Hdd

Catalog No. L51730

Installation of Pipelines by Horizontal Directional Drilling An Engineering Design Guide Contract PR-227-9424

Prepared for the Design Applications Supervisory Committee (Off/On Shore Supervisory Committee) Pipeline Research Council International, Inc.

Prepared by the following Research Agencies: J.D. Hair and Associates, Inc. Louis J. Capozzi & Associates, Inc. Stress Engineering Services, Inc.

Author: Paul D. Watson

Publication Date: April 15, 1995

“This report is furnished to Pipeline Research Council International, Inc. (PRCI) under the terms of PRCI PR-227-9424, between PRCI and J.D. Hair and Associates, Inc., Louis J. Capozzi & Associates, Inc., Stress Engineering Services, Inc.. The contents of this report are published as received from J.D. Hair and Associates, Inc., Louis J. Capozzi & Associates, Inc., Stress Engineering Services, Inc.. The opinions, findings, and conclusions expressed in the report are those of the authors and not necessarily those those of PRCI, PRCI , its member comp companies, anies, or their representatives. Publication Publication and dissemination of this report by PRCI should not be considered an endorsement by PRCI or J.D. Hair and Associates, Inc., Louis J. Capozzi & Associates, Inc., Stress Engineering Services, Inc., or the accuracy or validity of any opinions, findings, or conclusions expressed herein. In publishing this report, PRCI makes no warranty or representation, expressed or implied, with respect to the accuracy, completeness, usefulness, or fitness for purpose of the information contained herein, or that the use of any information, method, process, or apparatus apparatus disclosed disclosed in this report may may not infringe infringe on private privately ly owned rights. rights. PRCI PR CI assumes no liability with respect to the use of , or for damages resulting from the use of, any information, method, process, or apparatus disclosed in this report. The text of this publication, or any part thereof, may not be reproduced or transmitted in any form by any means, electronic or mechanical, including photocopying, recording, storage in an information retrieval system, or otherwise, without the prior, written approval of PRCI.”

Pipeline Research Council International Catalog No. L51730 Price: $995 Copyrigh Copyright, t, 1995 199 5 All Rights Reserved by Pipeline Research Council International, Inc. PRCI Reports are Published by Technical Toolboxes, Inc. 3801 Kirby Drive, Suite 340 Houston, Houston, Texas 77098 770 98 Tel: 713-630-0505 Fax: 713-630-0560 Email: [email protected]

PIPELINE RESEARCH COUNCIL INTERNATIONAL

G. L. Walker, Pacific Gas Transmission Company (Chairman) E. E. Thomas, Southern Natural Gas Company (Vice Chairman) P. S. Anderson, Foothills Pipe Lines Ltd. R. L. Brown, Natural Gas Pipeline Company of America E. Herløe, Statoil R. C. Hesje, Transportadora de Gas de1 Norte M. C. Hocking, Transcontinental Gas Pipe Line Corp. D. L. Johnson, Enron Operations Corp W. A. Johnson II, El Paso Natural Gas Company D. F. Keprta, ARCO Oil and Gas Company R. E. Keyser, Panhandle Eastern Corporation R. W. Little, Union Gas Limited J. P. Lucido, ANR Pipeline Company H. A. Madariaga, Southern California Gas Company J. K. McDonald, East Australian Pipeline Ltd. D. J. McNiel, Tenneco Gas M. Merrill, BP Pipelines (Alaska) Inc. K. J. Naarding, N. V. Nederlandse Gasunie C. W. Petersen, Exxon Production Research Company D. E. Reid, TransCanada PipeLines, Ltd. P. R. Smullen, Shell Development Company B. J. Sokoloski, CNG Transmission Corporation P. M. Sørensen, Dansk Olie og Naturgas A/S B. C. Sosinski, Consumers Power Company R. J. Turner, NOVA Gas Transmission Ltd. D. C. Walker, Oklahoma Natural Gas Company T. L. Willke, Gas Research Institute K. F. Wrenn, Jr., Columbia Gas Transmission Corp. T. F. Murphy, American Gas Association (PRC Staff) A. G. Cotterman, American Gas Association (PRC Staff)

OFFSHORE AND ONSHORE DESIGN APPLICATIONS SUPERVISORY COMMITTEE

R. E. Keyser, Panhandle Eastern Corporation (Chairman) *D. W. Allen, Shell Development Company *J. A. Barbalich, Tenneco Gas *S. T. Barbas, Exxon Production Research Company *R. L. Barron, Texas Gas Transmission Corp. *L. M. Bums, Colorado Interstate Gas Company T. D. Caldwell, BP Exploration, Inc. J. C. Chao, Exxon Production Research Company G. W. Connors, Union Gas Limited *M. J. Coyne, Shell Oil Company D. A. Degenhardt, Natural Gas Pipeline Co. of America J. P. Dunne, ANR Pipeline Company J. R. Ellwood, Foothills Pipe Lines Ltd. R. W. Gailing, Southern California Gas Company R. E. Hoepner, Transcontinental Gas Pipe Line Corp. W. C. Kazokas, Jr., ARCO Exploration and Production Technology *J. Kleinhans, BP Exploration, Inc. *F. Kopp, Shell Oil Company S. W. Lambright, Consumers Power Company *C. G. Langner, Shell Development Company W. R. Ledbetter, Tenneco Gas C. Lee, Pacific Gas and Electric Company S. Lund, Statoil S. N. Marr, TransCanada PipeLines, Ltd. O. Medina, El Paso Natural Gas Company *J. E. Meyer, Panhandle Eastern Corporation *K. C. Peters, Southern Natural Gas Company M. Rizkalla, NOVA Gas Transmission Ltd. *L. A. Salinas, Tenneco Gas *O. R. Samdal, Statoil J. Spiekhout, N. V. Nederlandse Gasunie J. E. Thygesen, Dansk Olie og Naturgas A/S *R. Verley, Statoil L. D. Walker, Southern Natural Gas Company A. G. Cotterman, American Gas Association (PRC Staff) *Alternate or Ad Hoc Group Member only Special thanks to the following PR-227-9321 ad hoc group members:

R. E. Hoepner, Transcontinental Gas Pipe Line Corp. (Chairman) J. A. Barbalich, Tenneco Gas D. A. Degenhardt, Natural Gas Pipeline Co. of America J. P. Dunne, ANR Pipeline Company R. W. Gailing, Southern California Gas Company J. E. Meyer, Panhandle Eastern Corporation M. Rizkalla, NOVA Gas Transmission Ltd. J. Spiekhout, N. V. Nederlandse Gasunie

Table of Contents

Executive Summary 1. The Horizontal Directional Drilling Process

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Pilot Hole Directional Drilling, 1; Jetting, 3; Downhole Motors, 3; Wash Pipe, 3; Downhole Surveying, 3; Surface Monitoring, 4; Reaming & Pulling Back, 5; Prereaming, 5; Pulling Back, 7; Buoyancy Control, 7. 2. Feasibility Considerations

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Technical Feasibility, 8; Subsurface Soil Material, 9; Contractual Feasibility, 10; Economic Feasibility, 12; Cost Estimating, 12; Estimating Parameters, 12; Shift Cost Summary, 16; Estimate Recap, 18; Owner’s Cost, 18. 3. Site Characterization

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Geological Factors, 21; Topographic and Hydrographic Details, 22; Geotechnical Aspects, 22; Unified Classification System for Soil Type, 22; Soil Condition Parameters, 25; Rock Condition Parameters, 26; Material Strengths, 27; Deformation Potential, 27; Groundwater, 27; Subsurface Stratification, 28; Site Characterization Study Contents, 28; Responsibility for Site Characterization, 28; Definition of the Obstacle, 29; Site Exploration, 29; Surface Survey, 30; Subsurface Survey, 30. 4. General Design Considerations

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Definition of the Obstacle, 32; Drilled Path Design, 32; Definition of Curves, 34; Entry and Exit Points, 34; Entry and Exit Angles, 34; Depth of Cover; 34; Design Radius of Curvature, 35; Directional Accuracy and Tolerances, 35; Pipe Specification, 35; External Pipe Coating, 36; Multiple Line Installation, 36.

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5. Pipe Stress Analysis

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Installation Loads and Stresses, 37; Pulling Load Calculation Method, 38; Drilled Path Analysis, 38; Pulling Loads, 38; Installation Stress Analysis, 45; Individual Loads, 45; Combined Loads, 47; Example Pulling Load Calculation, 48; Example Installation Stress Analysis, 54; Operating Loads and Stresses, 56; Combined Stresses and Limitations, 57; Example Operating Stress Analysis, 58; Spreadsheet - Load and Stress Analysis, 59.

6. Construction Impact

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Workspace, 61; Horizontal Drilling Rig, 61; Pull Section Fabrication, 63; Drilling Fluids, 65; Functions, 66; Composition, 66; Quantity Estimating Calculations, 67; Recommended Disposal Methods, 70; Environmental Impact, 73. 7. Contractual Considerations

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Lump Sum Contracts, 77; Pricing, 77; Unknown Subsurface Condition Risk, 78; Technical Specification, 78; Plan & Profile Drawing, 78; Daywork Contract, 83; Uniform Daywork Bid Sheet, 83; Equipment Failure Risk, 83. 8. Construction Monitoring

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Drilled Path, 87; Construction Staking, 87; Pilot Hole, 87; Directional Drilling Performance, 92; Downhole Survey Calculations, 92; Radius of Curvature Calculations, 94; TruTracker Surface Monitoring System, 95; Asbuilt Error Distribution, 96; Pipe Installation, 96; Pull Section Handling, 96; Buoyancy Control, 96; Coating Integrity, 96; Drilling Fluid Flow, 96. Bibliography Metric “SI” Unit Conversion Table Glossary

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EXECUTIVE SUMMARY

This engineering design guide is the principal product of PRC project PR-227-9424. Its purpose is to serve as a step by step guide for engineers engaged in the evaluation, design, and management of natural gas pipeline construction by Horizontal Directional Drilling (HDD). It is not intended to replace sound engineering judgment in the design process nor can it possibly address every question which might arise in the design of any specific crossing. HDD pipeline design involves sophisticated engineering principles and should be performed under the supervision of a qualified professional engineer. The guide contains eight sections which address the following general topics. 1.

A description of the HDD installation process;

2. Feasibility considerations including the state of the art in HDD, factors which limit its use, and

a method for estimating the detailed cost of HDD installations under various conditions; 3. Components of a site characterization required for HDD design and bidding including geological factors, geotechnical aspects, and field survey requirements; 4. General considerations relative to drilled path design, pipe specification, external pipe coating, and multiple line installation;

5. Methods for analyzing pipe stresses both during installation and under operating conditions including a method for calculating pulling loads involved with pull back; 6. The impact of HDD operations on the environment including a discussion of drilling fluid functions, composition, quantities, and disposal methods; 7. General considerations relative to contract form, unknown subsurface condition risk, technical specifications, design drawings; and 8. Inspection requirements during construction including a detailed discussion of downhole survey calculation methods.

Cost estimating, pipe stress, and drilling fluid quantity calculation methods are presented in a Lotus l-2-3 spreadsheet format and demonstrated with sample problems. A diskette containing spreadsheet tiles is fixed to the inside back cover of the guide. Photographs and sketches have been included where appropriate to illustrate construction operations.

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SECTION 1 - THE HORIZONTAL DIRECTIONAL, DRILLING PROCESS

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SECTION 1 THE HORIZONTAL DIRECTIONAL DRILLING PROCESS

The horizontal directional drilling process represents a significant improvement over traditional cut and cover methods for installing pipelines beneath obstructions, such as rivers or shorelines, which warrant specialized construction attention. In order to take full advantage of the benefits offered by horizontal directional drilling (HDD) and produce designs which can be efficiently executed in the field, design engineers should have a working knowledge of the process. This section presents a general description of the HDD process.

The tools and techniques used in the HDD process are an outgrowth of the oil well drilling industry. The components of a horizontal drilling rig used for pipeline construction are similar to those of an oil well drilling rig with the major exception being that a horizontal drilling rig is equipped with an inclined ramp as opposed to a vertical mast. HDD pilot hole operations are not unlike those involved in drilling a directional oil well. Drill pipe and downhole tools are generally interchangeable and drilling fluid is used throughout the operation to transport drilled spoil, reduce friction, stabilize the hole, etc. Because of these similarities, the process is generally referred to as drilling as opposed to boring. Installation of a pipeline by HDD is generally accomplished in two stages as illustrated in Figure l-l. The first stage consists of directionally drilling a small diameter pilot hole along a designed directional path. The second stage involves enlarging this pilot hole to a diameter which will accommodate the pipeline and pulling the pipeline back into the enlarged hole. Pilot Hole Directional Drilling

Pilot hole directional control is achieved by using a non-rotating drill string with an asymmetrical leading edge. The asymmetry of the leading edge creates a steering bias while the non-rotating aspect of the drill string allows the steering bias to be held in a specific position while drilling. If a change in direction is required, the drill string is rolled so that the direction of bias is the same as the desired change in direction. The direction of bias is referred to as the tool face. Straight progress may be achieved by drilling with a series of offsetting tool face positions. The drill string may also be continually rotated where directional control is not required. Leading edge asymmetry can be accomplished by several methods. Typically, the leading edge will have an angular offset created by a bent sub or bent motor housing. This is illustrated schematically in Figure l-2.

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SECTION 1 - THE HORIZONTAL DIRECTIONAL DRILLING PROCESS

STAGE 1, PILOT HOLE DIRECTIONAL DRILLING HORIZONTAL DRILLING RIG DRILLING FLUID RETURNS

EXIT POINT

DESIGNED DRILLED PATH THEORETICAL ANNULUS GENERAL DIRECTION OF PROGRESS PILOT HOLE DRILLING

STAGE 2, REAMING & PULLING BACK

THEORETICAL ANNULUS GENERAL DIRECTION OF PROGRESS PREREAMING

GENERAL DIRECTION OF PROGRESS PULLING BACK

Figure l-l The HDD Process


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DOWNHOLE MOTOR

BIT

BENT SUB

NON-MAGNETIC COLLAR

Figure 1-2 Bottom Hole Assembly Jetting

It is common in soft soils to achieve drilling progress by hydraulic cutting with a jet nozzle. In this case, the direction of flow from the nozzle can be offset from the central axis of the drill string thereby creating a steering bias. This may be accomplished by blocking selected nozzles on a standard roller cone bit or by custom fabricating a jet deflection bit. If hard spots are encountered, the drill string may be rotated to drill without directional control until the hard spot has been penetrated. Downhole Motors

Downhole mechanical cutting action required for harder soils is provided by downhole hydraulic motors. Downhole hydraulic motors, commonly referred to as mud motors, convert hydraulic energy from drilling mud pumped from the surface to mechanical energy at the bit. This allows for bit rotation without drill string rotation. There are two basic types of mud motors; positive displacement and turbine. Positive displacement motors are typically used in HDD applications. Basically, a positive displacement mud motor consists of a spiralshaped stator containing a sinusoidal shaped rotor. Mud flow through the stator imparts rotation to the rotor which is in turn connected through a linkage to the bit. Wash Pipe

In some cases, a larger diameter wash pipe may be rotated concentrically over the nonrotating steerable drill string. This serves to prevent sticking of the steerable string and allows its tool face to be freely oriented. It also maintains the pilot hole if it becomes necessary to withdraw the steerable string. Downhole Surveying

The actual path of the pilot hole is monitored during drilling by taking periodic readings of the inclination and azimuth of the leading edge. Readings are taken with an instrument,

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commonly referred to as a probe, inserted in a drill collar as close as possible to the drill bit. Transmission of downhole probe survey readings to the surface is generally accomplished throug through h a wire runni running ng insid insidee the drill drill strin string. g. These These readin readings, gs, in conjun conjuncti ction on with with measurements of the distance drilled since the last survey, are used to calculate the horizontal and vertical coordinates along the pilot hole relative to the initial entry point on the surface. Survey calculation methods are discussed in detail in Section 8.

