responsible for, but not limited to the following duties.
Chevron Corporation
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B. Responsibilities 1.
Ensure backfilling meets contract specifications.
2.
Ensure that backfill material placed within six inches of the pipeline contains no hard objects such as rocks, boards, or welding rods that could injure the coating.
3.
Ensure that soil separation, where required, is adhered to and that top soil is not used for other purposes.
4.
Ensure that the crown of the ditch is adequate and is placed directly over the ditch and will not leave a furrow over the pipeline after settlement.
5.
Ensure that compaction of soil, where required, is carried out as set forth by the specifications.
6.
Check after rains that drainage at ditches, terraces, roads, bridges, and highways is occurring as designed and that sedimentation downstream has not occurred.
7.
See that revegetation is in accordance with the specifications.
8.
Ensure that Contractor has restored the right-of-way to a satisfactory condition, replaced gates, removed temporary fences and has observed the conditions of the line list.
9.
Ensure that where blasting has been performed, any loose rock scattered on the right-of-way or adjacent lands is cleaned up.
10. Ensure that open fires are not lit unless written permits have been obtained. 11. Check that the pipe hauling or stringing subcontractor has restored lands disturbed by his operation. 12. Vent pipe, aerial markers (linesigning) and test lead posts are to be firmly placed and painted. 13. Check that right-of-way and surrounding ground is cleared and all waste materials, debris and rock disposed of. All materials under Contractor’s custody, including pipe along the right-of-way shall be delivered to points designated by the Company. All equipment, tools and appliances used by the Contractor in the performance of the work shall be removed. Ensure the repair or replacement of public or private roads and railroads. 14. Submit daily written report to the Lead Inspector.
November 1988
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E7.15
Appendix E
Lead Inspector — Procedure No. 15 A. Job Responsibilities The Lead Inspector will be under the direct supervision of Company’s Sr. Engineer, with technical assistance from the Chief Inspector. The Lead Inspector shall be responsible for, but not limited to the following duties. B. Responsibilities
E8.0
1.
Supervision of all Field Inspectors, and shall submit daily field reports to Chief Inspector and Senior Engineer.
2.
To interpret the construction contract specifications for the individual craft inspector if a question arises. a.
To make Field decisions requiring deviation from Construction Specifications and/or Contract after clearing same with the Senior Engineer responsible for the pipeline segment.
b.
To review expense sheets, time sheets and all daily, weekly or monthly reports required by Company’s Construction Representative.
c.
To assure that the necessary tools are issued to the respective Craft Inspectors.
d.
To assure accuracy and completeness of information of Craft Inspectors report.
e.
Fill in and perform the duties of each Craft Inspector during the Craft Inspectors short term absences.
f.
To assure the safety measures necessary for the protection of personnel under his supervision.
g.
Co-ordinate with Contractors on daily field problems such as materials, Right-of-Way access, or any other problems.
h.
Perform other functions as detailed by Sr. Engineer.
Inspection Audit Forms — Mesquite Pipeline Project
Chevron Corporation
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November 1988
Appendix E
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Appendix E
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Appendix E
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Appendix E
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Appendix E
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Appendix E
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Appendix E
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Appendix E
November 1988
Appendix E
E9.0
Pipeline Manual
Welding Procedures Note
Section not reproduced for this appendix.
E10.0 Welder Qualifications Note
Section not reproduced for this appendix.
E11.0 Line Pipe Summary Note
Section not reproduced for this appendix.
E12.0 Codes and Specifications Note
November 1988
Section not reproduced for this appendix.
E-54
Chevron Corporation
Appendix F. Development of Depth of Burial Diagrams
Contents
Chevron Corporation
Page
F1.0
Introduction
F-2
F2.0
Methodology for Generation of Depth of Cover Curves
F-2
F3.0
Pipeline Modeling
F-3
F4.0
Bend Modeling
F-7
F5.0
References
F-14
F-1
November 1988
Appendix F
F1.0
Pipeline Manual
Introduction Depth of burial diagrams, commonly called depth of cover curves, enable pipeline field engineers to quickly determine the required burial depth for a pipeline subject to thermal movement. Because soil restrains pipeline movement and soil restraint increases with depth, the final burial depth is critical to ensure pipeline movement is controlled. If adequate soil restraint is not provided, the pipeline can move upwards, laterally, or downward depending on the system configuration at that point. Pipeline movement may result in decreased soil resistance, increased pipeline stress, and less-than-ideal operating conditions should the pipeline break ground. Analysis of buried pipelines experiencing applied displacements requires complex computer modeling and analysis techniques. We often use simplistic modeling techniques that assume a static soil state without considering secondary load effects. Unfortunately, this approach may be unconservative and result in underestimating soil and pipeline stresses. Development of depth of cover curves requires knowledge of the pipeline’s sensitivity to various design parameters (anchorage length, soil friction, etc.) and thus should include sensitive parameters and incorporate pipeline-soil interaction to ensure accurate prediction of pipeline stresses, stability, and deflections. Recent Company projects having buried lines with significant applied displacements have been successfully analyzed by specialized consulting firms. The design of oil and gas pipelines on the Point Arguello project was analyzed by SSD Engineering Consultants of Berkeley, CA. Soil information was developed from soil boring data by the soil consultant using finite element modeling techniques to generate soil force-displacement curves. The Company does not currently possess a software package that uses finite element methods either for analysis of buried pipelines subject to applied displacements or for generation of soil force-displacement curves. An approximation of pipeline-soil interaction may be obtained from PIPESAG, a program held by the Engineering Technology Department-Civil and Structural Division. This program has not been used extensively. A list of references on current research and analysis techniques, as well as contact information for the previously mentioned consultant, is provided at the end of this appendix.
F2.0
Methodology for Generation of Depth of Cover Curves Here is a summary of the steps to follow when developing depth of cover curves:
November 1988
1.
Define design criteria for the pipeline. Obtain soils data (force-displacement curves, soil densities, water table locations, etc.). Note: soil force-displacement curves are sensitive to pipeline size.
2.
Perform a sensitivity study to determine the governing parameters such as anchor length, soil friction, and bend radius effects. Is displacement or stress governing?
F-2
Chevron Corporation
Pipeline Manual
F3.0
Appendix F
3.
Develop an analytical model using load-deformation characteristics of the surrounding soil, the stress-strain curve of the steel pipe, sensitive parameters etc. Model overbends, sidebends, and sag bends using current soil theories. See following discussions on pipeline and bend modeling.
4.
Analyze the model. From this analysis develop design curves of soil resistivity vs. crown displacement for various bend angle conditions. The bend angle will affect soil resistance and locations of virtual anchors (points where longitudinal displacement is zero). Other limiting criteria (see Step 2) may also govern. See Figure F-1, curve 1.
5.
Using the data from Step 4, develop a depth of cover vs. soil resistance curve (see Figure F-1, curve 2) and additional curves of depth of cover vs. soil resistance (see Figure F-2). The additional depth of cover vs. soil resistance curves must be generated and should reflect bounds for different backfill (loose vs. compacted), and bend (overbend, sidebend, sagbend) configurations. Formulas that provide the basis for these curves follow (see bend discussions); however, other factors may govern (see results of Step 2). These curves incorporate data from field soil testing and are typically provided by a soils consultant.
6.
Develop a depth of cover vs. bend angle curve using curves developed in Steps 4 and 5. See Figure F-1, curve 3.
Pipeline Modeling The soil-pipeline interaction may be modeled as shown in Figure F-3. The soil is represented by a set of perpendicular, discrete springs in the vertical, axial, and horizontal directions. Spring stiffnesses are a function of the soil’s p-y (force-displacement) behavior and should be obtained from a soils consultant. Note spring stiffness varies in the vertical (upward vs. downward) directions. The pipeline itself is represented by beam elements. The response of buried pipelines depends on soil stresses and deformations, which in practice are difficult to characterize. The upward soil force on the base of the pipe is estimated by conventional bearing capacity theory, downward soil force is evaluated using the uplift capacity of buried linear objects, and lateral soil force is approximated by test data on lateral loading of buried linear objects. Recent research (1978) indicates passive earth pressure theories for foundation engineering do not accurately model data from lateral soil-pipeline response. This is mainly due to reliance on data from lateral loading of vertically oriented piles, rather than from a buried, horizontally oriented pipeline. Pipeline movement will exceed pile movement due to the increase in soil resistance with increasing depth for the pile.
Chevron Corporation
F-3
November 1988
Appendix F
Fig. F-1
Pipeline Manual
Methodology for Depth of Cover Curves
NOTE: ALL VALUES SHOWN ARE ARBITRARY.
November 1988
F-4
Chevron Corporation
Pipeline Manual
Fig. F-2
Appendix F
Cover vs. Soil Resistance Curves
Chevron Corporation
F-5
November 1988
Appendix F
Fig. F-3
Pipeline Manual
Model for Bend Design Analyses
(a) Typical Model for α °Bend
(b) Transverse Soil Resistance
November 1988
(c) Longitudinal Soil Resistance
F-6
Chevron Corporation
Pipeline Manual
F4.0
Appendix F
Bend Modeling In evaluating soil resistance to pipe movements, each bend condition should be analyzed separately to account for differences in soil resistance mobilization. Three bend conditions will be considered: • • •
F4.1
overbends (upward pipe movement) sidebends (lateral pipe movement) sagbends (downward pipe movement)
Overbends The amount of soil resistance mobilized at overbends is dependent on the longitudinal and upward movement of the pipeline. The longitudinal soil resistance, F, may be calculated per Equations 400-17 and 400-18 in Section 400 of this manual. The upward soil resistance may be inferred from test data on the uplift capacity of buried anchor plates (Rowe and Davis). See Figure F-4 for breakout wedge shapes. Total resistance may be estimated using the following equation: Fu = W s + d ( cF c + γ′DF′ q ) where: Fu = ultimate soil reaction, FL-1 Ws = effective weight of soil wedge per unit length, FL-1 d = pipe diameter, L c = cohesion, FL-2 γ = effective unit weight of the soil, FL-3 D = depth to the top of the pipe F c and F′ q = breakout factors (dimensionless) Figures F-5 and F-6 show Fc and Fq as functions of the depth of burial and the angle of internal friction, Ø.
Chevron Corporation
F-7
November 1988
Appendix F
Fig. F-4
Pipeline Manual
Possible Shapes of Breakout, for Shallow Embedment
(a) This is a lower bound, especially good for remodeled soils. Use this. (b) This is good for sandy soils, however it may overpredict soil resistance. Use (a). (c) This is good for clayey soils, however (a) is more conservative. Use (a).