Azimuth readings are taken from the earth’s magnetic field and are subject to interference from downhole tools, drill pipe, and magnetic fields created by adjacent structures. Therefore, the probe must be inserted in a non magnetic collar and positioned in the string so that it is adequately adequately isolated isolated from from downhole downhole tools tools and drill drill pipe. The combination combination of bit, bit, mud motor (if used), subs, survey probe, and non magnetic collars is referred to as the Bottom Hole Hole Assembly Assembly or BHA. BHA. A typical typical bottom bottom hole assemb assembly ly is shown shown as as Figure 1-2. Surface Monitoring

The pilot hole path may also be tracked using a surface monitoring system. Surface monitoring systems determine the location of the probe downhole by taking measurements ® from a grid grid or or point point on the the surfa surface. ce. An example example of this is the TruTrack TruTracker er System. This system uses uses a surface surface coil of known known location location to induce induce a magnetic magnetic field. field. The probe senses senses its location relative to this induced magnetic field and communicates this information to the surface. This is shown schematically in Figure l-3.

KNOWN CORNER LOCATIONS

SURFACE COIL

Figure l-3

TruTracker Surface Monitoring System (TruTracker is a Trademark of Sharewell, Inc.)


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Reaming & PulIing Back

Enlarging the pilot hole is accomplished using either prereaming passes prior to pipe installation or simultaneously during pipe installation. Reaming tools typically consist of a circular array of cutters and drilling fluid jets and are often custom made by contractors for a particular hole size or type of soil. Examples of different types of reaming tools are shown in Figures l-4, l-5, 1-6. Prereaming

Most contractors will opt to preream a pilot hole before attempting to install pipe. For a prereaming pass, reamers attached to the drill string at the exit point are rotated and drawn to the drilling rig thus enlarging the pilot hole. Drill pipe is added behind the reamers as they progress toward the drill rig. This insures that a string of pipe is always maintained in the drilled hole. It is also possible to ream away from the drill rig. In this case, reamers fitted into the drill string at the rig are rotated and thrust away from it.

Figure l-4 44 inch hole opener typically used for rock crossings. (photo courtesy of Specialty Drilling Services)

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Figure l-5 Soft soil flycutter emerging from exit point with pull section attached. (photo courtesy of Michels Pipeline Construction Co.)

Figure 1-6

42 inch barrel reamer typically used in prereamed holes. (photo courtesy of Specialty Drilling Services)


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Pulling Back

Pipe installation is accomplished by attaching the prefabricated pipeline pull section behind a reaming assembly at the exit point and pulling the reaming assembly and pull section back to the drilling rig. This is undertaken after completion of prereaming or, for smaller diameter lines in soft soils, directly after completion of the pilot hole. A swivel is utilized to connect the pull section to the leading reaming assembly to minimize torsion transmitted to the pipe (refer to Figure 1-5). The pull section is supported using some combination of roller stands, pipe handling equipment, or a flotation ditch to minimize tension and prevent damage to the pipe. Buoyancy Control

Uplift forces resulting from the buoyancy of larger diameter lines can be very substantial. High pulling forces may be required to overcome drag resulting from buoyancy uplift. Therefore, contractors will often implement measures to control the buoyancy of pipe 30 inches or over in diameter. The most common method of controlling buoyancy is to fill the pipe with water as it enters the hole. This requires an internal fill line to discharge water at the leading edge of the pull section (after the breakover point). An air line may also be required to break the vacuum which may form at the leading edge as the pull section is pulled up to the rig. The amount of water placed in the pipe is controlled to provide the most advantageous distribution of buoyant forces. Some contractors may choose to establish a constant buoyancy. This can be accomplished by inserting a smaller diameter line into the pull section and filling the smaller line with water. The smaller line is sized to hold the volume of water required per lineal foot to offset the uplift forces. References Microtunneling & Horizontal Directional Drilling, Proceedings of the First Trenchless

Excavation Center (TEC) Symposium, November 13-15, 1990, Houston, Texas. Rotary Drilling, Controlled Directional Drilling, Unit III, Lesson 1, Courtesy, Petroleum

Extension Service (PETEX), The University of Texas at Austin.


SECTION 2 - FEASIBLITY CONSIDERATIONS

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SECTION 2 FEASIBILITY CONSIDERATIONS

Three standards may be used to assess the feasibility of HDD for a given crossing. These are technical, contractual, and economic. First, a crossing is technically feasible if it can be installed using existing tools and techniques regardless of uncertainties surrounding the cost of installation. Second, a crossing is contractually feasible if the cost of installation can be accurately estimated in advance allowing contractors to submit lump sum bids. Third, a crossing is economically feasible if its installation cost is less than the cost of an equivalent construction method. Technical Feasibility

For a pipeline to be installed by HDD, one of two conditions must be achieved downhole. Either an open hole must be cut into the subsurface material to such an extent that installation of a pipeline by the pull back method is possible, or the soil properties must be modified so that it behaves in fluid manner allowing a pipeline to be pulled through it. The possibility of achieving either of these conditions downhole is dependent primarily on subsurface soil conditions. The open hole condition is similar to that achieved in a typical oil well. A cylindrical hole is cut in the subsurface. Drilling fluid flows to the surface in the annulus between the pipe and the hole wall. Drilled spoil is transported in the drilling fluid to the surface. This is generally applicable to rock and cohesive soils. It may also apply to some sandy or silty soils depending on the density of the material, the specific makeup of the coarse fraction, and the binding or structural capacity of the fine fraction. It is probable that loose cohesionless soils will not support an open hole over a long horizontally drilled length. This does not, however, prevent the installation of a pipeline. The mechanical agitation of the reaming tool coupled with the injection of bentonitic drilling fluid will cause the soil to experience a decrease in shear strength. If the resulting shear strength is low enough, the soil will behave in a fluid manner allowing a pipe to be pulled through it. The fluid behavior of loose sands, commonly referred to as quicksand, is defined by geotechnical engineers as liquefaction.

If either an open hole or fluid condition can be achieved downhole and the stresses imposed on the pipe and tooling are not excessive, installation by HDD is technically feasible. The technical feasibility of a proposed HDD installation can be predicted by comparing it to past installations in three basic parameters: drilled length, pipe diameter, and subsurface soil material. These three parameters work in combination to limit what can be achieved at a

SECTION 2 - FEASIBILITY CONSIDERATIONS

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given location. Installations which define the state of the art in length and diameter as of 1994 are presented in Table 2 - 1. Table 2 - l State of the Art Installations as of 1994

Location

Length

Diameter

Soil Material

Date

Wormley Creek Yorktown, VA

5,850 ft. (1,783 m)

10 in. (DN 250)

Alluvial

1994

SB Elizabeth River Norfolk, VA

2,160 ft (658 m)

48 in. (DN 1200)

Alluvial

1993

Limitations with respect to length and diameter are primarily due to limits on the capacity of existing tools and drill pipe. Present technology involves thrusting pipe from the surface to advance a pilot hole. The flexibility of relatively slender drill pipe does not allow an unlimited amount of thrust to be applied. Control of the leading edge diminishes over long lengths. Present technology also involves rotating pipe at the surface to rotate reamers downhole. The capacity of drill pipe for the transmission of torsion is limited. Installation of a 48 inch pipe will typically require completion of a 60 inch reaming pass. While development of new tools and techniques which increase load bearing and energy transmission capacities of drill pipe is possible, economic factors come into play. The market for HDD installation of pipe over longer lengths or larger diameters than those presented in Table 2-l has not been defined. Subsurface Soil Material

While length, diameter, and subsurface soil material work in combination to limit the technical feasibility of an HDD installation, technical feasibility is primarily limited by subsurface soil material. Two material characteristics prevent successful establishment of either an open hole or fluid condition. These are large grain content (i.e. gravel, cobbles) and excessive rock strength and hardness.

Soils consisting principally of coarse grained material present a serious restriction on the feasibility of HDD. Coarse material cannot be readily fluidized by the drilling fluid. Neither is it stable enough to be cut and removed in a drilling fluid stream through an op en hole as is the case in a crossing drilled in competent rock. A boulder or cluster of cobbles will remain in the drilled path and present an obstruction to a bit, reamer, or pipeline. They must be mechanically displaced during hole enlargement. Displacement may be radially outward into voids formed by the entrainment of finer grained (sand and smaller size) material. However, naturally dense, high gravel percentage soils contain little entrainable material and insufficient voids may be developed to permit passage by larger diameter reamers or pipe. Coarse material may also migrate to low spots on the drilled path forming impenetrable blocks.

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Exceptionally strong and hard rock will hamper all phases of an HDD project. Experience has shown competent rock with unconfined compressive strengths exceeding 12,000 psi and Mohs Scale of Hardness factors ranging somewhat above 7 can be negotiated with today’s technology. However, entry of such materials at depth is usually difficult. The directional drilling string tends to deflect rather than penetrate. Conversely, poor quality (extensively fractured or jointed) rock can present the same problems as coarse granular deposits. Two of the most significant crossings installed to date in rock were completed in the Fall of 1991. The longest, at approximately 3,000 feet (914 m) was installed beneath the Niagara River near Niagara Falls, New York. This 30 inch (DN 750) crossing was placed through a soft shale. An additional installation in harder rock was completed in 1991 beneath the Housatonic River near Shelton, Connecticut. This 24 inch (DN 600) line penetrated approximately 1,200 feet (366 m) of hard, fine-grained schist in a total horizontal drilled length of approximately 1,732 feet (528 m). General guidelines for assessing the feasibility of prospective HDD installations based on earth material type and gravel percent by weight are presented in Table 2-2. Earth material type and gravel percent by weight are determined in the site characterization phase of HDD installation design discussed in Section 3.0. Engineering judgment based on a foundation of practical experience must be applied when using the guidelines presented in Table 2.2. Knowledge of subsurface conditions will be based on extrapolation of measured properties from discreet soil borings generally taken by individuals not involved in HDD construction. A crossing may be placed in competent rock beneath a river. Nevertheless, overburden soils will probably have to be penetrated before the rock stratum is entered. A crossing installed in the lower Mississippi River flood plain may encounter clays, silts, sands, and gravels of varying relative densities in a relatively short distance. Only the general character of the subsurface material will be known in advance of construction. Contractual Feasibility

Once the technical feasibility of a prospective HDD installation has been established, its contractual feasibility can be assessed. This assessment is accomplished in the same way as technical feasibility, by comparing it to past installations. If the crossing falls near the limits of the state of the art in any of the basic parameters; length, diameter, or soil conditions, it is possible that it may be viewed by contractors as too risky to undertake for a fixed lump sum price. It should be understood, however, that determination of contractual feasibility is very subjective and will vary for individual contractors based on their experience and commercial situation. In today’s market for HDD services, most crossings that are technically feasible will be bid on a lump sum basis by at least one contractor. Nonetheless, it is not unusual to receive only one lump sum bid for state of the art crossings or for lump sum bids received to be very high. If contractual feasibility is questionable, the benefits of a day work contract or an alternate construction method should be considered. Contractual considerations, including day work contracts, are discussed in Section 7.


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Table 2-2 HDD Feasibility Assessment Guidelines

Earth Material Type Very soft to hard strength, possibly slickensided, clay.

Gravel % by Weight

N/A

HDD Feasibility

Good To Excellent. Plugging of the annulus surrounding the drill stem during pilot hole drilling may produce inadvertent drilling fluid returns through slickensides. Penetration of strong clay surrounded by considerably weaker or looser soils may result in the pilot bit “skipping” along the interface. Pilot hole steering difficulties are likely to result during passage through very soft layers.

Very loose to very dense sand with or without gravel traces.

0 to 30

Good to Excellent. Gravel may cause slight steering problems. Some steering imprecision may also result during passage through very loose material.

Very loose to very dense gravelly sand.

30 to 50

Marginally Acceptable. Drilling fluid characteristics and handling are critical to success. Pilot hole steering may be imprecise.

Very loose to very dense sandy gravel.

50 to 85

Very loose to very dense gravel.

85 to 100 Unacceptable. With present technology and experience, horizontal penetration, especially in the denser strata, is almost impossible. Such materials must be avoided or penetrated at a steep angle.

Rock.

N/A

Questionable. Horizontal penetration for any appreciable distance will be extremely difficult regardless of drilling fluid quality. Pilot hole steering may be imprecise.

Excellent to Unacceptable. Softer or partially weathered materials offer HDD performance akin to that of hard strength clay. Technology is available to drill through more competent rock, especially in the weaker horizontal plane. Penetrating solid rock after passing through soil may be difficult due to the bit’s tendency to “skip” along the lower hard surface. If in “rounded” cobble form, competent rock is virtually impossible to drill.

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Economic Feasibility

Determining the economic feasibility of a prospective HDD installation is a fairly straightforward exercise involving comparison of the estimated cost of HDD with the estimated cost of an alternate installation method. If the HDD estimate is less, it is economically feasible. When making this comparison, it is important to estimate the cost of equivalent designs and to include all costs associated with each method. For example, it would not be valid to compare the cost of a pipeline river crossing installed by open excavation with 3 feet of cover against the cost of a drilled installation providing 25 feet of cover without including some adjustment in the excavated estimate to account for possible future remedial work brought on by the relatively shallow 3 foot cover. Restoration costs and the costs associated with environmental impact for each method considered must also be included. The environmental impact associated with HDD construction operations is discussed in Section 6. A procedure estimating the cost of specialized HDD services is presented in the following paragraphs. Cost Estimating

The first step in accurately estimating the cost of specialized HDD services is to estimate the contractor’s direct job costs. Direct job costs are composed of two components, daily shift costs and non-daily costs. Daily shift costs are those costs which are dependent on the number of days operations are conducted. They are determined by calculating the cost of a given operation per shift and multiplying that figure by the number of shifts required to complete the operation. Non-daily costs are those costs which are not dependent the duration of operations such as equipment hauling involved with mobilization and demobilization. The cost to the owner is determined by adding a mark-up to the contractor’s direct costs. This mark-up covers the contractor‘s overhead, contingencies, and profit. A Lotus spreadsheet routine which performs these calculations is included in the file labeled ESTIMATE.WK4/WK3 on the diskette attached to the back cover of this manual. The routine is designed to estimate costs involved with the operation of a typical horizontal drilling rig. Included at the end of this section is the printout from an example estimate which has been performed using this routine. The example calculates an owner’s cost estimate for a 24 inch pipeline river crossing with a drilled length of 2,500 feet in soft alluvial deposits (silts, sands, clays). An explanation of how the routine operates is presented on the following pages. Estimating Parameters

The routine performs calculations using estimating parameters input by the operator. Based upon the length, diameter, and probable subsurface conditions, rates for pilot hole production, reaming and pull back penetration, and mud flow can be selected from the tables included in this section. The drilled segment length should be based on a preliminary design which takes into account standard horizontal drilling practices with respect to deflection angles and radius of curvature. Four general classifications of subsurface conditions are


13

listed in the tables. The general classification which is most descriptive of the anticipated conditions at the subject crossing should be used to select input parameters. Operational durations and drilling mud quantities are calculated by the routine using the input parameters. Calculations are organized by operational phase: pilot hole, prereaming, and pull back. Pilot Hole. The pilot hole production rate is truly a production rate as opposed to a penetration rate. It takes into account time spent redrilling, surveying, adding pipe, etc., and is dependent upon the subsurface conditions and required pilot hole tolerance. Typical values are given in the following tables. Table 2-3

Pilot Hole Production Rate in feet per hour for pipe diameters less than 30 inches Drilled Length. ft. < 2,000 2,000 - 3,000 > 3,000

Silt. Sand. Clay 60 55 50

Gravel 45 40 35

Soft Rock

Hard Rock

30 25 20

15 10 questionable

Table 2-4

Pilot Hole Production Rate in feet per hour for pipe diameters 30 inches and greater Drilled Length. ft. < 2,000 2,000 - 3,000 > 3,000

Silt. Sand, Clay 50 45 40

Soft Rock

Gravel 40 35 30

25

20 15

Hard Rock 10 questionable questionable

Pilot hole duration is determined by dividing the production rate into the drilled length to determine total hours and converting total hours to shifts using the number of hours per shift. Pilot hole mud flow rate is dependent upon whether a jetting assembly or downhole motor is used. A jetting assembly flow rate of 5 barrels/minute is used for silts, sands, and clays. A downhole motor flow rate of 10 barrels/minute is used for gravels, soft rock, and hard rock. The circulation loss factor adjusts drilling mud quantity calculations to account for mud which is unable to be recovered for recirculation. For example, a circulation loss factor of 0.2 indicates that 20% of the fluid pumped downhole will be lost and only 80% will be available for recirculation. The circulation loss factor is primarily dependent on subsurface conditions. It is difficult to predict and can range from near 0 to 1. Circulation loss factors used for cost estimating purposes are listed in the following table. Table 2-5

Circulation Loss Factors Silt, Sand, Clay Gravel Soft Rock Hard Rock

0.5 0.8 0.2 0.2


14

Pilot hole mud consumed is determined by multiplying the circulation loss factor by the total quantity of mud pumped downhole during pilot hole drilling. Mud pumped downhole during pilot hole drilling is the product of the pilot hole mud flow rate, the pilot hole duration, and a pumping factor. A pumping factor of 35 minutes per hour is used to account for time during pilot hole drilling when drilling fluid is not being pumped. Pilot hole mud consumed in barrels is converted to 100 pound sacks of high yield bentonite by dividing by a typical yield of 200 barrels of drilling mud per ton of dry bentonite. Prereaming. The prereaming penetration rate is the speed at which the reamer is being pulled along the pilot hole. It is dependent upon soil conditions and the diameter of the reamer. Typical values are given in the following table. Table 2-6

Prereaming Penetration Rate in feet per minute Pipe Diameter, in. < 24 24 - 32 > 32

Silt. Sand. Clay 3.0 2.5 2.0

Gravel 2.0 1.5 questionable

Soft Rock

Hard Rock

1.0 0.5 0.3

0.5 questionable questionable

The number of prereaming passes to be used is dependent upon the subsurface conditions and the pipe diameter. For estimating purposes, it can be assumed that all crossings will be prereamed at least once. If the pipe diameter is between 30 inches and 42 inches, the use of a second prereaming pass is probable. If the pipe diameter is greater than 42 inches, the use of a third prereaming pass is probable. If the crossing is being installed in soft rock or hard rock, an additional two passes should be used in the estimate.