Fig. F-5
Relationship Between Breakout Factor, F c , and Depth of Burial Pipe Diameter Ratio, D/d
November 1988
F-8
Chevron Corporation
Pipeline Manual
Fig. F-6
Appendix F
Relationship Between Breakout Factor, Fq, and Depth of Burial Pipe Diameter Ratio, D/d
F4.2
Sidebends The amount of lateral soil resistance mobilized at sidebends is dependent on the longitudinal and lateral movement of the pipeline. The longitudinal soil resistance, F, may be calculated per Equations 400-17 and 400-18 in Section 400 of this manual. The lateral soil resistance may be approximated by studies on the behavior of buried pipe (Trautmann and O’Rourke). Soil-pipeline interaction is similar to that of vertical anchor plates, footings, or walls moving horizontally and thus mobilizing a passive earth pressure. This bend condition may be critical in weak soils. For granular soil (sand): FL = (Rs) (P′o) (d) where: FL = ultimate resistance to transverse displacement, FL-1 Rs = dimensionless coefficient whose value varies with depth of embedment and the relative density of the sand P′o = effective overburden pressure at the level of the center of the pipe, FL-2. P′o is equal to γ′ Z where g′ is the unit weight of the soil (about 120 lb/ft3 above water and about 70 lb/ft3 below) and Z is the depth from ground surface to the center of the pipe
Chevron Corporation
F-9
November 1988
Appendix F
Pipeline Manual
d = pipe diameter, L Values of the coefficient Rs are given in Figure F-7. Fig. F-7
Values of Coefficient Rs for Pipes in Sand
Depth to Bottom of Pipe Divided by Pipe Diameter (H/d)(1)
Loose Sand
Values of Rs Medium-Dense Sand
Dense Sand
1.0
2.7
3.9
5.7
2.0
3.0
4.5
6.9
3.0
3.8
5.9
9.6
4.0
4.5
7.2
11.9
5.0
5.0
8.2
13.7
6.0
5.4
8.9
15.2
8.0
6.0
10.0
17.2
10.0
6.4
10.7
18.6
12.0
6.6
11.3
19.6
(1) H = depth from ground surface to bottom of pipe
For cohesive soil (clay): FL = (Rc) (Su) (d) where: FL = ultimate resistance to transverse displacement Rc = dimensionless coefficient whose value varies with depth of embedment. See Figure F-8. Su = undrained shear strength of clay, FL-2. See Figure F-9. d = pipe diameter, L
November 1988
F-10
Chevron Corporation
Pipeline Manual
Appendix F
Properties of Backfill Around Pipes
Fig. F-8
Approximate Undrained Strength of Clay
Approximate Relative Density of Sand
Dumped Backfill—No Compaction
250 psf or less
Loose
Jetting(1)
Not Applicable
Loose
Jetting and Vibrating(1)
Not Applicable
Loose to Medium
Light Mechanical Equipment
250 to 1000 psf
Medium
500 psf to 2000 psf
Dense
Method of Compaction
Heavy Mechanical Equipment, Good Procedures (1) Only useful for clean sands and gravels
Fig. F-9
Values of Coefficient Rc for Pipes in Clay
Depth to Bottom of Pipe Divided by Pipe Diameter (H/d)(1)
Value of Rc
1.0
2.0
2.0
3.5
3.0
4.5
4.0
5.3
5.0
6.0
6.0
6.7
8.0
8.0
10.0
8.2
≥ 12.0
9.0
(1) H = depth from ground surface to bottom of pipe
Chevron Corporation
F-11
November 1988
Appendix F
Pipeline Manual
F4.3
Sagbends This is the least critical bend condition, and is not likely to govern over uplift (overbend) concerns. The amount of soil resistance mobilized at sag bends is dependent on the longitudinal and downward movement of the pipeline. The longitudinal soil resistance, F, may be calculated per Equations 400-17, and 400-18 in Section 400 of this manual. The downward soil resistance may be approximated by the Terzaghi and Peck (1968) method for shallow continuous footings. The ultimate downward resisting force, FD, may be calculated by: For granular soil (sand): FD = (cNc + γ′ H Nq + 0.5 γ′ dNg) d where: FD = ultimate soil reaction, FL-1 c = undrained shear strength of the soil below the pipe, FL-2 Nc = bearing capacity factor (dimensionless) γ = unit weight of the soil, FL-3 H = depth to the bottom of the pipe, L d = pipe diameter, L γ′ = effective unit weight of the soil, FL-3. Use moist unit weight above water, buoyant unit weight below. Nc, Nq, Nγ = bearing capacity factors. See Figure F-10. For cohesive soil (clay): Pu = (cNc + γ H) d where: Pu = ultimate soil reaction, FL-1 c = undrained shear strength of the soil below the pipe, L Variation of the value of Nc with depth of embedment is shown in Figure F-11. The breadth, B, is equal to the pipe diameter, d.
November 1988
F-12
Chevron Corporation
Pipeline Manual
Appendix F
Fig. F-10 Bearing-Capacity Factors for the General Bearing-Capacity Equation.
Chevron Corporation
F-13
November 1988
Appendix F
Pipeline Manual
Fig. F-11 Bearing-Capacity Factors for Foundations in Clay
F5.0
References
November 1988
1.
Dames and Moore. Geotechnical Investigation, Onshore Pipelines-Point Conception to Gaviota, Point Arguello Gas and Oil Systems. Santa Barbara, CA: Job No. 113-726-03, 1984.
2.
Peng L. C. Stress Analysis Methods for Underground Pipe Lines. Pipe Line Industry, 1978.
3.
Rowe, R. K. and E. H. Davis. "The Behavior of Anchor Plates in Sand." Geotechnique, V.32, No. 1, 1982, pp. 25-41.
4.
SSD Engineering Consultants. "Pipeline Stress Analysis-Point Arguello Oil and Gas Systems," 1984.
5.
Trautmann, C. H., T. D. O’Rourke, F. H. Kulhawy. "Uplift Force-Displacement Response of Buried Pipe." Journal of Geotechnical Engineering, V.111, No. 9, 1985, pp. 1061-1076.
6.
Trautmann, C. H., T. D. O’Rourke. "Lateral Force-Displacement Response of Buried Pipe." Journal of Geotechnical Engineering, V.111, No. 9, 1984, pp. 1077-1092.
F-14
Chevron Corporation
Pipeline Manual
Appendix F
Engineering Consultants 1.
SSD Inc., 1930 Shattuck Ave., Berkeley, CA 94704 (415) 849-3458.
In-House Consultation
Chevron Corporation
1.
Engineering Technology Department-Civil and Structural Division.
2.
Engineering Technology Department-Engineering Analysis and Material Division.
F-15
November 1988
Appendix G. Subsea Valves
Abstract Lists of subsea pipeline valve users and applications. This information shows valve types, sizes, makes and actuator sizes typically available, which have been used subsea. This information may be used in planning, designing, and selecting components for offshore pipelines. Contents Figure G-1
Chevron Corporation
Page G-2
List of Users for Cameron Subsea Ball Valves
Figure G-2
Subsea Ball Valve Installations in the North Sea — Provided by J. P. Kenny & Partners Ltd./CPUK
G-4
Figure G-3
Partial User List of Shafer Subsea Actuators
G-5
Figure G-4
Neles Offshore Subsurface Valves
G-7
G-1
November 1988
Appendix G
Fig. G-1
Pipeline Manual
List of Users for Cameron Subsea Ball Valves (1 of 3)
Eng/Contractor
End User
Location Project
Valve Size/Make
Actuator Size
McDermott
ONGC
India/BEN Project
30" - 600 Cameron
20 × 16
Brown & Root
INOC
Iraq
48" - 400 Cameron
20 × 16
36" - 400 Cameron
16½ × 16
40" - 900
14½ × 14
30" - 900
12½ × 12
Eagleton Eng.
Woodside Pet.
Australia
Dubai Pet.
Dubai Pet.
Dubai, U. A. E.
36" - 150 Cameron
12½ × 12
Premaberg
British Gas
North Sea
36" - 900 Cameron
20 × 16
Tenn. Gas Transmission
Tenn. Gas
Gulf of Mexico
36" - 600
20 × 16
30" - 600 Cameron
16½ × 16
36" - 600 Cameron
20 × 16
30" - 600 Cameron
16½ × 16
Texas Eastern Gas Trans.
Texas Eastern
Gulf of Mexico
Columbia Gulf Gas Trans.
Columbia Gulf
Gulf of Mexico
36" - 600
20 × 16
IMODCO Calif. (SBM)
Various
Worldwide
Various
Various
Sofec-Housto(CALM)
Various
Worldwide
Various
Various
Protech Eng. (Holland)
MobilNetherlands
North Sea
20"×18"-900 Cameron
16½ × 16
Shell Oil Worldwide
Shell Oil
Worldwide
Various
Various
Pennzoil Netherlands
Pennzoil
North Sea
10" - 1500 Cameron
11 × 10
20" - 900
14½ × 14
Hydril-Houston
Zadco
Abu Dhabi
24" - 400
14½ × 14
Brown & Root
ONGC
S. Bassien
36" - 900 Cameron
20 × 16
November 1988
G-2
Chevron Corporation
Pipeline Manual
Fig. G-1
Appendix G
List of Users for Cameron Subsea Ball Valves (2 of 3)
Eng/Contractor
McDermott/ Hyundai
Hyundai
End User
ONGC
ONGC
Location Project
Valve Size/Make
Actuator Size
Hazira P. L.
32" - 900 Cameron
16½ × 16
India
20" - 900 Cameron
12½ × 12
16" - 900 Cameron
11 × 10
12" - 900 Cameron
6½ × 8
10" - 900 Cameron
6½ × 8
8" - 900 Cameron
6½ × 3½
20" - 900
12½ × 12
20"×18"-900
12½ × 12
18" - 900
12½ × 12
18"×16"-900
11 × 10
36" - 900 Cameron
20 × 16
30"×28"-900 Cameron
14½ × 14
20" - 900 Cameron
12½ × 12
12" - 900 Cameron
9×7
12"×10"-900
6½ × 8
“SH” Project India
BPA Proj. India
ESSAR
ONGC
“WIPPM”
12" - 900 Cameron
9 × 12
Gulf Interstate
Yemen E&P
No. Yemen Export Fac.
12" - 600 Cameron
6½ × 8
24" - 600 Cameron
12½ × 12
24" - 150
11 × 10
30" - 150
14½ × 14
10" - 150
11 × 10
Wms. Bros.
Sofec
Chevron Corporation
Ceylon Pet.