Prereaming duration is determined by dividing the length by the penetration rate to establish the actual reaming time in minutes, adding two minutes per joint (30 foot drill pipe) to break and make up drill pipe, converting total minutes to shifts using the number of hours per shift, and adding estimated rig-up time of one half shift. This gives the duration for a single prereaming pass which is multiplied by the number of passes to give a total duration for the prereaming operation. Prereaming mud flow rate is primarily a function of diameter and can be estimated from the following table. Table 2-7

Ream & Pull Back Mud Flow Rate in barrels per minute Pipe Diameter. in. < 24 24 - 32 > 32

Silt. Sand. Clay 7 10

Gravel 10

15

questionable

13

Soft Rock 7 10 15

Hard Rock 7 questionable questionable

SECTION 2 -

FEASIBILITY

CONSIDERATIONS

15

Circulation loss factors used for prereaming are the same as those used for pilot hole drilling and can be found in Table 2-5. Prereaming mud consumed is determined by multiplying the circulation loss factor by the total quantity of mud pumped downhole during prereaming. Mud pumped downhole during prereaming is the product of the drilled length, the prereaming mud flow rate, and the number of prereaming passes, divided by the prereaming penetration rate. Prereaming mud consumed in barrels is converted to 100 pound sacks of high yield bentonite by dividing by a typical yield of 200 barrels per ton of dry bentonite. Pull Back. The pull back penetration rate is the speed at which the pipe is being pulled into

the reamed hole. It is dependent primarily on pipe diameter but can also be affected by the quality of the reamed hole. Typical values are given in the following table. Table 2-8

Pull Back Penetration Rate in feet per minute Pipe Diameter. in < 24 24-32 > 32

10 8 6

Pull back duration is determined by dividing the length by the penetration rate to establish the actual pull back time in minutes, adding two minutes per joint (30 foot drill pipe) to break and make up drill pipe, converting total minutes to shifts using the number of hours per shift, and adding estimated rig-up time of one shift.

Drilling mud flow rates used during the pull back operation are essentially the same as those used in prereaming and are given in Table 2-7. Circulation loss factors used for pull back are the same as those used for pilot hole drilling and can be found in Table 2-5. Pull Back mud consumed is determined by multiplying the circulation loss factor by the total quantity of mud pumped downhole during pullback. Mud pumped downhole during pull back is the product of the drilled length and the pull back mud flow rate, divided by the pull back penetration rate. Pull back mud consumed in barrels is converted to 100 pound sacks of high yield bentonite by dividing by a typical yield of 200 barrels of drilling mud per ton of dry bentonite.

Total Mud Consumed. Drilling program calculations conclude with a determination of the total amount of drilling mud consumed. The total is the sum of the consumed amounts calculated for each operational phase plus 1,000 barrels. The addition of 1,000 barrels accounts for the drilling mud system “line fill”. For convenience in pricing, mud consumed in barrels is converted to 100 pound sacks of high yield bentonite by dividing by a typical yield of 200 barrels of drilling mud per ton of dry bentonite.


16

Shift Cost Summary

For clarity, the routine calculates total direct job cost by breaking the job into a series of functional tasks. These tasks are defined below. l

Mobilization. Transportation of men and equipment to the jobsite.

l

Rig-Up. Erection of the drilling rig at the jobsite ready for pilot hole drilling.

l

Pilot Hole. Directional drilling of the small diameter pilot hole complete for reaming

and pulling back. Ream & Pull Back. Reaming the pilot hole and pulling the prefabricated pull section

back through it to the drill rig. l

Rig-Down. Disassembly of the drilling rig at the jobsite ready for demobilization.

l

Demobilization. Transportation of men and equipment from the jobsite.

l

Drilling Mud. The cost of drilling mud used in crossing installation.

Additional tasks which are not addressed in the routine but which may need to be estimated are defined below. These tasks do not involve specialized drilling activities. They are accomplished using standard pipeline construction methods. l

l

Site Preparation. Clearing and grading of the jobsite on both river banks ready for construction operations. Pull Section Fabrication. Stringing, welding, coating and pretesting the pull section

and preparing the section for installation. l

l

Final Hydrostatic Test. Final hydrostatic test of the inplace pull section. Site Restoration. Clean-up, etc. of the work location.

Shift Cost. Labor and equipment costs per shift are determined by identifying the individual

laborers and equipment necessary to complete a specific task and assigning hourly or per shift rates to each laborer and equipment item. The labor and equipment costs per shift for a specific task can then be calculated. The routine uses two standard crews, a horizontal drilling crew and a pull back support crew. The horizontal drilling crew is structured to perform horizontal drilling activities while the pull back support crew is designed to handle the pull section during installation. Shift costs for these crews are detailed in Tables 2-9 and 2-10. Allocation of the crew costs to the defined tasks is presented in the routine under the heading “Shift Cost Summary”.


17

Table 2-9

Horizontal Drilling Crew cost per 10 hour shift Description Superintendent Driller Surveyor Mud Man Crane Operator Ramp Laborer Mud Laborer

1 1

1 1 1

2 2

Labor Total

9

Horizontal Drilling Spread (fuel & maintenance) Downhole Survey System Crane (fuel & maintenance) Backhoe Loader (fuel & maintenance) Pick-up Trucks (fuel & maintenance)

1

Unit/shift 600 500 500 500 500 300 300

Total/shift 600 500 500 500 500 600 600 $3,800

2,500 500 1,500 250 25 250 25 50

1 1

1

2

2,500 500 1,500 250 25 250 25 100 20

10

Equipment Total

$5,170 Crew Total

$8,970

Table 2-10

Pull Back Support Crew cost per 10 hour shift Description Foreman Sideboom Operator Backhoe Operator Common Laborer

1

2

1 6

Labor Total

10

Sideboom Tractor (fuel & maintenance) Track Mounted Backhoe (fuel & maintenance) Roller Stands Pick-up Trucks (fuel & maintenance)

2 1

1 set 2

Unit/shift 550 500 500 300

Total/shift 550 1,000 500 1,800 $3,850

500 200 300 150 200 50 10

Equipment Total

1,000 400 300 150 200 100 20

$2,170 Crew Total

$6,020

18


Estimate Recap

The routine presents calculated direct costs, broken down by task, under the heading “Estimate Recap”. Calculated direct costs are a combination of shift costs, determined by multiplying the number of shifts by the single shift cost, and non-shift costs, which are not tied to duration. Non-shift costs included by the routine are drilling mud and transportation. Drilling mud cost is calculated in the drilling program using a per sack price of $12.00. A lump sum for transportation of $20,000 is included in both the mobilization and demobilization tasks. Durations for pilot hole and ream & pull back are calculated in the drilling program. Durations for rig-up/rig-down and mobilization/demobilization are set at a constant 2 days each. Owner’s Cost

The estimated owner’s cost is calculated by adding a mark-up to total direct costs. This mark-up covers the contractor’s overhead, profit, and risk contingencies. The components for overhead and profit are held constant at 10% and 15%, respectively. The component for risk must be evaluated for each crossing taking into account the possibilities for operational problems posed by the length, diameter, and subsurface conditions. Risk may be logically evaluated by estimating the cost and frequency of possible operational problems. For example, encountering a single random boulder during pilot hole drilling may force the contractor to redrill a portion of the pilot hole to avoid the boulder. This redrill may add two days to the duration of pilot hole drilling resulting in an increase in direct cost of $17,940.00 (i.e., twice the shift cost of the horizontal drilling crew). A contractor’s experience in a given region or subsurface material may indicate that a boulder, or some type of obstruction requiring a two day redrill, will be encountered once in every 2,000 feet drilled. A logical contingency cost for encountering an obstruction during pilot hole drilling may then be calculated for a specific job by dividing the designed drilled length by 2,000 feet and multiplying the result times $17,940.00. These calculations illustrate a logical method for evaluating one risk scenario. However, operational problem scenarios and costs vary and are difficult to predict. This is illustrated by extending the previous example.

The contractor encounters a boulder and redrills around it. The redrilled path just misses another boulder. During prereaming the boulder is encountered but it is displaced slightly and the reaming tool “walks” around it. The boulder is encountered again during pull back. This time the rigid pipeline will not “walk” around the boulder and the pipe becomes stuck. The contractor works for five days to free the pipe before twisting off the drill pipe in front of the reamer. He cannot free the pipeline and must abandon it beneath the waterway. He has now spent close to his entire operational budget, has lost his reaming tools, some drill pipe, and owes the owner for the pipeline abandoned beneath the waterway. He must drill a new pilot hole along a different path, purchase new pipe and fabricate a pull section, and begin the ream and pull back process again. His risks have not been diminished. The geology has not changed. He may fail again.


19

Typical values for the risk component of mark-up due to length and diameter in varying soil conditions are presented in the following tables. These values are added to the previously mentioned 25% for overhead (10%) and profit (15%) to determine the mark-up. Table 2-11

Mark-up for Risk associated with drilled length Drilled Length. ft. < 2,000 2,000 - 3,000 > 3,000

Silt. Sand. Clay 0% 10% 20%

Gravel 20% 40% 60%

Soft Rock 10% 20% 30%

Hard Rock 30% 50% questionable

Table 2-12

Mark-up for Risk associated with pipe diameter Pine Diameter. in. < 24 24-32 > 32

Silt, Sand. Clay 0% 10% 20%

Gravel 30% 50% questionable

Soft Rock 20% 30% 40%

Hard Rock 50% questionable questionable

References Drilling Fluids in Pipeline Installation by Horizontal Directional Drilling, Prepared for the

Offshore and Onshore Design Applications Supervisory Committee of the Pipeline Research Committee at the American Gas Association, October 31, 1994.

EXAMPLE ANALYSIS - OWNER’S COST ESTIMATE, DRILLING SERVICES ONLY ESTIMATING PARAMETERS WORK SCHEDULE

LENGTH PILOT HOLE PROD RATE DRILLING MUD FLOW RATE PILOT HOLE DURATION CIRCULATION LOSS PILOT HOLE MUD QTY PREREAM PASSES PREREAM TRAVEL SPEED PREREAM MUD FLOW RATE PREREAMING DURATION CIRCULATION LOSS PREREAMING MUD QTY PULL BACK TRAVEL SPEED PULL BACK MUD FLOW RATE PULLBACK DURATION CIRCULATION LOSS PULLBACK MUD QTY MUD COST TOTAL MUD QTY

10.0 7.0 2,500 55.0 5 4.5 50% 398 1

2.50 10 24.4 2.4 50% 500 8.00 10 18.0 1.8 50% 156 12.00 1,154

Hours/Shift Shifts/Week Feet Feet/Hour bpm Shifts Sacks Quantity Feet/Min bpm Hours Shifts Sacks Feet/Min bpm Hours Shifts Sacks $/Sack (100 lb) Sacks (100 lb)

SHIFT COST SUMMARY

FUNCTIONAL TASK - (Crews Required) MOBILIZATION - (Drilling Crew) RIG-UP - (Drilling Crew) PILOT HOLE - (Drilling Crew) REAM & PULL BACK - (Drilling & P.B. Support Crews) RIG-DOWN - (Drilling Crew) DEMOBILIZATION - (Drilling Crew)

NUMBER OF PERSONNEL

LABOR COST

EQUIPMENT COST

CREW TOTAL

9 9 9 19 9 9

3,800.00 3,800.00 3,800.00 7,850.00 3,800.00 3,800.00

5.170.00 5.170.00 5,170.00 7,340.00 5,170.00 5,170.00

8,970.00 8,970.00 8,970.00 14,990.00 8,970.00 8,970.00

LABOR EQUIPMENT COST COST

NON-SHIFT COST

TASK TOTAL

ESTIMATE RECAP

FUNCTIONAL TASK

SHIFTS 2.0 2.0 4.5 4.2 2.0 2.0 N/A

7,600.00 7,800.00 17,272.73 32,459.38 7,600.00 7,600.00 N/A

10,340.00 10,340.00 23,500.00 31,144.03 10,340.00 10,340.00 N/ A

20,000.00 0.00 0.00 0.00 0.00 20,000.00 13,847.73

37,940.00 17,940.00 40,772.73 63,603.40 17,940.00 37,940.00 13.847.73

16.8

$80.132.10

$96,004.03

$53,847.73

229,983.86

MOBILIZATION

RIG-UP PILOT HOLE REAM (1 PULL BACK RIG-DOWN DEMOBILIZATION DRILLING MUD

TOTALS

ESTIMATED COST CONTRACTOR’S DIRECT JOB COST = ESTIMATED MARK-UP @ 45%

ESTIMATED OWNER’S COST =

$229,984 U.S. DOLLARS $103,493 U.S. DOLLARS $333,477 U.S. DOLLARS


21

SECTION 3 - SITE CHARACTERIZATION

SECTION 3 SITE CHARACTERIZATION

Selection of HDD for use on a particular crossing should be predicated on a thorough understanding of the site’s characteristics. If HDD is the selected construction method, the design, permitting, and execution of the crossing should be governed by the conditions at the crossing site. Existing features, both natural and man-made, should dictate the manner in which an HDD crossing is configured. Application of the HDD construction process will elicit responses from the site’s features during both the short and long terms. Site conditions can be divided into two major groups, passive and active. Passive conditions are the site’s characteristics prior to construction. Examples of passive conditions are the earth material types, stratification, and groundwater conditions. Also

included in this category are the various aspects of the site’s surface such as the topographic/hydrographic relief and the presence of humankind’s activities. In essence, passive conditions are the site’s inplace characteristics regardless of the selected method of crossing installation. Active conditions are broadly defined as the products of the HDD construction process.

This category includes the condition of the drilled hole, the various procedures necessary to

complete the HDD installation, the response of the passive conditions to the HDD process, and the short and long term effects on the installed pipe. Simply stated, active conditions are the construction dependent phenomena at a given location. Active conditions are discussed in other sections of this design guide. Passive conditions are described in this section along with procedures for characterizing the passive conditions at a specific crossing site. Primary passive condition considerations are geological factors, topographic and hydrographic details, and geotechnical aspects. Geological Factors

In assessing the suitability of HDD for a specific location, an understanding of the site’s origin is fundamental This is important not only to project the site’s effects on HDD, but also to plan an effective site characterization study. Understanding the mechanism by which the site was developed, whether by aeolian (airborne), colluvial (gravity), alluvial (river), lacustrine (lake), glacial, or marine (saltwater sea) depositional processes, will forecast the types of materials to be expected as well as the potential for anomalous impediments (boulders, cobble fields, buried logs, stumps, etc.) which influence the HDD construction process. Geological evaluation thus provides the background for assessing the obstacle to be crossed.