Petronas
Sri Lanka
Malaysia
G-3
November 1988
Appendix G
Fig. G-1
Pipeline Manual
List of Users for Cameron Subsea Ball Valves (3 of 3)
Eng/Contractor
End User
Location Project
Valve Size/Make
Actuator Size
SBM
SCOP
Iraq
24" - 600
14½ × 14
30" - 600
16½ × 16
36" - 600
20 × 16
Stibbe
N.A.M. (Shell)
Holland
Various
Various
SBM
Oasis Oil
Libya
16" - 300 Cameron
9×7
Sofec/Hydril/Fluor
L.O.O.P.
Louisiana USA
30" - 300
RPC-475-708
24" - 300
RPC-475-700
Fig. G-2
Subsea Ball Valve Installations in the North Sea — Provided by J. P. Kenny & Partners Ltd./CPUK
Manufacturer
Valve Size and Class
Subsea Location (North Sea)
Product
Borsig
8" - 16" CL900
Shell Western Leg
Gas
36" - CL900
Mobil Statfjord
Crude
36" CL900
Shell Flags System
Gas
2" - 30" CL900
Mobil Statfjord GT & T System (approx. 10 valves)
Gas
8" - 24" CL1500
Occidental Claymore/Piper
Gas
30" CL900
Danish Gas Transmission- System
Gas
Cort
10", 12" CL1500
BP NLGP System
Gas
Neles
20" - CL900
BP NLGP System
Gas
20" - CL900
Mobil Statfjord (GT & T Subsea tee)
Gas
20" - CL900
Statpipe Pipeline Tee
Gas
20" - CL900
Statoil Ula Y-piece
Crude
Cameron
November 1988
G-4
Chevron Corporation
Pipeline Manual
Fig. G-3
Appendix G
Partial User List of Shafer Subsea Actuators (1 of 2)
Eng/Contractor
End User
Project/Location
Valve Size/Make
Actuator Size
McDermott
ONGC
India/BHN Project
30"-600 Cameron
20 × 16
Brown & Root
INOC
Iraq
48"-400 Cameron
20 × 16
36"-400
16½ ×16
40"-900 JSW
14½ ×14
30"900 JSW
12½ ×12
Eagleton Eng.
WoodsidePet.
Australia
Dubai Pet
Dubai Pet.
Dubai U.A.E.
36"-150 Cameron
12½ ×12
Premaberg
British Gas
North Sea
36"-900 Cameron
20 × 16
Tenn. Gas Transmission
Tenn. Gas
Gulf of Mexico
36"-600
20 × 16
30"-600 Cameron
16½ ×16
36"-600 Cameron
20 × 16
30"-600 Cameron
16½ ×16 20 × 16
Texas Eastern Gas Trans.
Texas Eastern
Gulf of Mexico
Columbia Gulf
Columbia
Gulf of
36"-600
Gas Trans.
Gulf
Mexico
WKM
IMODCOCalif.(SBM)
Various
Worldwide
Various
Various
Sofec-Houston (CALM)
Various
Worldwide
Various
Various
Protech Eng. (Holland)
Mobil-Netherlands
North Sea
20"×18"-900 Cameron
16½ ×16
Shell Oil Worldwide
Shell Oil
Worldwide
Various
Various
Pennzoil Netherlands
Pennzoil
North Sea
10'-1500 Cameron
11 × 10
20"-900 Cameron
14½ ×14
Hydril-Houston
Zadco
Abu Dhabi
24"-400 Grove
14½ ×14
Brown & Root
ONGC
S. Bassien
36"-900 Cameron
20 × 16
Hazira P.L.
32"-900 Cameron
16½ ×12
India
20"-900 Cameron
12½ ×16
16"-900 Cameron
11 × 10
12"-900 Cameron
6½ × 8
10"-900 Cameron
6½ × 8
8"-900
6½ ×3½
20"-900 IKS
12½ ×12
20"×18"-900 IKS
12½ ×12
18"-900 IKS
12½ ×12
McDermott/Hyundai
Chevron Corporation
ONGC
“SH” Project India
G-5
November 1988
Appendix G
Fig. G-3
Pipeline Manual
Partial User List of Shafer Subsea Actuators (2 of 2)
Eng/Contractor
Hyundai
End User
ONGC
Project/Location
“BPA” Proj. India
Valve Size/Make
Actuator Size
18"×16"-900 IKS
11 × 10
36"-900 Cameron
20 × 16
30"×28"-900 Cameron
14½ ×14
20"-900 Cameron
12½ ×12
12"-900 Cameron
9×7
12"×10"-900
6½ × 8
ESSAR
ONGC
“WIPPM”
12"-900 Cameron
9 × 12
Gulf Interstate
Yemen E&P
No. Yemen Export Fac
12"-600 Cameron
6½ × 8
24"-600 Cameron
12½ ×12
24"-150 TK
11 × 10
30"-150 TK
14½ ×14
Wms. Bros.
Ceylon Pet.
Sri Lanka
Sofec
Petronas
Malaysia
10"-150 Grove
11 × 10
SBM
SCOP
Iraq
24"-600
14½ ×14
Grove 30"-600 Grove
16½ ×16
36"-600 Grove
20 × 16
Stibbe
N.A.M. (Shell)
Holland
Various
Various
SBM
Oasis Oil
Libya
16"-300 Cameron
9×7
Sofec/Hydril/Fluor
L.O.O.P.
Louisiana USA
30"-300 Grove
RPC-475-708
24"-300 Grove
RPC-475-700
16"-300 Cameron
6½ × 8
Hyundai/Blue Water Eng.
November 1988
O.N.G.C.
ICP/ICW Project India
G-6
Chevron Corporation
Pipeline Manual
Fig. G-4
Appendix G
Neles Offshore Subsurface Valves (1 of 4) Application/ Service
Customer/Plant
Description/Type
Qty
Date
Aker Off Shore A/S Mobil Condeep Platform Statfjord faltet
ANSI 150 Metal Seated Ball Valves with Navire Hydraulic Actuators Size: 10" and 12" Type: PCYA10AS PCYA12AS
16
07/74
Medium: Oil/water DP = 3-12 bar Outside liquid pressure: 5-10 bar
Installed 50100 m under surface
Shell Oil, UK Thosgoch, Anglesey North Wales
ANSI 150 Teflon Seated Ball Valves with Limitorque Wormgear Actuators Size: 24" Type: DCYA24AT-ZGH4Q-SGA
2
07/78
Medium: Crude Oil
Single Point Mooring Buoy
Shell Oil, UK Thosgoch, Anglesey North Wales
ANSI 300 Teflon Seated Ball Valves Size: 24" Type: DDYY24YT
2
06/79
Single Point Mooring Buoy
Shell Exploration & Production
ANSI 300 Teflon Seated Ball Valves with Shafer Rotary Vane Type
5
02/80
Subsurface
SALM FULMAR A North Sea Production Platform
Actuator Size: 16" Type: DDYY16YT
Single Buoy Moorings Inc./Shell Rotterdam
ANSI 150 Teflon Seated Ball Valves with Hand Levers Size: 2" and 4" Type: CCYA02DT-AM325 CCYA04DT-AM540
4
04/80
SBM Loading Buoy
Single Buoy Moorings Inc./Shell Rotterdam
ANSI 150 and 300 Teflon Seated Ball Valves with Torkmatic Wormgear Actuators Size: 12" and 20" Type: DDYA12YT-Y-KT240/ 0475R DCYA20YT-YMQSR6/6/0762R
3
08/80
SBM Loading Buoy
Shell Research Ltd. Thornton UK
ANSI 900 Nylon Seated Top-Entry Ball Valve with Kracht Hydraulic Actuator Size: 20" Type: TGAY20DT-Z-KS4250
1
12/80
Chevron Corporation
Remarks
Mounted on the buoy in splash line (very corrosive duty)
G-7
Prototype Valve for Shell Subsea
Tests
November 1988
Appendix G
Fig. G-4
Pipeline Manual
Neles Offshore Subsurface Valves (2 of 4) Application/ Service
Customer/Plant
Description/Type
Qty
Date
Shell International Valparaiso Chile
ANSI 150 Teflon Seated Ball Valves with Hand Levers Size: 4" Type: CCAG04YT-AM540
2
12/81
Medium: Submarine Line Clean white spirits
under Surface
The British National Oil Corporation (BNOC)
Uprated ANSI 900 Nylon Seated Top-Entry Ball Valves with Kracht
5
03/82 04/82
Medium: Raw Gas
Subsea Line depth 150 m water depth 150 m
The Northern Leg Pipeline
Hydraulic Subsea Actuators Size: 20" Type: TGBY20YY-Y-KS4250
Shell UK Exploration & Production
ANSI 300 Teflon Seated Ball Valve with Shafer Rotary Vane Type Actuator
SALM FULMAR A North Sea Production Platform
Size: 16" Type: DDYY16YT-Y-Shafer
Shell TRC Thornton Research Centre UK
Uprated ANSI 900 Nylon Seated Top-Entry Ball Valve with Ap Precision Hydraulic Subsea Actuator Size: 10" Type: TGAA10YY-APPH
Bechtel/Suez Oil Company Zeit Bay project
ANSI 300 Full Bore “piggable” Subsea Ball Valves, PTFE Seated, Split Body, Flanged RTJ with Kracht Hydraulic actuators Size: 20" Size: 30" Type: DDYY20YY-KS500 Type: DDYY30YY-KS1250
Fluor/Statoil Statfjord development Project
November 1988
Uprated ANSI 900 Nylon Seated Top-Entry Ball Valves with Kracht Hydraulic Actuators Size: 20" Type: TGBY20YY-KS6300
G-8
Remarks
t = -30 to +60°C
p = 2500 psig
1
07/82
Subsurface
1
12/82
Prototype Valve for Shell Subsea Tests
2 2
12/83 12/83
3
01/84
Crude oil/ Ballast water SBM/P.L.E.M. Systems
Subsea, Water Depth 40 m
Natural gas/sea water tie-in valves for future fields branch lines
Subsea line water depth 150 m
Chevron Corporation
Pipeline Manual
Fig. G-4
Appendix G
Neles Offshore Subsurface Valves (3 of 4) Application/ Service
Customer/Plant
Description/Type
Qty
Date
Remarks
Mobil/Moss Rosenberg Statfjord gas Treatment and Transportation project
Uprated ANSI 900 Nylon Seated Top-Entry Ball Valves with Kracht Hydraulic Actuators Size: 20" Type: TGBY20YY-KS6300
3
02/84
Natural gas/sea water
Shell UK Fulmar gas project
ANSI Class 900 Uprated to 25oo psi Nylon Seated Top-Entry Subsea Ball Valves with Kracht Hydraulic Actuator Size: 20" Type: TGBY20YY-KS
16
5-12 /84
Medium gas
Shell UK Fulmar gas project
ANSI Class 1500 and 900 Nylon Seated Top-Entry Subsea Ball Valves with Manual Gears Size: 2", ANSI 1500 Size: 10", ANSI 900 Types: THY02YGY-IP15.4 TGY10YGY-IP150.96
01/85
Gas
Subsea line
Subsea line water depth 150 m
13 11
Statiol Ula Pipeline Project
ANSI Class 900 Uprated to 2500 psi Nylon Seated Top-Entry Subsea Ball Valves with Kracht Hydraulic Actuators Size: 20" Type: TGBY20YY-KS
4
06/85
Crude Oil
Subsea line water depth 70 m
Statoil Gullfaks A Project SPM1
ANSI Class 300 Subsea Ball Valves, Full Bore, PTFE Seats Split-Body with Hydraulic Actuators Size: 20" 2 pcs Size: 24" 5 pcs Type: D2DY20FGT-KS1600 D2DY24FGT-KS1600 D2DY24FGT-T325
7
06/85
Crude oil
Subsea, water depth 70 m
Chevron Corporation
G-9
November 1988
Appendix G
Fig. G-4
Pipeline Manual
Neles Offshore Subsurface Valves (4 of 4)
Customer/Plant
Description/Type
Qty
Date
Application/ Service
Statoil Gulfaks A Project SPM2
ANSI Class 300 Subsea Ball Valves, Full Bore, PTFE Seats Split-Body with Hydraulic Actuators Size: 20" 2 pcs 24" 5 pcs 36" 1 pc Type: D2DY20FGT-KS1600 D2DY24FGT-KS1600 D2DY24FGT-T325 D2DY36FGT-KS4000
8
11/85
Crude oil
Subsea, water depth 70 m
Arco Indonesia Java Sea
ANSI Class 1500 Subsea Ball Valves, Top-Entry, PTFE Seats with Torkmatic Wormgear Actuators Size: 8" Type: T3HS08FGT-T400
2
11/85
Crude Oil p = 2000 psi
Subsea, water depth 30 m
November 1988
G-10
Remarks
Chevron Corporation
Appendix H. Guidelines for Weight-Coating on Submerged Pipelines
Contents
Chevron Corporation
Page
H1.0
Introduction
H-2
H2.0
Installation Conditions to Be Considered in Design
H-2
H3.0
Conditions for the Line In Service to Be Considered in Design
H-3
H4.0
Design Objective
H-4
H5.0
Design Data Required
H-4
H6.0
Weight-Coating Design
H-4
H7.0
Weight-Coating Specifications
H-6
H8.0
Data for Weight-Coating Control
H-8
H9.0
Precast Concrete Weights
H-9
H-1
January 1990
Appendix H
H1.0
Pipeline Manual
Introduction These guidelines cover design and specification development for weight-coating on submerged pipelines installed at waterway crossings, swamps, and offshore. Further guidelines for weight-coating are in Section 447 for waterway crossings and Sections 935 and 953 for offshore pipelines. When the combined weight of the pipe, corrosion protective coating, and operating fluid does not provide sufficient stability for the submerged pipeline during installation and service life, weight must be added by: • •
Continuous weight-coating of the pipe with a uniform cement-based coating Individual precast weights attached to or placed over the line at intervals
An economic comparison of alternative combinations of pipe wall thickness and weight-coating thickness, possibly with alternative protective coatings, may be necessary. Heavier wall pipe offers greater mechanical strength, possible use of a lower grade steel, and some insurance against pitting failures. The additional weight of steel will reduce the need for weight-coating; however, concrete is generally a cheaper way to provide weighting. For liquid-filled lines the feasibility of constructing the line using water-filled pipe should be considered. For example, in 1962 a 100-mile, 20-inch crude oil pipeline was installed in shallow waters from Empire Terminal, Louisiana, to Pascagoula Refinery, Mississippi. The line was Somastic-coated—without weight-coating— and filled with water to submerge it as it was laid from a lay-barge. Of course, the contents of this line can never be displaced with air or gas.
H2.0
Installation Conditions to Be Considered in Design
January 1990
•
Density of water. Water density is seldom significant, but may be a factor in bays where there could be a varying mixture of fresh water and salt water, and when close control of the submerged weight is critical for the particular construction method.
•
Nature of the bottom. Often this is not critical, but may affect buoyant or drag forces on the line, which may be a consideration for the particular construction method.
•
Density of the bottom and/or backfill material. This is a factor if a cohesionless material contributes to the buoyancy of the line, either during installation or after installation as backfill is intentionally placed or is naturally deposited over the line. Agitation of bottom material under conditions of unusual water flow or wave action should be considered if the bottom material could become “fluid.”
•
Nature of the backfill material. Besides density, consideration should be given to possible damage to the line if rock or other hard objects fall intentionally or naturally onto the line.
H-2
Chevron Corporation
Pipeline Manual
Appendix H
•
Construction method. The method of construction is determined by water depth, location of the work, and alignment of the line: –
–
–
–
–
Lay barge. The pipe is laid off the end of the barge, usually with a “stinger” and sometimes with tensioning, and is lowered to the bottom as the barge moves ahead. This is a widely used method for all water depths. Surface pull/push. The pipe is floated into position, and subsequently dropped to the bottom by filling with water or releasing flotation drums used to support the line while floated out to position. This is a commonly used method for lines running from or to shoreline in relatively shallow water. Submerged carry. The pipe is carried into position by equipment and lowered. In shallow river crossings sideboom tractors or backhoes may traverse the crossing; in deeper water, cranes or winches on barges are used. This method is used most at crossings. Off-bottom pull. The pipe is buoyant, usually employing flotation drums, and is kept submerged by the weight of heavy chains, attached to the pipe at intervals, which drag along the bottom so that the pipe is off the bottom while the lower ends of the chains are on the bottom. This is an unusual method. Bottom pull. The pipe is pulled from shore along the bottom into position, sometimes a distance from the shoreline fabrication site. This is a commonly used method, both for crossings and offshore.
Conditions may dictate the construction method: deep water requires a lay barge with stinger, possibly with controlled tensioning during lay. In other cases several alternative methods may be feasible, at the option of the construction contractor. Conditions for the operating line and the construction method may require that the line be either empty or filled with water during installation. The construction method to install the line must take fully into account the weight and strength of the pipe and the forces on the pipe both during installation and before the line is filled with the operating fluid.
H3.0
Conditions for the Line In Service to Be Considered in Design
Chevron Corporation
•
Weight of the pipeline filled with the operating fluid.
•
Weight of the empty line if the operating fluid is a liquid. This liquid could be displaced with air or gas, intentionally or inadvertently, during the service life of the pipeline.
•
Density of the bottom or backfill material. See Section H2.0.
•
Effect by hydrodynamic forces on the line during the service life of the pipeline. See Section 935.
H-3
January 1990
Appendix H
H4.0
Pipeline Manual
Design Objective The pipeline must be sufficiently stable on the bottom under all conditions of operation and exposure to external forces (buoyant, lateral, hydrodynamic). Greater stability is desirable, but represents higher costs for materials and, very possibly, for construction because of the greater weight of pipe to be handled.
H5.0
Design Data Required Data required for design of the weight-coated pipeline has been discussed in Sections H2.0 and H3.0. These guidelines do not cover specific criteria values to achieve final stability, such as: •
Required submerged weight (negative buoyancy) of the pipe in water or a cohesionless bottom or backfill material, or the equivalent required specific gravity of the line
•
Density values for cohesionless bottom or backfill material, and change in bottom or backfill properties under unusual water flow or wave action conditions
•
Data to determine hydrodynamic forces on the pipeline. See Section 935.
•
Risk and consequences of a liquid fill in a line being displaced with air or gas
Establishing design values for most of these criteria will involve prudent investigation, either by reference to previous installations, search of available geophysical literature, or field surveys. Other physical data relating to dimensions and weight of the pipe and corrosion protective coating, weight of the operating fluid, etc., are readily available.
H6.0
Weight-Coating Design A weight-coating is a more or less uniform thickness of concrete applied over the protective coating on the pipe to achieve a combined weight that will give the desired submerged weight of the pipeline. The density of the weight-coating can be adjusted within a range of approximately 140 to 190 pounds per cubic foot by selection of the aggregate used in the weight-coating concrete. Increasing the thickness of the applied weight-coating will add to the combined weight, but the larger diameter of the weight-coated pipe increases the buoyant force because more water, or bottom or backfill material is displaced. The following equations give the weight of weight-coating per lineal foot of pipe, outside diameter of the weight-coating, and the thickness of weight-coating required to provide a design submerged weight per lineal foot:
January 1990
H-4
Chevron Corporation
Pipeline Manual
Appendix H
Ws + ρw Ap – ( Wp + WF ) W c = ---------------------------------------------------------------ρw 1 ---------faρc 1/2 Ws + fa ρcAp – ( Wp + WF ) ----------------------------------------------------------------D c = 13.5 fa ρ c – ρw
Wc or = 13.5 ---------- + A p fa ρ c
1/2
t c = 0.5 × ( D c – D p ) (Eq. H-1)
where: Wc = Weight of weight-coating, lb/ft Ws = Submerged weight of the pipe, lb/ft Wp = Weight of pipe without weight-coating, lb/ft WF = Weight of fluid contents inside the pipe, lb/ft = 0 for empty pipe WT = Total weight of weight-coated pipe, lb/ft = Wp + W c + W F Dp = Outside diameter of protective-coated pipe without weightcoating, in. Ap = Cross-sectional area of protective-coated pipe without weightcoating, ft2 = 0.00545 Dp2 Dc = Outside diameter of weight-coated pipe, in. tc = Thickness of weight-coating, in. ρc = Density of weight-coating, lb/ft3 fa = Factor for absorption of water in the weight-coating concrete (see following discussion) ρw = Density of water or cohesionless material, lb/ft3
Chevron Corporation
H-5
January 1990
Appendix H
Pipeline Manual
If weight-coating thickness has already been set, or the weight-coating has been applied to the pipe, the following equation gives the resultant submerged weight per lineal foot: Wc W s = W T – ρ w ---------- + A p fa ρc (Eq. H-2)
Two important factors in establishing required weight-coating and specifying acceptable tolerances for applied weight-coating are: •
Absorption of water in the weight-coating concrete
•
Variations in concrete thickness and density during application of the weightcoating (discussed under specification tolerances, Section H7.0 below)
Depending on how the weight-coating concrete is applied and controlled during application, the concrete will absorb water in varying amounts when submerged. The weight of absorbed water can be expected to be 3% to 8% of the weight of the concrete coating, and should be included as a design consideration. Use of a water absorption factor of 1.0 is conservative, since absorbed water adds to the stability of the installed pipe. In calculating on-bottom stability of offshore pipeline, a water absorption factor of 1.05 is typically used for 140 lb/ft3 concrete. For 190 lb/ft3 concrete, a 1.03 factor is suggested. Water absorption is an important consideration when the construction method is sensitive to the weight of the pipeline in the water. A reasonably reliable method of determining the water absorption factor is to weigh several joints of pipe in air and again after submerging in water for a sufficient time to allow water absorption—usually at least 48 hours. Concrete samples may give an approximation, but are not likely to be representative because of their small size.