22

Topographic and Hydrographic Details

Essential information stemming from topographic and hydrographic considerations is the site’s surface configuration. Not only does this information allow definition of the obstacle to be crossed, it also provides a basis for decisions concerning the arrangement of construction operations. Informational products include the dry land and underwater configuration of the site or obstacle as well as any existing man-made features. Geotechnical Aspects

Geotechnical aspects can be divided into two classifications: earth material parameters and subsurface stratification. Earth material parameters define the type and condition of the material at the site. Subsurface stratification defines the manner in which the earth material is distributed throughout the site. For construction purposes, earth materials fall into two broad categories, soil and rock. Soil can be defined as material made up of distinct particles which interact to form a mass. The particles may vary in size and may contain water or air in the interstitial spaces. Soil can generally be excavated without drilling or blasting. In contrast to soil, rock is a consolidated and hardened material which generally requires drilling or blasting for excavation. Rock cannot be easily separated into distinct particles. The dividing line between soil and rock, however, is not definite. Unified Classification System for Soil Type

The type of soil at a crossing site should be classified using a standard classification system. For a soil classification system to be effective in the HDD industry, it must be widely used,’ simple, inexpensive, and based on parameters which impact the HDD process. The Unified Soil Classification System satisfies these standards. This system was developed by A. Casagrande and jointly adopted by the United States Corps of Engineers and Bureau of Reclamation in 1952. It is described in detail in ASTM Standard D 2487.

The ASTM Standard bases classification on laboratory tests performed on the portion of a soil sample passing the 3 inch (75 mm) sieve. Pertinent definitions from ASTM D 2487 are presented below. Cobbles. particles of rock that will pass a 12 inch (300 mm) square opening and be

retained on a 3 inch (75 mm) U.S. standard sieve. Boulders. particles of rock that will not pass a 12 inch (300 mm) square opening. Gravel. particles of rock that will pass a 3 inch (75 mm) sieve and be retained on a No. 4 (4.75 mm) U.S. standard sieve with the following subdivisions: Coarse. passes 3 inch (75 mm) sieve and retained on 3/4 inch (19 mm) sieve, and Fine. passes 3/4 inch (19 mm) sieve and retained on No. 4 (4.75 mm) sieve.


23

Sand. particles of rock that will pass a No. 4 (4.75 mm) sieve and be retained on a No. 200 (75 µm) U.S. standard sieve with the following subdivisions: Coarse. passes No. 4 (4.75 mm) sieve and retained on No. 10 (2.00 mm) sieve, Medium. passes No. 10 (2.00 mm) sieve and retained on No. 40 (425 µm) sieve, and Fine. passes No. 40 (425 µm) sieve and retained on No. 200 (75 µm) sieve. Clay. soil passing a No. 200 (75 µm) U.S. standard sieve that can be made to exhibit

plasticity (putty-like properties) within a range of water contents and that exhibits considerable strength when air dry. Silt. soil passing a No. 200 (75 µm) U.S. standard sieve that is nonplastic or very slightly plastic and that exhibits little or no strength when air dry. Organic clay. a clay with sufficient organic content to influence the soil properties. Organic silt. a silt with sufficient organic content to influence the soil properties, Peat, a soil composed of vegetable tissue in various stages of decomposition usually with an

organic odor, a dark-brown to black color, a spongy consistency, and a texture ranging from fibrous to amorphous.

General criteria for assigning group symbols from ASTM D 2487 are summarized in Figure 3-l. Details with respect to laboratory classification may be found in ASTM D 2487. A general discussion of the Unified Soil Classification System is presented in Soil Engineering (Third Edition, pp. 306-310) by Spangler and Handy. Excerpts from this discussion are included below. All soils are classified into fifteen groups, each group being designated by two letters. These letters are abbreviations of certain soil characteristics, as follows... G - Gravel

S M C Pt

-

Sand Nonplastic or low plasticity fines Plastic fines Peat, humus, swamp soils

W P L H O

Organic Well graded Poorly graded Low liquid limit High liquid limit

GW and SW Groups. These groups comprise well-graded gravelly and sandy soils which contain less than 5% of nonplastic fines passing the No. 200 sieve. Fines which are present must not noticeably change the strength characteristics of the coarse-grained fraction and must not interfere with its free-draining characteristic... GP and SP Groups. These groups are poorly graded gravels and sands containing less than 5% of nonplastic fines. They may consist of uniform gravels, uniform sands, or nonuniform mixtures of very coarse material and very fine sand with intermediate sizes lacking. Materials of this latter type are sometimes referred to as skip-graded, gap-graded, or step-graded.

SOIL CLASSIFICATION

SUMMARIZED CRITERIA FOR ASSIGNING GROUP SYMBOLS AND GROUP NAMES COARSE-GRAINED SOILS More than 50% retained on No. 200 sieve

GRAVELS More than 50% of coarse fraction retained on No. 4 sieve

CLEAN GRAVELS Less than 5% fines GRAVELS WITH FINES More than 12% fines CLEAN SANDS Less than 5% fines

SANDS 50% or more of coarse fraction passes No. 4 sieve FINE-GRAINED SOILS 50% or more passes the No. 200 sieve

SANDS WITH FINES More than 12% fines INORGANIC

SILTS AND CLAYS Liquid limit less than 50

ORGANIC SILTS AND CLAYS Liquid limit 50 or more

OL CH MH

ORGANIC

HIGHLY ORGANIC SOILS

GROUP SYMBOL GW GP GM GC SW SP SM SC CL ML

Primarily organic matter, dark in color, and organic odor Figure 3-1

Soil Classification Chart Extracted with permission from the Annual Book of ASTM Standards (ASTM Designation: D 2487-93, p. 208), copyright American Society for Testing and Materials, 1916 Race Street, Philadelphia, PA 19103.

GROUP NAME Well-graded gravel Poorly graded gravel Silty gravel Clayey gravel Well-graded sand Poorly graded sand Silty sand Clayey sand Lean clay Silt Organic clay Organic silt

OH

Fat clay Elastic silt Organic clay Organic silt

PT

Peat


25

GM and SM Groups. In general, these groups include gravels or sands which contain

more than 12% of fines having little or no plasticity. Gradation is not important, and both well-graded and poorly graded materials are included. Some sands and gravels in these groups may have a binder composed of natural cementing agents, so proportioned that the mixture shows negligible swelling or shrinkage. Thus the dry strength is provided by a small amount of soil binder or by cementation of calcareous materials or iron oxide. The fine fraction of noncemented materials may be composed of silts or rock-flour types having little or no plasticity, and the mixture will exhibit no dry strength... GC and SC Groups. These groups comprise gravelly or sandy soils with more than 12% of fines which exhibit either low or high plasticity. Gradation of these materials is not important. The plasticity of the binder fraction has more influence on the behavior of the soils than does variation in gradation. The fine fraction is generally composed of clays...

These groups include the predominantly silty materials and micaceous or diatomaceous soils. Soils in these groups are sandy silts, clayey silts, or inorganic silts with relatively low plasticity. Also included are loessial soils and rock flours. Micaceous and diatomaceous soils generally fall within the MH group but may extend into the ML group. The same is true for certain types of kaolin clays and some illite clays having relatively low plasticity... ML and MH Groups.

CL and CH Groups. The CL and CH groups embrace clays with low and high liquid

limits, respectively. They are primarily inorganic clays. Low-plasticity clays are classified as CL and are usually lean clays, sandy clays, or silty clays. The medium-plasticity and high-plasticity clays are classified as CH. These include the fat clays, gumbo clays, certain volcanic clays, and bentonite. The glacial clays of the northern United States cover a wide band in the CL and CH groups. The soils in these groups are characterized by the presence of organic matter, including organic silts and clays. They have a plasticity range which corresponds with the ML and MH groups. OL and OH Groups.

Pt Group. Highly organic soils which are very compressible and have undesirable

construction characteristics are classified in one group with the symbol Pt. Peat, humus, and swamp soils with a highly organic texture are typical of the group. Particles of leaves, grass, branches of bushes, or other fibrous vegetable matter are common components of these soils. Borderline Classifications. Soils in the GW, SW, GP and SP groups are nonplastic

materials having less than 5% passing the No. 200 sieve, while GM, SM, GC and SC soils have more than 12% passing the No. 200 sieve. When these coarse-grained materials contain between 5% and 12% of fines, they are classified as borderline and are designated by a dual symbol, such as GW-GM. Similarly, coarse-grained soils which have less than 5% passing the No. 200 sieve, but which are not free draining or in which the fine fraction exhibits plasticity, are also classed as borderline and given a dual symbol...

Soil Condition Parameters

Parameters which determine a soil’s condition and aid in its classification vary depending on the soil type. For clay soils, the unit weight, moisture content, and Atterberg limits should be determined. For granular soils, the in situ density (Standard Penetration Test “blow counts”)


26

and grain size distribution should be determined. Standard procedures for measuring these parameters are listed below. EM1110-2-1906 ASTM D-2216 ASTM D-4318 ASTM D-1586 ASTM D-422

Unit Weight Moisture Content Atterberg Limits Standard Penetration Test Sieve Analysis

Note: ASTM refers to The American Society for Testing and Materials EM denotes Engineer Manual, Laboratory Soils Testing, U.S. Army Corps of Engineers Rock Condition Parameters

In the case of rock, measurements of unit weight, hardness, and in situ condition are necessary. Rock hardness is measured by Mohs Scale of Hardness. Details of Mohs Scale are listed in Table 3-l below. Table 3-l

Mohs Scale Of Hardness Original Version Talc Gypsum Calcite Fluorite Apatite Orthoclase Quartz Topaz Corundum Diamond

1

2 3 4 5

6 7 8

9 10 11

12 13 14 15

Revised And Expanded Version Talc Gypsum Calcite Fluorite Apatite Orthoclase Vitreous Pure Silica Quartz Topaz Garnet Fused Zirconium Oxide Fused Alumina Silicon Carbide Boron Carbide Diamond

In situ rock quality is indicated by a modified core recovery ratio known as the Rock Quality Designation (RQD). This ratio is determined by considering only pieces of core that are at least 4 inches long and are hard and sound. The percentage ratio between the total length of such core recovered and the length of core drilled on a given run is the RQD. Breaks obviously caused by drilling are ignored. The diameter of the core should preferably not be less than 2 l/8 inch. Rock quality descriptions related to RQD are listed in Table 3-2.


27

Table 3-2

Rock Quality Descriptions ROD (%) 90 - 100 75 - 90 50 - 75 25 - 50 0 - 25

Rock Quality Excellent Good Fair Poor Very Poor

Material Strengths

Shear strength determination through laboratory unconfined compression testing of undisturbed clay and rock specimens usually provides adequate definition for HDD construction. Especially important in the analysis of clay strength is determination of sensitivity: the material’s initial strength compared to its remolded strength. High strength clay generally features healed pre prefrac ractur tures. Ter Termed med slickensides, these passive condition anomalies may result in loss of drilling fluid circulation and inadvertent surface returns. Deformation Potential

Construction related short term, or “immediate”, earth material deformations, both elastic (recoverable) and plastic (permanent), can be assessed through various numerical techni technique quess such such as as finit finitee eleme element nt anal analysi ysis. s. Modul Modulii deter determin mined ed from from uncon unconfin fined ed compression and triaxial shear testing should be used. Assessment of longer term, time dependent deformational deformational behavior (i.e., (i.e., settlement) should be determined determined by conducting conducting incremental or constant rate of strain consolidation tests. Performance of incremental rate of strain consolidation testing, in which a load increment is held through several cycles of “secondary” consolidation, will also allow evaluation of ultra long term deflection (i.e., “creep”) characteristics. Groundwater

Trenchless construction operations, as well as in-service performance of the completed project, will largely depend upon proximity to (whether above or below) the free water surface. Consequently, the potential for fluctuation of the groundwater table, due to natural as well as man-made causes such as rainfall, river stage variation, and human induced area dewatering, must be determined. The potential for a perched water table must also be assessed since unchecked borehole flow during HDD operations could jeopardize successful construction completion. Facility design and execution must also consider both total as well as buoyant buoyant soil unit unit weights. weights. Finally, Finally, because because regulatory regulatory bodies are beginning beginning to question question the effects of directional drilling on groundwater quality, study efforts varying from cursory to extensive extensive have have been evoked. evoked. In light of these considera considerations tions,, earth material material permeabil permeability ity is a parameter which should be assessed.


28

Normally, the phreatic surface is measured in place. However, the potential for variation must be derived from review of long term site specific records. Permeability can be determined through laboratory testing; either through direct measurement (falling head, constant head, or triaxial permeability testing) or extracted from consolidation test time rate analysis. Subsurface Stratification

Once geotechnical material parameters have been defined, the manner in which they are dispersed throughout the site (i.e., the subsurface profile) can be determined. In essence, earth materials will form two types of interfaces: material and conditional. A material interface is the demarcation between two different classifications (i.e., clay and sand, rock and gravel), while a conditional interface is the differentiation within a particular earth material type (i.e., loose and dense sand, soft and hard clay). Another part of stratification determination is assessment of the possibilities for natural as well as manmade anomalous obstacles to HDD operations. Buried logs, stumps, gravel pockets, cobble fields, and boulders exemplify natural anomalies. Manmade impediments consist of existing pipelines, sunken barges, bulkhead/bridge pier piling, etc. In essence, determination of the subsurface profile, incorporating the site’s geological, potamological, and geotechnical aspects, completes definition of the site’s passive conditions relative to HDD. Site Characterization Study Contents

The objective of the site characterization study inherent to HDD construction, or for that matter, the engineering investigation involved in any project, is to determine and portray the site conditions relevant to selecting, designing, and executing the installation. In accomplishing this objective, the typical site characterization process produces three classes of data: l

l

Raw Data. Direct measurements. Processed Data. Information stemming from test results or computations performed on

raw data. l

Information stated in the form of construction plans, drawings, specifications, bid documents, permit applications, etc.

Evaluated Data.

The site characterization process develops information, through a sequentially staged generation of raw, processed, and evaluated data, which is used in the production of detailed construction plans and specifications necessary to execute an HDD installation. Responsibility for Site Characterization

Because full utilization of the site characterization study spans a particular project from conception to completion, the owner is generally the party best able to bear responsibility for study execution. However, due to the “emerging technology” nature of HDD, construction

29


contractors have often assumed, or been charged with, provision of site characterization details. While this may be viewed as placing responsibility for the construction and liability for failure directly on the appropriate party’s shoulders, the benefits of the detailed site characterization study occurring prior to the construction method selection, design, and permitting processes are lost. Likewise, a complete definition of the obstacle itself is denied the owner’s engineers. The permitting process, an increasingly involved and intricate phase of any constructed facility, is thus placed on the critical path in terms of project accomplishment, rather than being being set in a parallel parallel mode with with contractor contractor selection. selection. Consequent Consequently, ly, aside from the provision of site specific supplementary data, responsibility for execution of the site characterization study can be most efficiently discharged by, and should be placed with, the owner. Definition of the Obstacle

Basically, two classes of obstacles are negotiated via HDD. l

Time Dependent. Obstacles such as rivers (alluvial) and zones of migrating subsurface

contamination possessing the capability of expanding and/or relocating with the passage of time. l

Obstacles such as highway or railroad embankments, flood protection levees, and environmentally sensitive surface areas having temporally fixed boundaries.

Feature Dependent.

The primary concern in evaluating either type of obstacle is determination of its spatial extent. In the former case, such determination must include assessment of the obstacle’s boundaries throughout the design life of the HDD installation. Potamology (the study of rivers) yields an alluvial obstacle’s potential for horizontal

displacem displacement ent and and vertica verticall penetrati penetration on (i.e., (i.e., the stream’s stream’s meanderi meandering ng and scouring scouring characteristics) during a selected time span. By the same token, non-alluvial obstacle effects with the passage of time, such as uncompleted consolidation settlement of a massive highway embankment or integrity maintenance of a flood protection levee, must also be evaluated. In concert with a site’s geotechnically related passive conditions, a thorough definition of the obstacle to be crossed will dictate geometry of the directionally drilled path plus the steps necessary to restore site integrity following HDD completion. Site Exploration

The primary primary compone component nt of a site site characte characterizat rization ion study study is a site site explorati exploration. on. An appropriat appropriatee site exploration will consist of both surface and subsurface surveys. Although each survey may be performed by different specialized engineering consultants, it is important that the results be integrated onto a single plan and profile drawing which will form the basis of any contract contract and be used used to price, price, plan, and execut executee the crossing. crossing. Since this drawing drawing will also also be


30

used to make the working profile which will be the basis for downhole navigation, accurate measurements are essential. Surface Survey

A topographic survey should be conducted to accurately describe the working areas where construction activities will take place. Both horizontal and vertical control must be established for use in referencing hydrographic and geotechnical data. A typical survey should include overbank profiles on the design path centerline extending from approximately 300 feet (91 m) landward of the entry point to the length of the prefabricated pull section landward of the exit point. Survey ties should also be made to topographic features in the vicinity of the crossing. For significant waterways, a hydrographic survey will be required to accurately describe the bottom contours. Typically, it should consist of fathometer readings along the design path centerline, and along parallel paths approximately 200 feet (60m) upstream and downstream of the centerline. This scope can be expanded to include more upstream and/or downstream ranges if this data is required to analyze future river activity. Subsurface Survey

The subsurface survey is directed at determining: l

l

Material Interfaces. Differentiation between different types of earth materials. Conditional Interfaces.

Differentiation between different states of a single earth

material. l

Discrete inclusions of dissimilar and/or conditionally different materials from within the enveloping earth material mass.

Inplace Anomalies.

Definitions of such items, when brought together in the context of one another, produce a subsurface profile. In turn, such a profile enables assessment of the obstacle’s bounds, both time dependent as well as feature dependent, plus the site specific efficacy of the HDD process. Concerted presentation of such information will allow efficient execution and will expedite pre-construction permitting and post-construction certification processes. At the present time, subsurface surveying for HDD installations mainly involves taking vertical borings to produce specimens for physical testing. Borehole conduct procedures, spacing, depth, and sampling frequency generally depend on a project’s extent and the subsurface profile’s potential for variation (as defined by the previously mentioned geological and potamological evaluations). Material properties of clay and rock are determined through securing undisturbed test specimens. Granular materials, such as silt, sand, and gravel, are subjected to in situ density determinations (primarily Standard Penetration Testing) which also produce samples for laboratory classification (mainly grain size analyses). Of particular concern in the exploration of granular soils is that a hydraulic gradient outward from the


31

borehole is maintained at all times. An inward gradient risks “quickening” the in situ soils to produce a false sense of what is actually there. At any rate, material and conditional interfaces are then established through interpolation between boreholes. Field sampling specifications are listed below. Standard Penetration Test Thin walled Tube Sampling Rock Coring

ASTM D-1586 ASTM D-1587 ASTM D-2113

As an alternative to the Standard Penetration Test when soft soils are encountered, the Dutch Cone Penetration Test can be used. Although not yet extensively employed in the United States, this test is used in Europe and is a recognized “ISO-test”. Other non-sampled intrusive procedures (cross-borehole electrical resistivity/conductivity and shear wave analyses, etc.) as well as non-intrusive, near surface geophysical techniques (reflective/refractive surveying, sub-bottom acoustic profiling, ground penetrating radar, etc.) are possible candidates to expand field exploration utilities. Generally speaking, these exploration methods can enhance data from boreholes by providing a more precise definition of material and conditional interfaces. Expansion of a sampled borehole program through the utilization of non-sampled soundings and/or non-intrusive examinations will improve site characterization efforts. Sampled boreholes, however, are likely to remain the cornerstone of any field investigation because of drawbacks to using these non-traditional exploration procedures, such as regulatory considerations requiring site surface integrity restoration and the lack of physical specimens. Laboratory Testing. As previously detailed, earth material parameter determination relies

heavily on laboratory testing. In contrast to field procedures, laboratory evaluation offers better control of the test conditions plus the ability to impose a variety of stress systems. In this manner, the site’s overall “performance” (its active conditions during HDD as well as its post-construction responses) can be better simulated. By contrast, many passive conditions are more precisely defined through field procedures (the disturbance associated with sampling any non-lithified earth material is not a factor). Therefore, a complete investigative program should be based on laboratory testing results in concert with data from field procedures. References

ASTM Standard D 2487 - 93, Classification of Soils for Engineering Purposes (Unified Soil Classification System). (Extracted, with permission, from the Annual Book of ASTM Standards, copyright American Society for Testing and Materials, 1916 Race Street, Philadelphia, PA 19103 .)

Merlin G. Spangler and Richard L. Handy, Soil Engineering, Third Edition, (New York, New York; Intext Press, Inc., 1973)


32

SECTION 4 - GENERAL DESIGN CONSIDERATIONS

SECTION 4 GENERAL DESIGN CONSIDERATIONS

Horizontal directional drilling is a specialized pipeline construction method that is used to cross obstacles which cannot be readily crossed by open cut excavation. Considerations relative to the technical, contractual, and economic feasibility which govern the use of HDD have been discussed in Section 2. This section presents general considerations relative to detailed drilled crossing design. In planning a drilled crossing, the designer should seek to minimize its installation cost while satisfying the objectives of the owner. The primary way to minimize the installation cost is to minimize the drilled length. Typically, the objectives of the owner are satisfied if the following conditions are met: construction must not adversely impact the environment, construction must not damage the pipeline, and the crossing must remain intact and functional over its design life. Definition of the Obstacle

To maximize the advantages offered by HDD, primary design consideration should be given to defining the obstacle to be crossed. For example, a river is a dynamic entity. Not only should the water’s width and depth be considered, the potential for bank migration and scour during the design life of the crossing should also be taken into account. It should always be remembered that flexibility in locating a pipeline to be installed by HDD exists not only in the horizontal plane but in the vertical plane as well. An engineering definition of the obstacle results from site characterization efforts which have been discussed in Section 3. Drilled Path Design

A designed drilled path consists of a series of straight lines and curves. The straight lines are referred to as tangents and the curves are typically sag bend, over bends, or side bends depending on their axial plane. Compound bends may also be used but are generally avoided to simplify drilling. The location and configuration of a drilled profile are defined by its entry and exit points, entry and exit angles, radius of curvature, and points of curvature and tangency. The relationship of these parameters to each other is shown in Figure 4-l. These parameters, or their limiting values, should be specified on the contract plan & profile drawing.

EXISTING GRADE

PT

POINT

PC

EXIT POINT

PT

RADIUS OF

RADIUS OF CURVATURE, R

CURVATURE, R EXIT ANGLE

DESIGNED

DIRECTION OF HORLZONTAL COORDINATES POINT OF CURVATURE, PC

POINT OF TANGENCY, PT

Figure 4-l Definition of Drilled Path Curves

DRILLED

PROFILE

34


Definition of Curves

Designed drilled segment sag bends, over bends, and side bends are generally defined as simple circular curves using standard surveying relationships. Nomenclature is shown in Figure 4-1. Entry and Exit Points

The entry and exit points are the end points of the drilled profile. The drilling rig is positioned at the entry point. The pipeline is pulled into the exit point and back to the entry point. The relative location of the entry and exit points, and consequently the direction of pilot hole drilling, reaming, and pulling back, should be established by the site’s geotechnical and topographical conditions. When choosing the relative locations of the entry and exit points, it is important to note that steering precision and drilling effectiveness are greater close to the drilling rig. Where possible, the entry point should be located close to anticipated adverse subsurface conditions. An additional consideration is the availability of workspace for pull section fabrication. It is preferable to have workspace in line with the drilled segment and extending back from the exit point the length of the pull section plus 200 feet (61 m). This will allow the pull section to be prefabricated in one continuous length prior to installation. If space is not available, the pull section may be fabricated in two or more sections which are welded together during installation. However, welding during installation slows the process and will increase costs. A slow installation also increases the chances of getting the pipe stuck. Entry and Exit Angles

Entry angles should be held between 8º and 20º with horizontal. These boundaries are due chiefly to equipment limitations. Horizontal drilling rigs are typically manufactured to operate at 10º to 12º. Exit angles should be designed to allow easy breakover support. That is, the exit angle should not be so steep that the pull section must be severely elevated in order to guide it into the drilled hole. This will generally be less than 10º for larger diameter lines.

Depth of Cover

The depth of cover should be governed by the definition of the obstacle. Adequate cover should be provided to maintain crossing integrity over its design life. Geotechnical drillability factors may also be considered when selecting the vertical position of the pipeline. A minimum depth of cover of 15 feet (4.6m) should be maintained in designing drilled profiles. This aids in reducing inadvertent returns, provides a margin for error in existing grade elevation, and allows for future changes in grade elevation.


35

Design Radius of Curvature

Industry Standard. The design radius of curvature in feet for circular bends used in HDD installations is determined by the following formula.

R = lOO*Dnom

(5.1)

where, R

=

The radius of curvature of circular bends in feet.

Dnom

=

The nominal diameter of the pipe in inches.

This relationship has been developed over a period of years in the horizontal drilling industry and is based on experience with constructability as opposed to any theoretical analysis. Pipe Stress Criteria. The design radius of curvature may be reduced from the industry standard. However, a reduction in radius will increase bending stresses and pulling tension.

Methods for analyzing the effect of radius of curvature variations on the integrity of the pipeline and the pulling tension are discussed in detail in Section 5. Directional Accuracy and Tolerances

Downhole survey instruments are typically magnetic and are therefore subject to some inaccuracy. Additionally, some pilot hole deviation from the designed drilled path may be experienced due to soil reaction. Therefore, a tolerance should be allowed in actual versus designed pilot hole course. For magnetic instruments, an error in alignment of 1% of the drilled length is not unusual. Error can be reduced by using a surface monitoring system or redrilling the pilot hole, but this will increase the cost of the installation. Magnetic error may also be eliminated through the use of a gyroscopic survey system. However, gyroscopic systems are susceptible to mechanical failure in HDD applications and have been used only on a limited basis in North America. Therefore, tolerances should be considered when locating a drilled segment near existing facilities and purchasing easements. Construction specifications with respect to pilot hole accuracy are discussed in Section 7. Pipe Specification

The primary criteria governing the specification of pipe to be installed by HDD is its service. In most cases, the wall thickness and specified minimum yield strength will be determined by applicable codes and regulations. However, stresses and loads imposed by the installation method should be reviewed and, where prudent, analyzed in combination with operating stresses to insure that acceptable limits are not exceeded. Methods for analyzing the loads and stresses imposed on a steel pipeline installed by HDD are discussed in detail in Section 5.

36


External Pipe Coating

External coatings used in HDD installations should be smooth and resistant to abrasion. Historically, pipelines installed by HDD in alluvial soils have been coated with corrosion coating only. Weight coating is generally not required. The deep, undisturbed cover provided by HDD installation has proven adequate to restrain buoyant pipelines. The corrosion coating most often used on HDD crossings is thin film fusion bonded epoxy ranging in thickness from 14 to 22 mils. This coating is popular not only because it is a highly durable system, but also because the field joints can be coated using a compatible fusion bonded epoxy system. If problems are experienced with a fusion bonded epoxy field joint coating system on larger diameter and wall thickness pipe, glass fiber reinforced epoxy joint coating may be used. This joint coating system has been used with success in Europe. However, the acceptable radius of curvature for bends should be increased to avoid micro cracks in the glass fiber reinforced coating. Pipe coated with extruded coatings may also be used with shrink sleeves on field joints. This system is acceptable from an installation standpoint as long as care is taken to insure that the shrink sleeves are properly applied and suitably bonded. Tape coating for pipe or field joints should not be used because of its tendency to be rolled off during pull back. For crossings installed in rock, highly abrasive soils, or soil conditions which might involve point loads, a reinforcing coating should be used in addition to the corrosion coating. The reinforcing coating need not have corrosion prevention properties, but should provide mechanical protection to the underlying corrosion coating. Multiple Line Installation

Multiple pipelines may be installed in a single drilled hole by joining them to a common pulling head for pull back. The lines do not need to be banded together but should follow the head freely as they are pulled into the drilled hole. Installation of multiple pipelines in a single hole in this manner is fairly common. If separation of the pipelines is required for cathodic protection purposes, this may be accomplished using rubber spacers or by providing the pipelines with a thick resilient coating. The pipelines will roll during installation. Therefore, provisions should be made outside of the drilled segment to allow the pipelines to be properly positioned for tie-in.


SECTION 5 - PIPE STRESS ANALYSIS

37

SECTION 5 PIPE STRESS ANALYSIS

Load and stress analysis for an HDD pipeline is different from similar analyses of conventionally buried or laid pipelines because of the relatively high tension loads, sometimes severe bending, and external fluid pressures felt by the pipeline during the installation process. In some cases these loads may be higher than the design service loads. Pipeline properties (wall thickness, material grade) and pilot hole profiles must be selected such that the pipeline can be installed and operated without risk of damage. A pipeline installed by HDD can be examined for load and stress states by first breaking the problem into two distinct events: installation and operation. Installation Loads and Stresses

The focus here is to examine the loads experienced during installation of the pipeline as it is pulled into a prereamed pilot hole, or one that is being back reamed immediately ahead of the incoming pipeline. During installation the pipeline is subjected to: tension required to pull the pipe into the pilot hole and around curved sections in the

hole, made up of, frictional drag due to wetted friction between pipe and wall of hole,

fluidic drag of pipe pulled through the viscous drilling mud trapped in the hole annulus,

unbalanced gravity (weight) effects of pulling the pipe into and out of a hole at different elevations, bending as the pipe is forced to negotiate the curves in the hole,

external hoop from the pressure exerted by the presence of the drilling mud in the annulus around the pipe (unless the pipe is flooded with a fluid at a similar pressure).

The stresses and failure potential of the pipe are a result of the interaction of these loads; therefore, calculation of the individual effects does not give an accurate picture of the stress limitations (Fowler and Langer) (Loh). The purpose of this section is to describe a reasonably simple means to estimate installation loads, calculate the resulting stresses, and determine if the overall HDD design is adequate. Loads and stresses experienced during installation of the pipeline are distinct from loads and stresses experienced during the service life of the pipeline and call for specific calculations

38


and design checks. It is assumed in the method that follows that the pilot hole has been reamed approximately 12 inches larger than the pipeline diameter and that the annulus between the diameter and the reamed hole is filled with drilling mud of a known (or assumable) density. Reconsolidation of the formation surrounding the pilot hole will undoubtedly occur over time but if any significant formation pressure loads were exerted on the pipe during the pull back process, it is not expected that the pipe could be pulled in at all. Therefore, formation pressures are not considered in the analysis of the installation loads, Pulling Load Calculation Method Drilled Path Analysis

The first step in calculating pulling load is to analyze the drilled path. This analysis can be based on the designed drilled path or the “asbuilt” pilot hole. The drilled path centerline should be plotted in the two-dimensional vertical and horizontal planes with pipe length along the x-axis and distance from the reference line the y-axis. The entire drilled path should be broken into discrete sections: straight or curved. As many sections as necessary can be defined and there is no upper or lower bound on the length or arc length of any chosen section. Straight sections are those in which hole curvature is ideally zero but may actually have very slight curvature. Any pipe section with a net curvature less than that necessary to make the pipe deviate beyond the walls of the hole, which is roughly 12 inches larger in diameter than the pipe itself, can be considered a straight section. Curved sections should be short enough to assume one constant radius for the entire sweep of that section. If the radius of curvature in a particular curved section is variable, break that curved length into small enough sections to justify the assumption of constant radiu s of curvature in each smaller section. A plot of a simple designed drilled profile is shown in Figure 5-1.

As few sections as possible should be designated for the entire drilled path but as many as necessary to completely define its shape. The junctions between sections are assumed to be continuous (no sudden non-linearities in the shape of the pipe) and free of externally applied moment. The junction between a straight and curved section will constitute the beginning of the curvature for the curved section. It will later be modeled in this analysis as the end point of a simply supported beam. Curved sections may join straight sections or other curved sections but straight sections will always join curved sections on both ends since there is no reason to sub-divide long straight sections. Pulling Loads

The load and stress calculation method described here begins with an elementary finite difference calculation of the pull force required to completely install the pipeline section from exit to entry point of the reamed pilot hole. The calculation is done in a way to define the maximum pulling loads which are assumed to occur at the moment the pipeline emerges from the entry point. Axial load in the pipe during the last instant of the pull back process will be distributed along its length from entry to exit. Cumulative axial load is composed of discrete axial loads occurring in each section of the hole due to friction between the pipe and

Figure 5-l HDD Designed Drilled Profile

40


the hole wall plus dynamic fluid friction required to make the pipe move through the viscous drilling mud. Because the hole wall/pipe frictional components are caused by the shape of the hole, the axial tension in the pipe at any given point can conveniently be considered to be confined to that particular location in the hole, regardless of which portion of the pipe is passing that point in the hole during any instant in the pull back process. This fact allows for worst case loads anywhere in the hole to be calculated only for the case where the pipe has just emerged from the hole. Calculation - Straight Sections. The pipe is assumed to be pulled from the right to the left

(as viewed in Figure 5-1) in all of the following models and calculations. The total pull force required to install the pipe is determined by summing the individual forces required to pull the pipe through each of the straight and curved sections defined in the hole profile. The modeling and calculation process must be done sequentially from right to left (i.e. from pipe side to rig side). Each straight section is modeled with variables as shown in Figure 5-2. Figure 5-2

Straight Section Model

For any straight section, the left end tension, T2, is found from the static force balance,

T2 = T1 + IfrictI + DRAG + Ws x L x sin

(5.l)

The ± term is resolved as follows: (-) if T2 tends downhole, (+) if T2 tends upslope, (0) if the hole section is horizontal,

= 0.

where,

T2

=

tension at the left end of the section, in lbs, required to over come drag and friction.