H7.0
Weight-Coating Specifications Specifications for weight-coating should contain three sections. The first two sections need to be developed for the particular project, giving consideration to conditions during installation and for the line in operation. The third section can incorporate standard specifications suitable for the application method, as follows: •
Description of pipe to be weight-coated, nominal weight-coating thickness and density, and coating application method
•
Tolerances for thickness, density, and weight of weight-coating; methods for measurement and calculation of these during application; means to control application to meet the tolerances
•
Quality of weight-coating material components and applied concrete, consistent with the particular application method selected
Rejecting weight-coated pipe that does not conform with specifications is very costly, not only to the weight-coating applicator (since the purchase order contract normally makes him responsible for all costs to correct weight-coating that does not
January 1990
H-6
Chevron Corporation
Pipeline Manual
Appendix H
meet specifications) but also to the Company, because of the delay to remove and re-do the concrete coating and the possible damage to the pipe or the corrosion protective coating and attendant delays. There is usually agreement that the concrete quality must conform to the specifications, and, normally, reputable weight-coating applicators have established procedures that produce a good product. However, for both commercial application methods—impingement and compression coat—the thickness of concrete and the density of the concrete will vary slightly during application, and will affect the submerged weight of the individual pipe joints. Close control of thickness is difficult, and a fraction of an inch may have a significant effect on the submerged weight. Also, the weights of the protective-coated pipe joints before weight-coating vary. This influences the total weight of the weight-coated joint, and is not within the control of the weight-coating applicator. Weight and dimensional tolerances must be clearly defined in the specification, and understood and agreed to by Company and the weight-coating applicator before award of the purchase order contract. Specifications must be realistic to get an achievable product. Weight tolerances defined in weight-coating specifications are often the basis for information included in pipeline construction specifications, and when the Company furnishes the weight-coated pipe to the construction contractor, the contractor has valid claim for recourse if the weight-coated pipe does not conform to weight data stated in the construction contract. In one instance, an effluent line was to be pulled empty on the bottom in a shallow bay. A submerged weight of 10 pounds per lineal foot was specified, and a 10% tolerance on the specified submerged weight was specified in the weight-coating purchase order and again stated in the construction contract. This represented a hypothetical control of weight-coating to within 1 pound per lineal foot on 3.4-inch-thick concrete coating, which weighed 425 pounds per lineal foot on a 36-inch pipe. This was in no way achievable. The description section of the specification should include: •
Size and total length of pipe, type and thickness of corrosion protective coating on the pipe, average pipe joint length, and minimum and maximum joint lengths
•
Thickness and density of weight-coating to be applied, application method, and length of hold-back of weight-coating from the end of the pipe (to allow for application of protective coating at the girth welds)
•
Shipping and storage information and instructions
The section on tolerances should recognize the tolerances desired to comply with design and construction requirements, practical limitations on control of thickness dimensions and density inherent in the particular application method, and the adjustments available during application to achieve the specified tolerances. In developing this section of the specifications, input is needed from the weight-coating applicator either in discussion before soliciting quotations or as specifically requested information with the quotations. This information from the applicator should include not only values for proposed tolerances, but also how and when
Chevron Corporation
H-7
January 1990
Appendix H
Pipeline Manual
measurements of weight, outside diameter, and concrete density are taken, and the ability to make adjustments during application to keep the product within tolerances. Setting a minimum on the weight of each weight-coated joint is practical if the construction method is not sensitive to the weight of the pipe in water, since the coating applicator can reasonably produce weight-coated pipe that meets or exceeds the specified minimum. However, when the construction method is critically dependent on the weight of the pipe in water, the setting of maximum and minimum weights must be carefully considered, and water absorption taken into account. This is typical for surface pull/push and bottom pull methods. Because of the difficulty in closely controlling the weight-coating on each joint of pipe, practice is to specify tolerances for weight and thickness for averages of a number of joints, often ten, recognizing that when welded and laid, a considerable length of line will act together in the water and on the bottom. Thus, the specification for weight-coating should include weight and thickness tolerances for individual joints and closer tolerances for averages of any 10 consecutive joints. The section on quality of material components and the weight-coating concrete should pertain to the particular application method, and usually can utilize standard specifications with current updating as available from specialists in the Materials Division of the Chevron Research and Technology Company.
H8.0
Data for Weight-Coating Control Measured data are needed to determine that weight-coating is within specification tolerances and to control the ongoing application process. The data that must be taken, at appropriate intervals, are: P = Weight of the protective-coated joint before weight-coating, lb J = Weight of the weight-coated joint, lb Dc = Average outside diameter of the weight- coated pipe joint, as determined by measuring the circumferences at a number of places along the length of the joint, in. L = Length of the pipe joint, ft h = Lengths without weight-coating, such as hold-back from the ends of the pipe (to allow for application of protective coating at girth welds), ft a = Lengths without weight-coating for any other purpose (anode bracelets, branch connections, etc.), ft The calculated weight Jcalc of weight-coated joint is:
January 1990
H-8
Chevron Corporation
Pipeline Manual
Appendix H
Jcalc = L Wp + (L − 2h − a) Wc (Eq. H-3)
where Wc is based on specified concrete density and thickness to give a specified weight per lineal foot, and L, h, and a are as indicated above. The value for Wp can either be calculated for the pipe steel plus the protective coating, or based on actual weights P and lengths L. This calculated weight can then be compared with the measured weight J. The approximate submerged weight W′s of the joint without accounting for water absorption can be calculated as follows: J – ( 2h + a )W p W′ s = ------------------------------------- – 0.00545 ρ w D c2 L – ( 2h + a ) (Eq. H-4)
and the approximate concrete density as follows: J – L ⋅ Wp 1 ρ c = ----------------------------- × ----------------------------------------L – ( 2h + a ) 0.00545 D 2 – A c
p
(Eq. H-5)
Scales for weighing the weight-coated joints should be calibrated and certified before start of weight-coating and, for large orders, should be checked periodically. Calculations to be made will depend upon the tolerances set for a particular design and construction method. Data from calculations can be used to adjust concrete thickness and/or density during the day if the applicator is set up to respond promptly. Accurate records of the measured data and calculations should be made available to the construction contractor and Company field engineers.
H9.0
Precast Concrete Weights Bolt-on precast concrete weights may be useful: •
For shorter sections of pipeline, such as waterway crossings
•
In muskeg or swampy terrain, where additional weighting is needed for intermittent lengths but can only be determined during construction
•
In locales where continuous concrete coatings are not available or are uneconomic
The spacing between weights can be determined using the submerged weight of each precast unit. If the line is to be installed by a bottom-pull method, special measures should be taken so that the weights do not move along the pipe as the pipe is dragged over the bottom, and that the drag forces on the weights do not
Chevron Corporation
H-9
January 1990
Appendix H
Pipeline Manual
damage the protective coating. Because of this, continuous weight-coating is preferable. For buried lines crossing seasonally flooded ground where construction is done during the dry season, “set-on” pre-cast weights can be used, carefully placed in position over the pipe, followed by backfilling. Additional protection should be provided to prevent damage to the protective coating under the precast weights, usually “rock-shield” or equivalent heavy flexible padding. Some precast weights have a felt or burlap shield cast into their interior surfaces.
January 1990
H-10
Chevron Corporation
Appendix I.
Calculation of Bending Stress in Buried Pressurized Pipeline Due to External Loads
Abstract This appendix discusses the calculation of bending stress in buried pressurized pipelines due to external loads. It is based on API (American Petroleum Institute) Recommended Practice 1102 (November 1981) and includes the most recent design criteria and technology and the extensive knowledge and experiences from past projects. Contents
Chevron Corporation
Page
I1.0
Introduction
I-2
I2.0
Nomenclature
I-2
I3.0
General Concepts
I-3
I4.0
Deflection and Bending Moment Parameters, Kb, Kz
I-4
I5.0
Total Vertical Load on the Pipe
I-5
I6.0
Effect of Side Soil Pressure
I-13
I7.0
Examples
I-13
I8.0
References
I-19
I-1
November 1994
Appendix I
I1.0
Pipeline Manual
Introduction This appendix can be used to calculate bending stress in buried-pressurized pipelines due to external loads. Specifically, this appendix should be used to determine added stresses in existing buried pipelines due to loadings from vehicles and construction cranes. The calculated stress must then be combined with the tensile hoop stress due to internal pressure and compared to applicable stress values. The procedure used in this appendix is based on API Recommended Practice 1102 for Liquid Petroleum Pipelines Crossing Railroads and Highways. In 1968, API RP 1102 incorporated data on uncased-carrier pipes and on casing design, and the performance of uncased-carrier pipes under dead and live loads as well as internal pressures. Extensive computer analysis was performed using M. G. Spangler’s Iowa Formula to determine the stress in uncased-carrier pipes and the wall thickness of casing pipes in instances where casing pipes are required. Note that external loads on flexible pipes can cause failure only by buckling and not by overstress. Buckling occurs when the vertical diameter has undergone an 18% 22% deflection. Failure by buckling does not result in rupture of the pipe wall, although the metal may be stressed far beyond its elastic limit. API RP 1102 has based its design criteria on a maximum vertical deflection of 3% of the vertical diameter. Measurement of actual installed casings and carrier pipes using API RP 1102 design criteria demonstrate that the Iowa Formula is very conservative, and, in most instances the measured long-term vertical deflection has been 0.65% or less of the vertical diameter. The performance of carrier pipes in uncased crossings and casings installed since 1934 (which have been operated in accordance with API Codes 26 and 1102, and API RP 1102) has been excellent. There is no known occurrence in the petroleum industry of a structural failure due to imposed earth and live loads on a carrier pipe or casing under a railroad or highway. Pipeline company reports to the U.S. Department of Transportation in compliance with CFR 49 Part 195 corroborate this record.