41

T1

=

tension at the right end of the section in lbs. This may be zero for the first section of the hole (Point A in Figure 5-1), or it may be determined by the drag of the pipe remaining on the rollers.

frict

=

friction between pipe and soil in lbs.

DRAG =

fluidic drag between pipe and viscous drilling fluid in lbs.

Ws

=

effective (submerged) weight per foot of the pipeline plus internal contents (if filled with water) in lbs/ft.

L

=

length of section in feet.

=

angle of the axis of the straight hole section relative to horizontal (zero equals horizontal, 90° is vertical)

Relationships defining the friction and fluidic drag terms are presented below. The absolute value for frict is used to insure that the it always acts in the proper direction relative to T2. (5.2) (5.3) where, µ soil

=

average coefficient of friction between pipe and soil; recommended values between 0.21-0.30 (Maidla)

D

=

outside diameter of pipe in inches.

µ m u d =

fluid drag coefficient for steel tube pulled through bentonite mud; recommended value 0.05 psi (NEN 3650).

Calculation - Curved Sections. Each curved hole section selected in the hole profile is

modelled as shown in Figure 5-3 with the variables the same as the straight section, plus additional variables as defined below, =

(constant) radius of curvature of the section in feet,

=

included angle of the curved section in degrees.

1

=

angle in degrees from horizontal of T1, at right end of section.

2

=

angle in degrees from horizontal of T2, at left end of section,

R

=

(5.4)


42

L is replaced by Larc = R x

x Figure 5-3

Curved Section Model

N1, N, & N2 = normal contact forces at right, center, & left points, respectively.

frict1, frict, & frict2 = frictional forces associated with normal forces at right, center, & left points, respectively.

The distributed submerged weight of the pipe and contents are approximated to operate vertically at the center of the section despite the curvature of the pipe section. To determine the normal forces of contact at the center and ends, each curved section is modelled as a beam in 3-point bending as shown in Figure 5-4. Loads on the beam are axial tension, T, plus distributed, submerged weight, Ws. A beam in 3-point, simply supported bending will not assume a constant radial, circular shape. For the bent pipe to fit in the circular hole section it must deflect enough to place its center at a point matching the displacement, h, of a circular arc with radius, R, where, h = R x [ 1 - cos

]

(5.5)

Note that this approximation of beam behavior in each curved section cannot be expected to be strictly accurate since more than three points of contact are likely for virtually any


43

pipe/hole shape combination. However, since the objective is to determine normal contact forces and then calculate frictional forces exerted on the pipe as it is pulled through a curved section, this method is an adequate approximation and accounts for pipe stiffness relative to curve radius. The frictional forces become components in a later calculation of total pulling tension, Ttot. Sensitivity checks on the effect of T tot in the overall stress analysis of the pipeline show that small variations in the value for T tot do not grossly affect calculated stresses. Also, frictional loads are significantly affected by the assumed coefficients of friction, µ soil, and drag, µ mud. Figure 5-4 3 -Point Bending

Nl N2

The solution to the beam model to find N uses the vertical component of distributed weight, Ws x cos as the main load and the arc length of the pipe section, L,,, in place of L. From Roark’s solution for elastic beam deflection,

N = [12 x T x h - (ws/12) x cos

x Y]/X

(5.6)


44

where,

X = 3 x Larc - j/2 x tanh(U/2) 2

(5.7)

2

Y = 18 x (L arc) - j x [ 1 - l/cosh(U/2)]

j = (E x I/T)

(5.8)

1/2

(5.9)

where, 7

E

=

Young’s Modulus (2.9 x 10 psi for steel)

I

=

Bending Moment of Inertia in inch

U

=

12 x Larc /j

tanh

=

hyperbolic tangent

cosh =

4

(5.10)

hyperbolic cosine

A value for T must be used to calculate both N and j. The proper value for T is the average of T1 and T2; therefore, an iterative solution is required to solve for T2 with accuracy. For hand calculations a few sensitivity checks on the value of T2 as the average, or T ave, varies are quick to show that the assumed Tave, need not be exactly the average of T1 and T2.

frict = N x µ soil

(5.11)

Therefore, end reactions are assumed to be N/2 and end friction forces are assumed to be f/2. Where N is a positive value (defined as downward acting as in Figure 5-4) it shows that the bending resistance and/or buoyancy of the pipe is sufficient to require a normal force acting against the top of the hole in order to get the pipe to displace downward by an amount equal to h. Where N is negative, the submerged pipe weight is sufficient to carry the pipe to the bottom of the curved section where an upward acting normal force is felt at the point of contact. Whether N is positive or negative in value, all friction values are taken as positive, acting in opposition to T2. Assume forces acting along the curved path of the pipeline can be added as if acting in a straight line (as along a highly flexible, rope-like member). Then,

T2 = T1 + 2 x [frict] + DRAG ± Ws x L arc x sin The ± term is resolved as follows: (-) if T2 tends downhole,

(5.12)


45

(+) if T2 tends upslope, (0) if the hole section is horizontal,

= 0.

The absolute value of frict is used because friction always retards pipe movement caused by T2. Calculation - Total Pulling Load. The total force, Ttot, required to pull the entire pipeline into the reamed pilot hole is the sum of all straight and curved section values for AT, (T2 T1).

T tot

=

(T2 - T1), for i sections

(5.13)

Installation Stress Analysis

The worst case stress condition for the pipe will be located where the most serious combination of tensile, bending and/or hoop stresses occur simultaneously. This is not always obvious in looking at the hole profile because the interactions of the three loading conditions is not necessarily intuitive. To be sure that the point with the worst case condition is isolated it may be necessary to do a critical stress analysis for several suspect locations. In general, highest stresses will be felt at locations of tight radius bending, high tension (closer to the rig side), and high hydrostatic head (deepest point). The approach that follows is taken from the API Recommended Practice 2A-WSD. Lower case f’s represent actual stresses, upper case F’s represent allowable stresses. Individual Loads

For any selected location in the drilled path profile that is suspected of being a critical stress location, first calculate the individual stresses for the specific loading conditions (tensile, bending, hoop stresses) and compare against allowable levels for these stress states. If no individual stress condition appears to cause overstress failure, the combined stress state is compared in two interaction equations presented as unity checks. That is, the combined stresses in the interaction equation must be less than 1.0 for the pipe to be safe from collapse by bending or hoop collapse in all regimes (plastic, elastic and transition). Tensile stress.

f t =T/A

(5.14)

where, T A

= =

tension at the point of interest in lbs. cross-sectional area of pipe wall in inches.


46

Bending stress.

f b = (E x D)/(24 x R)

(5.15)

Hoop Stress. f h = (

(5.16)

x D)/(2 x t)

where,

t

=

pipe wall thickness in inches

and where Ap (psi) is equal to the difference between hydrostatic pressure exerted by the drilling mud in the hole acting on the outside of the pipe and the pressure from water, mud or air acting on the inside of the pipe, at the depth of the point of interest (Ap producing a compressive external hoop stress is taken as positive), external mud pressure = mud wt (ppg) x depth (ft)/19.25

(5.17)

Compare each actual stress, f, to its allowable stress, F, as follows: Tension.

Ft = 0.9 x SMYS

(5.18)

where,

SMYS =

Specified Minimum Yield Strength in psi

Bending.

Fb = 0.75 x SMYS for D/t

(5.19)

1,5OO,OOO/SMYS

Fb = [0.84 - {1.74 x SMYS x D/(E x t)}] x SMYS for 1,5OO,OOO/SMYS < D/t

3,OOO,OOO/SMYS

Fb = [0.72 - (0.58 x SMYS x D/(E x t)}] x SMYS for 3,OOO,OOO/SMYS < D/t

(5.20) (5.21)

300,000

Hoop Buckling Stress.

f h < Fhc /l.5

(5.22)

where Fhc, critical hoop buckling stress, is a function of F he, elastic hoop buckling stress as follows:


47

2

Fhe = 0.88 x E x (t/D) (for long, unstiffened cylinders)

(5.23)

Fhc = Fhe for Fhe Ij 0.55 x SMYS

(5.24)

and,

For inelastic hoop buckling,

Fhc = 0.45 x SMYS + 0.18 x Fhe for 0.55 x SMYS < Fhe 1.6 x SMYS

(5.25)

Fhc = 1.31 x SMYS/[l.15 + (SMYS/Fhe)] for 1.6 x SMYS < Fhe 6.2 x SMYS

(5.26)

Fhc = SMYS for Fhe > 6.2 X SMYS

(5.27)

Combined Loads

If all preliminary checks indicate that the loading on the pipe will not cause failure (overstress or buckling) due to a single load condition, the suspect stress locations must be checked for safety under interactive combined loading by conducting two unity checks; first a dual load condition (tension plus bending) and finally a full interactive load unity check which must be satisfied for combined tensile, bending and hoop stresses. The unity check for combined stresses, tensile and bending, is:

f /(0.9 x SMYS) + f b /Fb t

1.0

(5.28)

The unity check for full interaction of tensile, bending and external hoop stresses is: 2

2

A + B + 2v x [A] x B

1

(5.29)

where,

A = (f t + f b - 0.5 x f h) x 1.25/SMYS

(5.30)

B = 1.5 x f h /Fhc

(5.31)

v = Poisson’s ratio (0.3 for steel) Satisfying the unity check equation for combined loading at all particular locations of suspect serious stresses, after first satisfying all single-load condition stress cases at those

48

SECTION 5- PIPE STRESS ANALYSIS

locations, is sufficient to qualify the design for an HDD pipeline installation. If the unity check results in a value greater than one it does not mean that the pipeline will necessarily fail (by overstress or buckling) but it does indicate that the combined stress state places the design in a range where some test specimens under similar stress states have been found to be subject to failure.

The combined stress interaction analysis described above is useful for finding solutions to field problems where conditions differ from original design expectations. One typical case might be if a pilot hole has a few spots where the radius is tighter than designed and, thus, the unity check exceeds one. In this case it is possible to find a modified solution to the installation problem by varying one load parameter and checking its effect on the stress interaction. For example, if a certain HDD design profile fails the unity check with the pipe installed empty it may pass the unity check when filled with water, thus reducing hoop stress and decreasing buoyancy. Example Pulling Load Calculation

Use the example HDD pilot hole profile as shown in Figure 5-5. For this example the hole is assumed to occupy only a single plane, i.e. there is no significant curvature into or out of the plane of the paper. The pipe side (right) and rig side (left) are at the same elevation and 1,500 feet apart. The total depth for the horizontal straight section is 100 feet below the entry/exit datum elevation. The total arc length of the centerline of the hole profile is 1,525 feet. The right curved section is a 20° arc at a 1,000 foot radius. The left curved section is a 14° arc at a 1,200 foot radius. The following particulars are given for this example installation:

D = 12.75 in Pipe: Grade B Steel µ soil soil = 0.3 Mud Mud wt. wt. = 12 12 ppg ppg

t = 0.25 in Ws = -46.21 lb/ft 7 E = 2.9 x l0 psi SMYS = 35,000 psi µ mud mud = 0.05 psi This This is a con conserv servat ativ ivee (h (high igh dril drille ledd soli solidds cont conten entt ass assuumed) med) 3 mud weight value. 12 ppg = 89.76 lb/ft Formation is predominately soft clay Right side tension (pull-back) on the pipe as it enters the hole = 0 Pipe is installed empty

Examination of the geometry of the pilot hole allows for it to be broken down into five convenient sections for calculating pull forces. From right to left they are: Section

Type

A to B B to C C to D D to E E to F

straight curved, R = 1000 ft

straight curved, R = 1200 ft

straight

Angle = 20°

= 10° = 20° =0 = 7° = 14° = 14°

Length L La r c L La r c L

= 116.1 ft = 349.1 ft = 500.3 ft = 293.2 ft = 266.2 ft

T2

1500

RIG SIDE

PIPE SIDE

R =1200'

20”

Figure 5-5

Example, HDD Pilot Hole Profile


50

Pulling Loads Straight Section at Point B.

= TB - TA = [frict] + DRAG - Ws x L x sin [frict] = Ws x L x cos x µ s o i l = (-46.21 lb/ft) ( 116.1 ft) (cos 20º) (0.3) = 1,512 lb

DRAG

= 12

x

= (12) = 2,790 lb Ws x L x sin

x D x L x µ mud mud 2 (12.75 in) (ll6.1 ft) (0.05 lb/in )

= (-46.21 lb/ft) (ll6.1 ft) (sin 20°)

= -1,835 lb = 1,512 lb+ 2,790 lb - (-1,835 lb) = 6,137 lb TB = + TA = 6,137 lb

Pull Load at Point B

Curved Section at Point C. h = R x [l - cos

o

= (1000 ft ft)(l - cos 10 10 ) = 15.19ft 3

I = x (D - t) x t/8 3 = (12 (12.75 in - 0.25 in) (0.25 in)/8 4 = 191.75 in Assume Tave for section = 10,000 lb to start iterative solution. 1/2

j = (E x I/Tave) 7 4 1/2 = [2.9 x 10 psi (191.75 in )/10,000 lb] = 745.7 in U = 12 12 x Larc /j = (12)(349.1 ft)/(745.7 in) = 5.62


51

X = 3 x Larc - (j/2) x tanh(U/2) = (3)(349.1 ft) - (0.5)(745.7 in)tanh(5.62/2) = 677.15 in 2

2

Y = 18 x (Larc) - j x [l - l/cosh(U/2)] 2 2 = (18)(349.1 ft) - (745.7 in) x [l - l/cosh(5.62/2)] 2 = 1,704,320 in N = [12 x Tave x h - (Ws/12) x cos x Y]/X 2 = [(12)(10,000 lb)(15.19 ft) -(l/12)(-46.21 lb/ft)(cos 10°)(1,704,320 in )]/677.15 in = 12,237 lb

The positive value indicates that N acting down is the reaction normal force required at the top of the hole to bend the buoyant pipe (in this example) into the curve required to match the pilot hole. = T c -T b = 2 x [frict] + DRAG - Ws x Larc x sin [frict] = N x µ soil = (12,237 lb)(0.3) = 3,671 lb DRAG = 12 x = (12) =

WS x Larc x sin

x D x Larc x µ mud 2 (12.75 in)(349.1 ft)(0.05 lb/in )

8,389 lb

= (-46.21 lb/ft)(349.1 ft)(sin 10º) = -2,801 lb = 2(3,671 lb) + 8,389 lb - (-2,801 lb) = 18,533 lb

Tc = + TB = 24,670 lb

Pull Load at Point C before T ave assumption check

Check accuracy of assuming T ave = 10,000 at the beginning of this iterative solution. T ave = (Tc + TB)/2 = (24,670 lb + 6,137 lb)/2 = 15,404 lb

Percent difference is (15,404 - 10,000)/10,000 x l00%, which is equal to 54%. This does not fall within an acceptable level of l0%, so the iteration process begins. Select 15,404 as


52

the value for the assumed T ave. Run through the same calculations and once again compare the calculated Tave with the assumed Tave. Continue the iteration until the percent difference is equal to or below 10%. In this example, a little iteration reveals that a more exact value for Tave is 15,698 lb, and thus, = 2(3,966 lb) + 8,389 lb - (-2,801 lb) = 19,122 lb T c = 25,259 lb

Pull Load at Point C

Straight Section at Point D.