I2.0
Nomenclature S = stress due to external loads in psi p = internal pressure in psi r = outside radius in inches t = wall thickness in inches E = modules of elasticity of steel (30 x 106 psi) Kb = bending moment parameter (no unit, see Section I4.0) Kz = deflection parameter (no unit, see Section I4.0)
November 1994
I-2
Chevron Corporation
Pipeline Manual
Appendix I
W = total vertical load (including dead load, live load, and impact) in pounds per inch of length of pipe (discussed in more detail in a following section)
I3.0
General Concepts The following conditions occur when a circular pipe is exposed to both internal pressure and an external load: •
Fig. I-1
The pipe will assume an elliptical shape. (The pipe deflects an amount (∆x) under the influence of external loads and assumes an elliptical shape with the major axis horizontal and the minor axis vertical see Figure I-1).
Deflections of steel pipe under various conditions of external load and internal pressures. (a) No external load, no internal pressure; (b) external load only, no internal pressure; (c) external load plus internal pressure.
•
When internal pressure is introduced into the pipe, the pipe will partially return to its original shape.
•
The excess internal vertical pressure against the upper half of the pipe opposes the vertical load, combines with the resilience in the pipe, and resists the external load.
Therefore, pipe equilibrium will be maintained (stabilized as an ellipse) if the sum of the vertical excess pressure and pipe resilience is equal to the external load. The bending stresses in the pipe wall are less than the stresses due to the external load alone, and these bending stresses are assumed to be algebraically additive to the tensile hoop stress from internal pressure.
Chevron Corporation
I-3
November 1994
Appendix I
Pipeline Manual
The tensile stress at the bottom of the pipe due to the external loads (bending stresses) is 6K b W Ert S = ----------------------------------Et 3 + 24K z pr 3 Remember that this stress (S) should be combined with the tensile hoop stress due to internal pressure and compared to applicable allowable stress values. For applicable allowable stress values, see ANSI/ASME Code B31.4 Section 402.3.1 for oil lines and ANSI/ASME Code B1.8, Table 841.15A for gas transmission lines. (See Section 447 of the Pipeline Manual for a more detailed discussion.) The next section discusses in detail the methodology for calculating bending stress in buried pipelines. For specific examples, skip to Section I7.0.
I4.0
Deflection and Bending Moment Parameters, Kb, Kz The load, W, is assumed to be uniformly distributed over the top half of the pipe. The distribution of the bottom reaction depends to a great extent upon the manner of construction and installation of the pipe. For example, if a pipe is laid in an open ditch and the bottom has not been shaped to fit the contour of the pipe, the reaction distribution will depend largely upon the extent to which the pipe settles into the soil. In all probability, the reaction will not be distributed over a width greater than 30 degrees (see Figure I-2) and, in unyielding soil, this may be considerably less. Fig. I-2
November 1994
Definition of α, Width of Uniform Reaction in Degrees
I-4
Chevron Corporation
Pipeline Manual
Appendix I
On the other hand, a pipe installed in a bored hole that is not much larger in diameter than the pipe will develop a much wider bedding, probably as much as 120 degrees. Figure I-3 lists values for Kz (deflection parameter) and Kb (bending moment parameter) for a load distribution which is uniform over the top half of the pipe and a bottom reaction distributed over various bottom widths. That is, Kz and Kb depend on α. Fig. I-3
Deflection and bending moment parameters for circular pipe with load uniformly distributed over top 180 deg and bottom reaction distributed over various widths.
Width of Uniform Reaction deg
I5.0
Parameters Deflection Kz
Moment Kb
Description
0
0.110
0.294
Pipe placed on a flat surface without any attempt to shape the bedding to fit the contour of the pipe.
30
0.108
0.235
Pipe laid in an open ditch in which the bottom has not been shaped to fit the contour of the pipe.
60
0.103
0.189
Bedding is preshaped to fit the pipe over a width of 60°.
90
0.096
0.157
Bedding is preshaped to fit the pipe over a width of 90°.
120
0.089
0.138
Pipe installed in a bored hole that is not much greater in diameter than the pipe.
Total Vertical Load on the Pipe The total vertical load on a pipe, W, equals the earth load, the traffic or construction loads (such as cranes), plus impact transmitted through the soil to the pipe.
I5.1
Earth Load The prism of soil between the pipe and the embankment grade tends to settle downward. The load on the pipe then equals the weight of the overlying prism of soil minus the upward shear or friction forces which are generated along the sides of the ditch (see Figure I-4). The maximum load is calculated by the equation: Wearth = CdwBd2 where: Wearth = earth load on pipe in pounds per foot of length of pipe. w = the unit weight of soil in pounds per cubic foot. Bd = the width of ditch in feet at the elevation of the top of the pipe.
Chevron Corporation
I-5
November 1994
Appendix I
Pipeline Manual
Cd = a load coefficient. The load coefficient is a function of the ratio H/Bd, where H is the height of fill above the top of the pipe. Cd is also a function of µ, the coefficient of internal friction of the soil backfill, and of µ′, the coefficient of friction between the backfill and the sides of the ditch. Five different classes of soil ranging from sand and gravel to saturated clay can be used to determine Cd (see Figure I-5). Designs for pipe in ditches are usually based on the ordinary maximum for clay class (see Figure I-6). For this class, Kµ = Kµ′ = 0.130, where K is the ratio of lateral to vertical pressure at the sides of the ditch. Later on, two example problems will be completed to illustrate this information. Fig. I-4
I5.2
Cross Section of Pipe and Soil (Courtesy of the Journal of the Pipeline Division, Proceedings of the American Society of Civil Engineers, October 1968)
Surface Loads Trucks or construction cranes may contribute to the stress in the pipe. A typical surface load in a refinery or chemical plant could come from a truck load or a construction crane load.
5.2.1 Vehicle Wheel Loads Truck wheel loads may be considered as concentrated point loads applied at the surface, and the effect of this wheel load on a buried pipe can be represented by the equation
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Appendix I
WT = 0.33IcCTP where: WT = the average load on the pipe due to truck wheel load in pounds per foot of length of pipe Ic = the impact factor CT = the load coefficient P = the truck wheel load in pounds
Fig. I-5
Values of Cd for Different Soil Classes (Courtesy of the Journal of the Pipeline Division, Proceedings of the American Society of Civil Engineers, October 1968)
Impact factor. The impact factor, Ic, is equal to unity when the vehicle wheel load is static. For moving loads, Ic depends upon the speed of the vehicle, its vibratory action, and, most importantly, the roughness of the roadway surface. It is independent of the depth of cover over a pipe. Suggested values of the impact factor for trucks operating on roadways paved with flexible-type surface or unpaved roadways range from 1.5 to 2.0. Use an impact factor of 1.3 for trucks operating on rigid types of pavement. Load coefficient. The load coefficient, CT, represents the fractional part of the wheel load, P, that is transmitted through the soil overburden to a pipe and is based upon the Boussinesq equation. CT is dependent upon the length and width of the section of pipe under consideration, its depth below the roadway surface, and the position
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Appendix I
Fig. I-6
Pipeline Manual
Values of Cd for the Soil Class of Ordinary Maximum for Clay Backfill (Courtesy of the Journal of the Pipeline Division, Proceedings of the American Society of Civil Engineers, October 1968) H -----Bd 0.2
0.20
H -----Bd 3.2
0.4
2.18
0.38
3.4
2.26
0.6
0.56
3.6
2.34
0.8
0.72
4.0
2.49
1.0
0.88
4.5
2.65
1.2
1.03
5.0
2.80
1.4
1.18
5.5
2.93
1.6
1.30
6.0
3.04
1.8
1.43
7.0
3.22
2.0
1.56
8.0
3.36
2.2
1.68
9.0
3.47
2.4
1.78
10.0
3.56
2.6
1.89
12.0
3.68
2.8
1.99
15.0
3.77
3.0
2.08
∞
3.86
Cd
Cd
of the point of application of the wheel load with respect to the area in plan of the pipe section. The area on which the load is calculated is a horizontal plane through the top of the pipe. Coefficients given in Figures I-7 and I-8 are for loads on a rectangular area, one corner of which lies directly below the applied wheel load as illustrated in Figure I-9. They are functions of the ratios m = X/H and n = Y/H, in which X is onehalf of the pipe diameter and Y is one-half of the dimension of the effective loaded area of the pipe along the length of the pipe, and H is the height of fill in feet above the top of the pipe. Y is the actual length of a segmental section of pipe three feet or less in length. For continuous pipes or those constructed of segmental sections more than three feet in length, Y is defined as the length of pipe over which the average live load produces the same effect on stress or deflection as does the actual load, which is of varying intensity along the pipe. For continuous pipelines, three feet is suggested for use in the design of longer pipe sections. The equation for WT and Figures I-7 and I-8 may be applied to a wide variety of situations with reference to the lateral position of the truck wheel load relative to the projected area of the pipe. The most usual situation is that in which the point of application of load is directly above the center of the pipe. As the coefficients in Figures I-7 and I-8 are applicable only when the point load is directly above one corner of a rectangular load-receiving area, it is necessary to divide the pipe area into four quadrants with their common corner directly beneath the load and then calculate the load on one quadrant (see shaded area in Figure I-9) and multiply by
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Appendix I
four to obtain the total load. A sample problem in Section I7.0 will illustrate this information. Literature is also available that develops design procedures for situations in which the load is not directly above the center of the pipe (see Reference 3). Fig. I-7
Influence Coefficients for Rectangular Areas (1 of 2) (Figure I-7, both 1 and 2 are taken from Soil Engineering, 3rd Edition by Merlin G. Spangler and Richard L.Handy. Copyright 1951, 1960 by Harper & Row, Publishers, Inc. Copyright 1973 by Harper & Row, Publishers, Inc. Reprinted by permission of HarperCollins Publishers, Inc.)
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Appendix I
Fig. I-7
Pipeline Manual
Influence Coefficients for Rectangular Areas (2 of 2) (Figure I-7, both 1 and 2 are taken from Soil Engineering, 3rd Edition by Merlin G. Spangler and Richard L.Handy. Copyright 1951, 1960 by Harper & Row, Publishers, Inc. Copyright 1973 by Harper & Row, Publishers, Inc. Reprinted by permission of HarperCollins Publishers, Inc.)
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Fig. I-8
Appendix I
Influence Coefficients for Rectangular Areas (This figure is taken from Soil Engineering, 3rd Edition by Merlin G. Spangler and Richard L. Handy. Copyright 1951, 1960 by Harper & Row, Publishers, Inc. Copyright 1973 by Harper & Row, Publishers, Inc. Reprinted by permission of HarperCollins Publishers, Inc.)
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Appendix I
Pipeline Manual
Fig. I-9
Concentrated Truck Wheel Load Transmitted to Underground Pipe (Courtesy of Journal of the AWWA, August 1964)
5.2.2 Crane Loads Like truck loads, the load that a construction crane imparts on a buried pipe may be estimated by the Boussinesq equation. The crane load may be treated as a uniformly distributed load over an area equal to the crane track as illustrated in Figure I-10. Fig. I-10
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Crane Track Load Transmitted to Underground Pipe (Courtesy of Journal of the AWWA, August 1964)
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Appendix I
The unit load on a pipe at a point directly beneath a corner of a uniformly loaded rectangular area is σz = CG G C
is the unit applied load applied at the base of the crane track in pounds per square foot; is the influence coefficient, a function of the ratios m = X/H and n = Y/H, values for which are given in Figures I-7 and I-8;
in which σz is the unit load on the pipe at a point directly beneath a corner of the loaded area, in pounds per square foot; X
is one-half the length of loaded area in feet;
Y
is one-half the width of loaded area in feet; and
H
is the height of fill from the top of the pipe to the base of the crane track.
The calculation here is the same as for truck wheel load. To use the σz equation, divide the loaded surface area into four quadrants with their common corner directly above the center of the pipe below. The value of the unit load on the pipe is determined for one quadrant, then multiplied by four to obtain the total unit load. To obtain the load-per-unit length, this unit load is multiplied by the outside diameter of the pipe. A sample problem is shown in 7.0 to illustrate this information. Also, there is literature available that develops procedures for cases where the load is not directly above the center of the pipe (see Reference 3).
I6.0
Effect of Side Soil Pressure Note that the combination of bending and hoop stress does not take side soil pressure into account and is limited to pipes in open ditches that are backfilled (without compacting the soil at the sides) and to bored-in-place pipe (before the soil has moved into tight contact with the sides of the pipe). This probably results in stress numbers that are too high for installations where the side soil is well compacted. However, it is recommended that we use the conservative approach, as outlined in this Appendix.
I7.0
Examples The following two examples illustrate the procedure for determining bending stresses from external loads. Remember, each problem is unique.
I7.1
H 20-44 Truck — Example 1 Objective: Calculate the stress in a buried 28 inch carbon steel crude line pipe due to the combined effect of the earth load and crossing it with a H-20 truck. Other information is: wall thickness is 0.375 inch, internal pressure is 225 psi, and height
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Appendix I
Pipeline Manual
of fill above the top of the pipe is three feet. Also, the width of uniform reaction (α) is 30°. We will solve the following equation: 6K b WErt S = -----------------------------------Et 3 + 24Kzpr 3 Therefore, (from Figure I-3) Kb = 0.235 Kz = 0.108 E = 30 x 106 psi (carbon steel pipe) r = 14 inches (outside radius of pipe) t = 0.375 inches (wall thickness) p = 225 psi (internal pressure in psi) W = total vertical load Wearth = CdwBw2 w = 120 pounds per cubic foot (ordinary soil) Bd = 34 inches (in this example, the trench is 6 inches wider than the outside diameter of the pipe) Cd
with H = 36 inches (note that in API 1102, Recommended Practice for Liquid Petroleum Pipelines Crossing Railroads and Highways, it states that pipes under highway surface shall be installed with a minimum cover of 4 feet) and H 36 with ------ = ------ = 1.06 Bd 34
Cd = 0.93 (from Figure I-6) 2 34 in lb Wearth = ( 0.93 ) 120 -----3- ------------- ft 12 in ---ft Wearth = CdwBw2 Wearth = 896 lb/foot of length of pipe Next, we need to determine the vertical load due to the H 20-44 truck loading. The point load for a H 20-44 track is 16,000 lbs. Use the equation, WT = 0.33 IcCTP
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Appendix I
Ic = 1.8 (Impact Factor, see Section 531) P = 16,000 lbs CT
(see Figure I-9)
3 In this example, X = 1.17 ft. (width), Y = --- = 1.5 feet (length), and H = 3 2 feet. X 1.17 Y 1.5 Therefore, m = ---- = ---------- = 0.39and n = ---- = ------- = 0.50 . H 3 H 3 Using Figure I-7 or I-8, CT = 0.071 WT = 0.33 IC CT P 0.33 = --------------------------------------------------- ( 1.8 ) ( 0.071 ) ( 16, 000 lbs. ) foot of length of pipe lbs WT = 675 --------------------------------------------------foot of length of pipe This calculates the load on one quadrant. We need to multiply by four to obtain the total load. WT = 4 x 675 = 2700. See Figure I-9. W = Wearth + WT lbs ft W = ( 896 + 2700 ) ------- ------------------------- ft 12 inches lbs W = 300 ------in 6K b W Ert S = ----------------------------------Et 3 + 24K z pr 3 lbs lb 6 ( .235 ) 300 ------- 30 × 10 6 ------2- ( 14 in. ) ( .375 in. ) in in S = ------------------------------------------------------------------------------------------------------------------------------lb lb 30 × 10 6 ------ ( .375in ) 3 + 24 ( .108 ) 225 ------2- ( 14in ) 3 2 in in lb 2 66,622 × 10 6 ------in S = --------------------------------------------------------------------------------------------------6 ( 1.58 × 10 )lb – in + ( 1.60 × 10 6 )lb – in
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Pipeline Manual
lb 2 66, 622 × 10 6 ------in S = -----------------------------------------6 3.18 × 10 lb – in S = 21, 000 psi Therefore, the stress due to the external loads of the earth and the moving H 20-44 truck is 21,000 psi. Remember, that this stress (S) should be added to the tensile hoop stress due to internal pressure and compared to applicable allowable stress values (see Sections 442 and 443 of the Pipeline Manual for calculation of the hoop stress and allowable stress values).
I7.2
Crawler Crane — Example 2 Suppose you have an existing 34 inch diameter carbon steel crude line and you wanted to determine if you could make a 75,000 lbs. lift with a crawler crane weighing 222,000 lbs. sitting on top of the crude line. Other information is: wall thickness is 0.5 inch, internal pressure is 250 psi, and height of fill above the top of the pipe is 4 feet. Also, the bedding was preshaped to fit the pipe over a width of 60°. Fig. I-11
Crawler Crane
This example will take you through the procedure to determine the bending stress due to external loads. We will solve the following equation.
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Appendix I
6K b W Ert S = ----------------------------------Et 3 + 24K z pr 3 From Figure I-3 and with α = 60°, Kb = 0.189 Kz = 0.103 E = 30 x 106 psi (carbon steel pipe) r = 17 inches (outside radius of pipe) t = 0.5 inch (wall thickness) p = 250 psi (internal pressure in psi) W = total vertical load Wearth = CdwBw2 w = 120 pounds per cubic feet (ordinary soil) Bd = 40 inches (in this example, the trench is 6 inches wider than the outside diameter of the pipe) Cd H 48 with H = 48 inches and with ------ = ------ = 1.2 Bd 40 Cd = 1.03 from Figure I-6 Wearth = C d w B d2 2 lb 40 in = ( 1.03 ) 120 -----3- ------------ ft 12 in ---ft lb = 1370 -------------------------ft of length Next, we need to determine the vertical load due to the crane and the lifted load. Use the equation, σz = CG
Weight of crane = 220,000 lbs Lifted load = 75,000 lbs
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Pipeline Manual
(Impact factor)(Lifted Load) = (1.5)(75,000 lbs) = 113,000 lbs Total Load = 113,000 +220,000 333,000 lbs. Crane has 2 tracks, therefore, 330, 000 lbs total load in our example is ------------------------------ = 165,000 lbs 2 In terms of pressure, 165, 000 lbs G = --------------------------------------------------------------------------------------------------------(width of crane track)(length of crane track) 165, 000 lb = ---------------------------------in 38 ------------ ( 20 ft ) 12 G = 2,605 psf To determine C, 38 Y = ------ = 19 inches 2 in 20 ft × 12 ----ft X = ----------------------------- = 120 inches 2 H = 48 inches Therefore, X 120 m = ---- = --------- = 2.5 H 48 Y 19 n = ---- = ------ = 0.40 H 48 Using Figure I-7, C = 0.115 σz = CG = (0.115)(2,605 psf) = 300 psf We need to multiply this by 4 to account for the four quadrants. See Figure I-10 shown on the following page. σz = (4) (300) = 1,200 psf
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Appendix I
Our pipe is 34 inches in diameter. Therefore, the load per foot of length, lb 34 in σz = 1200 -----2- ----------- ft 12 in ---ft σz = 3,400 lb/ft
lb lb lb W = W earth + σ z = 3, 400 ----- + 1, 370 ----- = 4, 770 ---- ft ft ft 4, 770 lb ----- ft lb W = ------------------------- = 398 --------------------------------------------------inch of length of pipe in 12 ----ft Now 6K b WErt S = ----------------------------------Et 3 + 24K z pr 3 lb lb 6 ( 0.189 ) 398 ----- 30 × 10 6 ------2- ( 17 in. ) ( 0.5 in. ) in in = --------------------------------------------------------------------------------------------------------------------------------lb lb 30 × 10 6 ------ ( .5 in ) 3 + ( 24 ) ( .103 ) 250 ------2- ( 17 in ) 3 2 in in lb 2 115, 089 × 10 6 ------in = ------------------------------------------6 6.79 × 10 lb-in S=16,960 psi Therefore, the stress due to the external loads of the earth and the crane is 18,400 psi. Remember, that this stress (S) should be combined with the tensile hoop stress due to the internal pressure and compared to the applicable allowable stress values (see Sections 442 and 443 of the Pipeline Manual for calculation of the hoop stress and allowable stress values.)
I8.0
References
Chevron Corporation
1.
API Recommended Practice 1102, Liquid Petroleum Pipelines Crossing Railroads and Highways, Fifth Edition, November 1981.
2.
Merlin G. Spangler, F. ASCE, “Structural Design of Pipeline Casing Pipes,” Journal of the Pipeline Division, Proceedings of the American Society of Civil Engineers, October 1968, pages 137-154.
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Appendix I
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Pipeline Manual
3.
Merlin G. Spangler, Richard L. Handy, Soil Engineering, Third Edition, Intext Educational Publishers, New York, 1973, Pages 372-377 and 717-730.
4.
Merlin G. Spangler, “Pipeline Crossings Under Railroads and Highways,” Journal of the AWWA, August 1964, Pages 1029-1046.
I-20
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References The references listed here relate to the design and construction of pipelines. Some are referenced by the Company Specifications or by the Industry Standards included in this manual. Some are textbooks or similar materials which provide additional information. This is not a complete list. Further references are often found in the individual Industry Standards. The dates shown are the latest known at the time of publication. The latest edition of any Industry Standard should be used for new designs and modifications.
Publications — CUSA Western Region Producing Department PDP-1-6
Ordering Material.
PDP-1-7.
Trial and Test Procedures.
PDP-1-8.
Failed and Defective Material.
PDP-1-9.
Guide for Construction Contracts.
PDP-1-14.
Equipment Inspection.
PDP-3-200.
Piping Practices.
PDP-11-2.
Safety and Relief Valve Practices.
PRO-8.
Safe Practice Regulations.
SF-1003.
General Pipeline and Interconnecting Lines (ICL).
American National Standards Institute (ANSI), 1430 Broadway, New York 10018
Chevron Corporation
B.1.1.
Unified Inch Screw Threads (UN and UNR Thread Form).
B1.201-1983.
Pipe Threads, General Purpose (Inch).
B16.1.
125# Cast Iron Flanges and Flanged Valves.
B16.3.
150# Malleable Iron Threaded Fittings.
B16.5.
Pipe Flanges and Flanged Fittings.
B16.9.
Factory-Made Wrought Steel Buttwelding Fittings.
B16.10.
Face-to-Face and End-to-End Dimensions of Valves.
B16.11.
Forged Steel Fittings, Socket-Welding and Threaded.
B16.19.
300# Malleable Iron Screwed Fittings.
Reference-1
December 1989
References
Pipeline Manual
B16.20.
Ring Joint Gaskets and Grooves for Steel Pipe Flanges.
B16.21.
Nonmetallic Flat Gaskets for Pipe Flanges.
B16.28.
Wrought Steel Buttwelding Short Radius Elbows and Returns.
B16.34.
Steel Valves - Flanged and Buttwelding End.
B31.1.
Power Piping.
B31.2.
Fuel Gas Piping.
B31.3.
Chemical Plant and Petroleum Refinery Piping.
B31.4.
Liquid Petroleum Transportation Piping Systems.
B31.5.
Refrigeration Piping.
B31.8.
Gas Transmission and Distribution Piping Systems.
B36.10.
Welded and Seamless Wrought Steel Pipe.
American Society of Mechanical Engineers (ANSI/ASME), United Engineering Center, 345 East Forty-Seventh Street, New York, NY 10017 Boiler and Pressure Vessel Code Section V.
Nondestructive Examination, 1986.
Section VIII.
Pressure Vessels, Division 1, 1986.
Section VIII.
Pressure Vessels, Division 2, 1986.
Section IX.
Welding and Brazing Qualifications, 1986.
American Petroleum Institute (API), 1220 L Street, N. W. Washington, D.C. 20005
December 1989
SPEC 5A.
Casing Tubing and Drill Pipe.
SPEC 5L.
Specification for Line Pipe.
SPEC 5LC.
Specification for Corrosion Resistant Line Pipe.
SPEC 6A.
Specification for Wellhead Equipment.
SPEC 6AB.
30,000 PSI Flanged Wellhead Equipment.
SPEC 6D.
Large Diameter Pipeline and Producing Field Valves.
SPEC 6FA.
Fire Tests for Valves.
RP 5L1.
Recommended Practice for Railroad Transportation of Line Pipe.
RP 5L5.
Recommended Practice for Marine Transportation of Line Pipe.
RP 5L6.
Recommended Practice for Transportation of Line Pipe on Inland Waterways.
Reference-2
Chevron Corporation
Pipeline Manual
References
RP 5L8.
Recommended Practice for Field Inspection of New Line Pipe.
STD 526.
Flanged Steel Safety Relief Valves.
STD 590.
Steel Line Blanks.
STD 598.
Valve Inspection and Test.
STD 599.
Steel and Ductile Iron Plug Valves.
STD 600.
Steel Gate Valves, Flanged and Buttwelding Ends.
STD 601.
Metallic Gaskets for Raised-Face Pipe Flanges and Flanged Connections (Double-Jacketed, Corrugated and Spiral Wound).
STD 602.
Carbon Steel Gate Valves for Refinery Use (Compact Design).
STD 604.
Ductile Iron Gate Valves, Flanged Ends.
STD 605.
Large-Diameter Carbon Steel Flanges.
STD 607.
Fire Test for Soft-Seated Ball Valves.
STD 609.
Butterfly Valves.
Publication 2201-1978, Procedures for Welding or Hot tapping on Equipment Containing Flammables
American Society for Non-destructive Testing (ASNT) ASNT Recommended Practice No. SNT-TC-1A, 1984, Nondestructive Testing Personnel Qualification and Certification
American Society for Testing and Materials (ASTM, 1916 Race St., Philadelphia, PA 19103
Chevron Corporation
A 53.
Specification for Welded and Seamless Steel Pipe.
A 105.
Specification for Forgings, Carbon Steel, for Piping Components.
A 106.
Specification for Seamless Carbon Steel Pipe for High-Temperature Service.
A 120.
Specification for Pipe, Steel, Black and Hot-dipped, Zinc-Coated (Galvanized) Welded and Seamless for Ordinary Uses.
A 181.
Forged or Rolled Steel Pipe Flanges, Forged Fittings, and Valves and Parts for General Services.
A 182.
Specification for Forged or Rolled Alloy-Steel Pipe Flanged, forged Fittings, and Valves and Parts for High-Temperature Service.
A 193.
Specification for Alloy-Steel and Stainless Steel Bolting Materials for High-Temperature Service.
Reference-3
December 1989
References
Pipeline Manual
A 194.
Specification for Carbon and Alloy Steel Nuts for Bolts for High Pressure High Temperature Service.
A 216.
Specification for Carbon-Steel castings Suitable for fusion Welding for High-Temperature Service.
A 234.
Specification for Piping Fittings of Wrought Carbon Steel and Alloy Steel for Moderate and Elevated Temperature.
A 285.
Pressure Vessel Plate, Carbon Steel Low and Intermediate Tensile Strengths.
A 312.
Specification for Seamless and Welded Austenitic Stainless Steel Pipe.
A 350.
Specification for Forgings, Carbon and Low-Alloy Steel, Requiring Notch Toughness Testing for Piping Components.
A 351.
Specification for Austenitic Steel Castings for High-Temperature Service.
A 370-77.
Mechanical Testing of Steel Products.
A 395.
Specification for Ferritic Ductile Iron Pressure-Retaining Castings for Use at Elevated Temperatures.
A 403.
Specification for Wrought Austenitic Stainless Steel Piping Fittings.
A 751-82.
Chemical Analysis of Steel Products.
B 62.
Specification for Wrought austenitic Stainless Steel Piping Fittings.
E 18-84.
Rockwell Hardness and Rockwell Superficial Hardness of Metallic Materials.
E 23-82.
Notched Bar Impact Testing of Metallic Materials.
E 29-67.
(Reapproved 1980), Indicating Which Places of Figures Are to be Considered Significant in Specified Limiting Values.
E 92-82
Vickers Hardness of Metallic Materials.
E 142-83.
Controlling Quality of Radiographic Testing.
British Standards Institute (BSI) BS 5762:1979. Methods for crack opening displacement (COD) testing. PD 6493:1979. Guidance on some methods for the derivation of acceptance levels for defects in fusion welded joints.
Canadian Gas Association (CGA) OCC-1-1985.
December 1989
Recommended Practice for the Control of External Corrosion on Buried or Submerged Metallic Structures and Piping Systems.
Reference-4
Chevron Corporation
Pipeline Manual
References
OCC-3-1981.
Recommended Practice for the Mitigation of Alternating Current.
Canadian General Standards Board (CGSB) 48-GP-4M-1978
(Amended 1984) Certification of Non-destructive Testing Personnel (Industrial Radiography Method)
48-GP-7M-1979.
(Amended 1984) Certification of Non-destructive Testing Personnel (Industrial Ultrasonic Method).
Canadian Standards Association (CSA) CAN3-Z183-M86.
Oil Pipeline Systems.
CAN/CSA-Z184-M1983.
Gas Pipeline Systems.
CAN3-Z234.1-79.
Canadian Metric Practice Guide; Canadian Electric Code, Part III.
CAN3-Z245.1-M86.
Steel Line Pipe.
CAN3-Z299.1-85.
Quality Assurance Program - Category 1.
CAN3-Z299.2-85.
Quality Assurance Program - Category 2.
CAN3-Z299.3-85.
Quality Assurance Program - Category 3.
CAN3-Z299.4-85.
Quality Assurance Program - Category 4.
W178-1973.
Qualification Code for Welding Inspection Organizations.
C22.3 No. 4-1974(R1980). Control of Electro-chemical Corrosion of Underground Metallic Structures. W48.1-M1980.Mild Steel Covered Arc-Welding Electrodes. W48.3-M1982.Low-Alloy Steel Arc-Welding Electrodes.
Manufactures Standardization Society of the Valve and Fittings Industry (MSS), Inc., 127 Park Street N.E., Vienna, Virginia 22180 SP-25-1978 (R 1983).
Standard Marking System for Valves, Fittings, Flanges, and Unions.
SP-44-1985.
Steel Pipe Line Flanges.
SP-49.
Forged Steel Screwed Fittings.
National Association of Corrosion Engineers (NACE) MR-01-75-1980
Chevron Corporation
(Rev. 1984).Sulfide Stress Cracking Resistant Metallic Material for Oil Field Equipment.
Reference-5
December 1989
References
Pipeline Manual
RP-04-75.
Selection of Metallic Materials to be Used in All Phases of Water Handling for Injection into Oil Bearing Formations.
National Fire Protection Association (NFPA) NFPA 15.Water Spray Fixed Systems. NFPA 20.Fire Water Pumps. NFPA 30-1984.Flammable and Combustible Liquids Code.
U.S. Government Standards Occupational Safety and Health Standards, Department of Labor, Occupational Safety and Health Administration (OSHA), Washington, DC 20210 (The Standards and Revisions are Published in the Federal Register).
Publications - United States Minerals Management Service (Embraces API)
Publications - State of California - Division of Industrial Safety - Safety Orders Compressed Air Safety Orders Pressure Vessel/Boiler, Safety Orders Petroleum Safety Orders - Drilling and Production Petroleum Safety Orders - Refining, Transportation and Handling
Books Theory of Elasticity, Timoshenko and Goodier, 3rd Edition, McGraw-Hill Book Company, 1970. Piping Stress Calculations Simplified, S. W. Spielvogel, 5th Edition, 1961. Designing of Piping for Flexibility with Flex-Analysis Charts, 5th Edition, Power Piping Company, 1970. Piping System Analysis and Design Seminar, AAA Technology and Specialties Co., Inc., 1981. Piping Handbook, Salion Crocker, 5th Edition, McGraw-Hill Book Company, 1967. Design of Piping Systems, The M. W. Kellogg Company, John Wiley and Sons. Piping Systems Drafting and Design, Louis Gary Larait, Prentice Hall, Inc., 1981.
December 1989
Reference-6
Chevron Corporation