= TD-Tc = [frict] + DRAG - Ws x L x sin [frict] = Ws x L x cos x µsoil = (-46.21 lb/ft)(500.3 ft)(cos 0° )(0.3) = 6,936 lb DRAG = 12 x x D x L x µ mud 2 = (12) (12.75 in)(500.3 ft)(0.05 lb/in ) = 12,024 lb

Ws x L x sin

= =

(-46.21 lb/ft)(500.3 ft)(sin 0°) 0 lb

= 6,936 lb + 12,024 lb - 0 lb = 18,960 lb

+ TC TD = = 44,219 lb

Pull Load at Point D

Curved section at Point E.

The iterative solution will yield Tave = 51,545 lb. The calculation is as follows: h = R x [l = (1200 ft)(l - cos 7°) = 8.94 ft I = 191.75 in

4

1/2

j = (E x I/Tave) 7 4 1/2 = [(2.9 x l0 psi)(191.75 in )/(51,545 lb)]

53


=

328.45 in

U = 12 x Larc /j = (12)(293.2 ft)/(328.45 in) = 10.71 X = 3 x Larc - (j/2) x tanh(U/2) = (3)(293.2 ft) - (0.5)(328.45 in)tanh(10.71/2) = 715.38 in 2

2

Y = 18 x (Larc) - j x [ 1 - l/cosh(U/2)] = [(18)(293.2 ft) 2 - (328.45 in) 2 x [l - l/cosh(10.71/2)] = 1,440,532 in2 N = [12 x Tave x h - (Ws/12) x cos x Y]/X = [(12)(51,545 lb)(8.94 ft) - (1/12)(-46.21 lb/ft)(cos 7°)(1,440,532 in 2)]/715.38 in = 15,427 lb The positive value indicates that N acting down is the reaction normal force required at the top of the hole to bend the buoyant pipe (in this example) into the curve required to match the pilot hole. = TE - TD = 2 x [frict] + DRAG + Ws x L x sin [frict] = N x µ soil = (15,427 lb)(0.3) = 4,628 lb DRAG = 12 x x D x L x µ mud 2 ( 12.75 in)(293.2 ft)(0.05 lb/in ) = (12) = 7,047 lb Ws x Larc x sin

= (-46.21 lb/ft)(293.2 ft)(sin 7°) = -1,651 lbf = 2(4,628 lb) + 7,047 lb + (-1,651 lb) = 14,652 lb

TD TE = = 58,871 lb

Pull Load at Point E


54

Straight Section at Point F.

= TF - TE = [frict] + DRAG + Ws x L x sin [frict] = Ws x L x cos x µ soil = (-46.21 lb/ft)(266.2 ft)(cos 14°)(0.3) = 3,581 lb DRAG = 12 x x D x L x µ mud 2 = (12) (12.75 in)(266.2 ft)(0.05 lb/in ) = 6,398 lb Ws x L x sin

= (-46.21 lb/ft)(266.2 ft)(sin 14°) = -2,976 lb

= 3,581 lb + 6,398 lb + (-2,976 lb) = 7,003 lb TF =

=

+ TE 65,874 lb

Pull Load at Point F

Total Pull Load, Ttot. The total pulling load is simply the sum of all the individual loads which is equal to the pulling load at point F. T tot = + = = 65,874 lb

+

+

+

Example Installation Stress Analysis

A complete analysis of the installation stresses experienced by the pipe requires stress calculations for any point where the combined stresses may be near a maximum. For this example case, examination of the pilot hole plot shows that the most likely location for high stress due to combined loading is at point E. This point is closer to the rig side and, therefore, will have relatively high local tension. It also is part of a tight radius curve (R = 1200 A) and is near the deepest point with the highest hydrostatic mud pressure. For completeness and confidence, stresses at points C and D should also be checked. Individual Stresses at Point E

From Figure 5-5, the depth at Point E is 64.4 ft below datum elevation.


55

Tensile stress.

f t = TE /A 2 2 = (58,871 lb) / [ (n/4) (12.75 - 12.25 )] = 5,997 psi Bending stress.

f b = (E x D)/(24)(R) 7 = (2.9 x 10 )(12.75)/[(24)(1200 ft)] = 12,839 psi External Hoop Stress.

f h = x D)/(2 x t) = (40.15 psi)(12.75 in)/[(2)(0.25 in)] = 1,024 psi = (12 ppg)(64.4 ft)/(l9.25) = 40.15 psi Allowable Tension.

Ft = 0.9 x SMYS = (0.9)(35,000 psi) = 31,500 psi Note that f t is less than 31,500 psi, so tension is within allowable limits. Allowable Bending.

F b = [0.84 - { 1.74 x SMYS x D/(E x t)}] x SMYS for 1,500,000/SMYS < D/t fe 3,000,000/SMYS 7

Fb = [0.84 - {(1.74)(35,000 psi)(12.75 in)/(2.9 x 10 psi x 0.25 in)}](35,000 psi) = 25,652 psi Note that f b is less than 25,652 psi, so bending is within allowable limits. Allowable Elastic Hoop Buckling. 2

F h e = 0.88 x E x (t/D) 7 2 = 0.88(2.9 x 10 )(0.25 in/12.75 in) = 9,812 psi and,


56

Fhc = Fhe for Fhe 0.55 X 35,000 psi F hc = 9,812 psi Note that f h is less than Fhc /l.5 = 6,541 psi, so external hoop stress is within allowable limits for buckling. Combined Load Interactions at Point E

Since all individual stress checks are acceptable, the combined load interaction checks will now be examined. Tensile and Bending.

f /(0.9 x SMYS) + (f b /Fb) t

1.0

[Unity check]

5,997 psi/(0.9 x 35,000 psi) + (12,839 psi/25,652 psi) = 0.69 0.69 < 1.0 so combined tensile and bending at Point E is acceptable. Tensile, Bending, and External Hoop.

A = [f t + f b - 0.5 x f h] x 1.25/SMYS = [5,997 psi + 12,839 psi - (0.5)(1,024 psi)](1.25)/(35,000 psi) = 0.654 B = 1.5 f h /Fhc = (1.5)(1,024 psi)/(9,812 psi) = 0.157 2

2

(0.654) + (0. 157) + (2)(0.3)(0.654)(0.157) = 0.51 0.51 < 1.0 so combined stresses at Point E are acceptable. Operating Loads and Stresses

With one exception, the operating loads and stresses in a pipeline installed by HDD are not materially different from those experienced by pipelines installed by cut and cover techniques; therefore, past procedures for calculating and limiting stresses can be applied. The exception involves elastic bending. A pipeline installed by HDD will contain elastic bends. The pipe will not be bent to conform to the drilled hole as a pipeline installed by cut and cover is bent to conform to the ditch. Bending stresses imposed by the HDD installation


57

method will generally not be severe. However, they should be checked in combination with other longitudinal and hoop stresses to insure that acceptable limits are not exceeded. The operating loads imposed on a pipeline installed by HDD are listed below: internal pressure from the fluid flowing in it, elastic bending as the pipe conforms to the shape of the drilled hole, thermal resulting from the difference between the constructed (locked in)

temperature and the operating temperature.

Formulas for calculating stresses produced by internal pressure and elastic bending have been previously listed (5.15 and 5.16) and are repeated below. Bending stress.

f b = (E x D)/(24 x R)

(5.15)

Hoop Stress.

f h =

x D)/(2 x t)

(5.16)

In this case Ap is equal to the difference between hydrostatic pressure exerted by groundwater acting on the outside of the pipe and the pressure from the fluid (gas) flowing inside of the pipe. Note that for this analysis Ap producing a tensile external hoop stress is taken as positive. The formula for calculating thermal stresses is taken from ASME/ANSI B31.4 Thermal Stress.

f t = (E x k) x (T1-T2)

(5.3 1)

where, k

=

the coefficient of thermal expansion for steel (0.0000065 inches per inch per ºF)(ANSI B31.4)

TI

=

Constructed temperature in ºF

T2

=

Operating temperature in ºF

Combined Stresses and Limitations

Combined stresses can be analyzed by calculating the maximum shear stress on a small element in the pipeline. This maximum shear stress should be limited to 45% of the SMYS


58

of the pipe (ASME/ANSI B31.4). The maximum shear stress at any element is calculated using the following formula (Timoshenko and Gere). (5.32)

f v = (f hoop - f long)/2 where, f hoop =

the total hoop stress acting on the element

f long

the total longitudinal stress acting on the element

=

Note that in this analysis all tensile stresses are positive and all compressive stresses are negative.

The total hoop stress is determined using equation 5.16. The total longitudinal stress is determined by taking the sum of the longitudinal stresses resulting from bending (equation 5.15), thermal (equation 5.31), and internal pressure (equation 5.33). Longitudinal stress from internal pressure is calculated as follows: f p = f h x v

(5.33)

where, v = Poisson’s ratio (0.3 for steel)

The maximum shear stress will occur in an element on the compressive side of an elastic bend and at the maximum distance from the neutral axis of the bend. Example Operating Stress Analysis

Using the same example previously analyzed for installation stresses, check the combined operating stresses. Relevant data are listed below: D = 12.75 in Pipe: Grade B Steel

t = 0.25 in SMYS = 35,000 psi

7

E = 2.9 x 10 psi

The total depth for the horizontal straight section is 100 feet below the entry/exit datum elevation and the groundwater table is assumed to be 10 feet below the entry/exit datum. The shortest radius of curvature is 1,000 feet on the right curve. The maximum allowable operating pressure is 720 psi. The construction temperature is 60 ºF and the operating temperature is 80 ºF. Bending Stress.

f b = (E x D)/(24 x R) 7 = (2.9 x 10 psi)(12.75 in)/(24)(1000 ft)


59

= ±15,406 psi Hoop Stress.

= 720 psi - (90)(0.4333) 681 psi f h = x D)/(2 x t) = (681 psi)(12.75 in)/(2)(0.25 in) = +17,366 psi Thermal Stress.

f t = (E x k) x (Tl - T2) 7 = (2.9 x 10 psi)(0.0000065)(60 ºF- 80 ºF) = -3,770 psi Total Longitudinal Compressive Stress.

f long = -15,406 psi + -3,770 psi + (17,366 psi)(.3) = -13,966 psi Maximum Shear Stress

f v =

(f hoop - f long)/2 = [17,366 psi - (-13,966 psi)]/2 = 15,666 psi

The allowable shear stress is 15,750 psi (45% of 35,000 psi) which is greater than 15,666 psi. Therefore, the pipe specification is acceptable. It should be noted that violation of the 45% limit on shear stress does not necessarily mean that the pipeline will fail. Bending loads resulting from HDD installation are not sustained. That is, they may be relieved by plastic deformation. However, operating stresses should be maintained in the elastic range to provide a conservative design. Spreadsheet - Load and Stress Analysis

Hand calculations for a given pipeline installation case can be done; however, software to assist and do alternate scenario calculations would obviously be helpful for this analysis method. A Lotus spreadsheet routine for performing the installation load and stress calculations is included in the file PULL.WK4AVK3 on the diskette attached to the back cover of this manual. An example of this spreadsheet is attached at the end of this section for the pilot hole and stress point calculations explained in the previous subsections. By using this spreadsheet, a few alternate scenario cases can be calculated to observe effects of changing key parameters. For example, pull forces and combined stresses for this case can be significantly altered by assuming the pipe is pulled in flooded with water instead of empty.


60

The spreadsheet results of this alternate scenario are attached at the end of this section. Other interesting cases to examine are the effects of a tighter than designed radius in the curved sections, varying the mud weight in the hole, and using thicker walled pipe. A Lotus spreadsheet routine for performing the operating load and stress calculations is included in the file STRESS.WK4WK3 on the diskette attached to the back cover of this manual. An example of this spreadsheet is attached at the end of this section for the calculations explained in the previous subsections. References

API RP 2A-WSD, Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms -- Working Stress Design, Twentieth Edition, (Dallas, Texas; American Petroleum Institute, 1993) Fowler, J.R. and Langner, C.G., “Performance Limits for Deepwater Pipelines”, OTC 6757, 23rd Annual Offshore Technology Conference, Houston, TX, May 6-9, 1991. Loh, J.T., “A Unified Design Procedure for Tubular Members”, OTC 6310, 22nd Annual Offshore Technology Conference, Houston, TX, May 7-10, 1990. Maidla, E.E., “Borehole Friction Assessment and Application to Oilfield Casing Design in Directional Wells”, doctoral dissertation Louisiana State University, Department of Petroleum Engineering, Baton Rouge, LA, December 1987. Meijers, P., “Review of a Calculation Method for Earth Pressure on Pipelines Installed by Directional Drilling”, Delft Geotechnics, Report CO-341850/4 commissioned by N.V. Netherlands Gasunie, March 1993. NEN 3650, “Requirements for Steel Pipeline Transportation Systems”, unofficial translation, Government/Industry Standards Committee 343 20, The Netherlands, 1992. NEN 3651, “Supplementary Requirements for Steel Pipelines Crossing Major Public Works (Dykes, High Level Canals, Waterways, Roads)“, unofficial translation, Government/Industry Standards Committee 343 20, The Netherlands, February 1994. Roark, R. J., Formulas for Stress and Strain, Second Edition & Fifth Edition. (New York, New York; McGraw-Hill, 1943, 1965) ASME/ANSI B31.4-1986 Edition with 1987 Addenda, Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum Gas, Anhydrous Ammonia, and Alcohols. (New York, New York; The American Society of Mechanical Engineers, 1987) Timoshenko, S. P. and Gere, James M., Mechanics of Materials. (New York, New York; Van Nostrand Reinhold Company, 1972)

Date: 04/26/95

Page 1 of 2

ANALYSIS OF INSTALLATION LOADS AND STRESSES PROJECT:

HDD Design Guide, Example Calculation

GENERAL DATA

Pipe Diameter: Wall Thickness: SMYS: Young’s Modulus: Total Pipe Length: Moment of Inertia: Pipe Face Surface Area: Diameter/wall thickness ratio: Poisson’s ratio: Mud Weight: Coeff. of Soil Fric.: Fluid Drag Coeff.:

PIPE WEIGHT DATA

12.75 0.250 35,000 2.9E+07 1,525 191.75 9.82 51.00 0.30 89.76 0.30 0.05

Inches Inches Psi Psi ft Inches^4 Inches^2 Lb/cu.ft Psi

Pipe Weight in Air: 33.38 Lb/ft Pipe Interior Vol.: 0.82 cu.ft/ft Pipe Exterior Vol.: 0.89 cu.ft/ft Air Line Weight: 0.00 Lb/ft Air Line Diameter: 0.00 Inches Air Line Ext. Vol.: 0.000 cu.ft/ft Weight of Water: 0.00 Lb/ft Displaced Mud Weight: 79.58 Lb/ft Water density (enter 0 for no buoyancy control): 0.00 Lb/cu.ft Effective Wt. of pipe: -46.21 Lb/ft Note: positive value indicates downward force

ANALYSIS OF LOADS FOR STRAIGHT SECTION PULLED DOWNSLOPE

Measured Length: Angle of Inclination: =

116.10 ft 20.00 degrees 0.35 radians

Axial Tension limited by RP2A-WSD Comparison: Longitudinal Bending limited by RP2A-WSD Comparison:

Drag Forces from Mud: Friction from Soil: Effective Weight of Pipe:

2,790 Lb 1,512 Lb (1,835) Lb

Tension on section: Cumulative Force exerted:

6,138 Lb 6,138 Lb

625 Psi

< 31,500

0 Psi

< 25 , 65 2

External Hoop Stress limited by RP2A-WSD Comparison: 631 Psi

< 6 ,541

Combined Stresses, Tensile & Bending, limited by RP2A-WSD Comparison: 1.00 0.02 < Combined Stresses, Tensile, Bending & Hoop limited by RP2A-WSD < Comparison: 0.01 1.00

ANALYSIS OF LOADS FOR CURVILINEAR SECTION PULLED DOWNSLOPE

Measured Length: Change in Inclination Angle: = Radius of Curvature: Center Displacement:

349.07 20.00 0.35 1000.00 15.19

ft degrees radians ft ft

Assumed Average Tension:

15,698 Lb

Normal Force: Drag Forces from Mud: Friction from Soil: Effective Weight of Pipe:

13,218 Lb 8,389 Lb 7,931 Lb (2,801) Lb

Tension on section: Average Tension: Cumulative Force exerted:

19,121 Lb 15,698 Lb 25,259 Lb

Axial Tension limited by RP2A-WSD Comparison:

2,573 Psi

< 31,500

Longitudinal Bending limited by RP2A-WSD Comparison: 15,406 Psi

< 2 5, 65 2

External Hoop Stress limited by RP2A-WSD Comparison: 1,595 Psi < 6,541 Combined Stresses, Tensile & Bending, limited by RP2A-WSD Comparison: 0.68 < 1.00 Combined Stresses, Tensile, Bending & Hoop limited by RP2A-WSD Comparison: 1.00 0.53 <

Date: 04/26/95

Page 2 of 2

ANALYSIS OF LOADS FOR HORIZONTAL STRAIGHT SECTION




4,504 Psi

Longitudinal Bending limited by RP2A-WSD Comparison: Drag Forces from Mud: Friction from Soil: Effective Weight of Pipe:

12,024 Lb 6,936 Lb 0 Lb


18,959 Lb 44,218 Lb

0 Psi

< 3 1 , 50 0

< 25,652

External Hoop Stress limited by RP2A-WSD Comparison: 1,592 Psi < 6,541 Combined Stresses, Tensile & Bending, limited by RP2A-WSD Comparison: 0.14 < 1.00 Combined Stresses, Tensile, Bending & Hoop limited by RP2AWSD Comparison: 0.10 < 1.00

ANALYSIS OF LOADS FOR CURVILINEAR SECTION PULLED UPSLOPE

Measured Length: Change in Incl. Angle: = Radius of Curvature: Center Displacement:

293.22 ft 14.00 degrees 0.24 radians 1200.00 ft 8.94 ft

Assumed Average Tension:

51,545 Lb

Normal Force: Drag Forces from Mud: Friction from Soil: Effective Weight of Pipe:

15,430 Lb 7,047 Lb 9,258 Lb (1,651) Lb


14,654 Lb 51,545 Lb 58,872 Lb


5,997 Psi

<

31,500

Longitudinal Bending limited by RP2A-WSD Comparison: 12,839 Psi < 25,652 External Hoop Stress limited by RP2A-WSD Comparison: 1,024 Psi < 6,541 Combined Stresses, Tensile & Bending, limited by RP2A-WSD Comparison: 0.69 < 1.00 Combined Stresses, Tensile, Bending & Hoop limited by RP2A-WSD < Comparison: 0.51 1.00

ANALYSIS OF LOADS FOR STRAIGHT SECTION PULLED UPSLOPE

Length of Section: Angle of Inclination: =



6,398 Lb 3,581 Lb (2,976) Lb


7,002 Lb 65,874 Lb


6,710 Psi

<

31,500

Longitudinal Bending limited by RP2A-WSD Comparison:

0 Psi

<

25,652

External Hoop Stress limited by RP2A-WSD Comparison:

0

<

6,541

Psi

Combined Stresses, Tensile & Bending, limited by RP2A-WSD < Comparison: 0.21 1.00 Combined Stresses, Tensile, Bending & Hoop limited by RP2A-WSD Comparison: 0.06 < 1.00

TOTALS

Total Pulling Force: Stress Violations:

65,874 Lb 0

Date: 04/26/95

Page 1 of 2

ANALYSIS OF INSTALLATION LOADS AND STRESSES PROJECT:

HDD Design Guide, Example Calculation - Alternate Scenario Case

GENERAL DATA

Pipe Diameter: Wall Thickness: SMYS: Young’s Modulus: Total Pipe Length: Moment of Inertia: Pipe Face Surface Area: Diameter/wall thickness ratio: Poisson’s ratio: Mud Weight: Coeff. of Soil Fric.: Fluid Drag Coeff.:

PIPE WEIGHT DATA

12.75 0.250 35,000 2.9E+07 1,525 191.75 9.82 51.00 0.30 89.76 0.30 0 .0 5

Inches Inches Psi Psi ft Inches^4 Inches^2

Lb/cu.ft Psi

Pipe Weight in Air: 33.38 Lb/R Pipe Interior Vol.: 0.82 cu.ft/ft Pipe Exterior Vol.: 0.89 cu.ft/ft Air Line Weight: 0.00 Lb/ft Air Line Diameter: 0.00 Inches Air Line Ext. Vol.: 0.000 cu.ft/ft Weight of Water: 51.07 Lbm Displaced Mud Weight: 79.58 Lb/ft Water density (enter 0 for no buoyancy control): 62.40 Lb/cu.ft Effective Wt. of pipe: 4.86 Lb/ft Note: positive value indicates downward force

ANALYSIS OF LOADS FOR STRAlGHT SECTION PULLED DOWNSLOPE



Axial Tension limited by RP2A-WSD Comparison: Longitudinal Bending limited by RP2A-WSD Comparison:


2,790 Lb 159 Lb 193 Lb


2,756 Lb 2,756 Lb

281 Psi

< 31,500

0 Psi

< 25,652


< 6 ,541

Combined Stresses, Tensile & Bending, limited by RP2A-WSD < Comparison: 0.01 1.00 Combined Stresses, Tensile, Bending & Hoop limited by RP2A-WSD Comparison: 0.00 < 1.00

ANALYSIS OF LOADS FOR CURVILINEAR SECTION PULLED DOWNSLOPE

Measured Length: Change in Inclination Angle: = Radius of Curvature: Center Displacement: Assumed Average Tension: Normal Force: Drag Forces from Mud: Friction from Soil: Effective Weight of Pipe: Tension on section: Average Tension: Cumulative Force exerted:

349.07 ft 20.00 degrees 0.35 radians l000.00 ft 15.19 ft 7,136 Lb 1,107 8,389 664 295

Lb Lb Lb Lb

8,759 Lb 7,136 Lb 11,515 Lb


1,173 Psi

<

31,500


<

25,652


< 6,541

Combined Stresses, Tensile & Bending, limited by RP2A-WSD 1.00 Comparison: 0.64 < Combined Stresses, Tensile, Bending & Hoop limited by RP2A-WSD Comparison: 0.37 < 1.00

Date: 04/26/95

Page 2 of 2

ANALYSIS OF LOADS FOR HORIZONTAL STRAIGHT SECTION




2,472 Psi

Longitudinal Bending limited by RP2A-WSD Comparison: Drag Forces from Mud: Friction from Soil: Effective Weight of Pipe:

12,024 Lb 730 Lb 0 Lb


12,754 Lb 24,269 Lb

0 Psi

< 31,500 < 25,652

External Hoop Stress limited by RP2A-WSD Comparison: 485 Psi < 6,541 Combined Stresses, Tensile & Bending, limited by RP2A-WSD Comparison: 0.08 < 1.00 Combined Stresses, Tensile, Bending & Hoop limited by RP2A-WSD Comparison: 0.02 < 1.00

ANALYSIS OF LOADS FOR CURVILINEAR SECTION PULLED UPSLOPE

Measured Length: Change in Incl. Angle: = Radius of Curvature: Center Displacement: Assumed Average Tension: Normal Force: Drag Forces from Mud: Friction from Soil: Effective Weight of Pipe:


293.22 ft 14.00 degrees 0.24 radians 1200.00 ft 8.94 ft 29,045 Lb 3,887 7,047 2,332 174

Lb Lb Lb Lb

9,553 Lb 29,045 Lb 33,822 Lb


3,445 Psi < 31,500


< 25,652

External Hoop Stress limited by RP2A-WSD Comparison: 312 Psi < 6,541 Combined Stresses, Tensile & Bending, limited by RP2A-WSD < Comparison: 1.00 0.61 Combined Stresses, Tensile, Bending & Hoop limited by RP2A-WSD Comparison: 0.35 < 1.00

ANALYSIS OF LOADS FOR STRAIGHT SECTION PULLED UPSLOPE

Length of Section: Angle of Inclination: =



6,398 Lb 377 Lb 313 Lb


7,088 Lb 40,909 Lb


4,167 Psi

< 3 1 ,5 00

Longitudinal Bending limited by RP2A-WSD Comparison:

0 Psi

< 25,652

External Hoop Stress limited by RP2A-WSD Comparison:

0 Psi

< 6,541

Combined Stresses, Tensile & Bending, limited by RP2A-WSD Comparison: 1.00 0.13 < Combined Stresses, Tensile, Bending & Hoop limited by RP2A-WSD Comparison: 0.02 < 1.00

TOTALS

Total Pulling Force: Stress Violations:

40,909 Lb 0

Page 1 of 2

Date: 04/26/95

ANALYSIS OF OPERATING STRESSES PROJECT: HDD Design Guide, Example Calculation GENERAL DATA Pipe Diameter (inches): Wall Thickness (inches): SMYS (psi): Maximum Allowable Operating Pressure (psi): Poisson’s ratio: Young’s Modulus: Radius of Curvature (feet): Coefficient of Thermal Expansion (inches/inch/degree F): Installation Temperature (degrees F): Operating Temperature (degrees F): Groundwater table head (feet):

12.75 0.250 35,000 720 0.30 2.9E+07 1,000 6.5E-06 60 80 90

ANALYSIS

Longitudinal Stress from Bending = % SMYS =

15,406 psi 44.0%

Hoop Stress = % SMYS =

17,366 psi 49.6%

Longitudinal Compressive Stress from Hoop Stress = % SMYS =

5,210 psi 14.9%

Longitudinal Stress from Thermal Expansion = % SMYS =

(3,770) psi 10.8%

Net Longitudinal Compressive Stress = % SMYS =

(13,966) psi 39.9%

Maximum Shear Stress = % SMYS =

15,666 psi 44.8%

Hoop stress limited by design factor from 49 CFR Part 192.111.

Shear stress limited to 45% of SMYS by 402.3.1 of ASME/ANSI B31.4.


SECTION 6 - CONSTRUCTION IMPACT

61

SECTION 6 CONSTRUCTION IMPACT

The environmental impact associated with construction of a pipeline crossing by HDD is significantly less than that associated with construction by open cut excavation. Nevertheless, HDD installation is not totally without impact. This impact must be considered when designing a drilled installation and centers around two areas: workspace and drilling fluids. Workspace

Although workspace requirements for HDD may be different than open cut construction, the associated impact is basically the same. Working areas must be cleared and graded to allow movement and erection of equipment. Workspace requirements for horizontal drilling rig and pull section fabrication operations are described in the following paragraphs. Horizontal Drilling Rig

A typical large horizontal drilling rig can be moved onto a site in approximately seven tractor trailer loads. A workspace of 150 feet (45.7 m) by 250 feet (76.2 m) is adequate for most operations. If necessary, a rig may be assembled in a minimal workspace of 60 feet (18.3 m) by 150 feet (45.7 m). However, this minimal workspace will restrict the size and capacity of the drilling rig. A typical horizontal drilling rig site plan is shown in Figure 6 - 1. Photographs of rigsites are shown in Figures 6-2 and 6-3.

Figure 6-l Typical Site Plan, Horizontal Drilling Rig

62


(photo courtesy of Rending & Rates Construction Co.)

Figure 6-3 (photo courtesy of Reading & Bates Construction Co.)


63

Space requirements will vary depending on the make and model of the drilling rig and how the various components may be positioned. However, the location of the principal components of the rig (rig ramp, drill pipe, and control van) are fixed by the entry point. The rig ramp must be positioned in line with the drilled segment and approximately 25 feet (7.6 m) back from the entry point. The control van and pipe must be positioned adjacent to the rig.

The workspace must be cleared and graded level. The equipment is typically supported on the ground surface. Timber mats may be used where soft ground is encountered. For marine locations, it is possible to operate off of a raft of barges. Pull Section Fabrication

Pipe pull section fabrication is accomplished using the same construction methods used to lay a pipeline. Therefore, similar workspace is required. A typical pull section fabrication site plan is shown in Figure 6-4. Photographs of pull sections during pull back are shown in Figures 6-5 and 6-6. Note that a flotation ditch has been used in Figure 6-5.

Figure 6-4

Typical Site Plan, Pull Section Fabrication

The location of pull section fabrication workspace is controlled by the drilled segment exit point. Space must be available to allow the pipe to be fed into the drilled hole. It is preferable to have workspace in line with the drilled segment and extending back from the exit point the length of the pull section plus 200 feet (61 m). This will allow the pull section to be prefabricated in one continuous length prior to installation. If space is not available, the pull section may be fabricated in two or more sections which are welded together during installation.

64





65

The pull section fabrication workspace must be cleared but need not be graded level. Equipment is typically supported on the ground surface. Timber mats may be used where soft ground is encountered. Drilling Fluids

The primary impact of HDD on the environment revolves around the use of drilling fluids. Where regulatory problems are experienced, the majority of concerns and misunderstandings are associated with drilling fluids. An awareness of the function and composition of HDD drilling fluids is imperative in producing a permittable and constructable HDD crossing design. A detailed discussion of drilling fluids involved with HDD installations can be found in a report prepared for the Pipeline Research Committee of the American Gas Association entitled Drilling Fluids in Pipeline Installation by Horizontal Directional Drilling, A Practical Applications Manual. The elements of HDD drilling fluid flow during pull back are shown in Figure 6-7.

Figure 6-7

HDD Drilling Fluid Flow Schematic


66

Functions

The principal functions of drilling fluid in HDD pipeline installation are listed below. l

l

Transportation of Spoil. Drilled spoil, consisting of excavated soil or rock cuttings, is suspended in the fluid and carried to the surface by the fluid stream flowing in the annulus between the hole and the pipe. Cooling and Cleaning of Cutters. Drilled spoil build-up on bit or reamer cutters is

removed by high velocity fluid streams directed at the cutters. Cutters are also cooled by the fluid. l

l

Reduction of Friction. Friction between the pipe and the hole wall is reduced by the lubricating properties of the mud. Hole Stabilization. The drilled or reamed hole is stabilized by the drilling fluid. This is

critical in HDD pipeline installation as holes are typically in soft soil formations and are uncased. Stabilization is accomplished by the drilling fluid building up a wall cake and exerting a positive pressure on the hole wall. Ideally, the wall cake will seal pores and produce a bridging mechanism to hold soil particles in place. l

Transmission of Hydraulic Power. Power required to turn a bit and mechanically drill a

hole is transmitted to a downhole motor by the drilling fluid. l

l

Soil is excavated by erosion from high velocity fluid streams directed from jet nozzles on bits or reaming tools.

Hydraulic Excavation.

Soil Modification. Mixing of the drilling fluid with the soil along the drilled path

facilitates installation of a pipeline by reducing the shear strength of the soil to a near fluid condition. The resulting soil mixture can then be displaced as a pipeline is pulled into it. Composition

The primary component of drilling fluid used in HDD pipeline installation is fresh water found at the location. In order for water to perform the functions previously listed, it is generally necessary to modify its properties by adding a viscosifier. The viscosifier almost exclusively used is a naturally occurring clay in the form of bentonite. The term bentonite includes any member of the general montmorillonite group, which includes montmorillonite, beidellite, nontronite, hectorite, and saponite. The bentonite normally used in drilling fluids comes from Wyoming and South Dakota and is principally sodium montmorillonite (Bleier, Leuterman and Stark, p. 10) (Lummus and Azar, p. 111). It is not a hazardous material as defined by the U.S. Environmental Protection Agency characteristics of ignitability, corrosivity, reactivity or commercial chemicals. It is also used to seal earth structures such as ponds or dams and as a suspending component in livestock feeds.


67

The properties of bentonite used in drilling fluids are often enhanced by the addition of polymers. This enhancement typically involves increasing the yield. That is, reducing the amount of dry bentonite required to produce a given amount of drilling fluid. For use in drilling fluids, Wyoming bentonite yields in excess of 85 barrels (42 gal/bbl) per ton of material. Addition of polymers to produce high yield bentonite can increase the yield to 200 barrels per ton of material. The polymers used have varying properties and, if a detailed description is required, specific products should be investigated. Quantity Estimating Calculations

Reasonable estimates of the quantity of drilling fluid and fluid components which will be consumed or disposed of on an HDD installation are important in assessing the impact of drilling activities. Calculation of quantities consumed can be accomplished by breaking the installation down into its separate phases and assuming drilling parameters for each phase. Formulas for calculating quantities are presented below along with a discussion of drilling parameters. It should be noted that these formulas are for use in estimating and contain assumptions and simplifications. Pilot Hole Drilling. The total volume, VP, in barrels of drilling fluid consumed (not available

for recirculation) during pilot hole drilling can be found using the relation, Vp = Qp x (L/P) x fp x f 1p

(6.1)

where, =

The drilling fluid flow rate in barrels per minute (bpm). This will range from between 2 to 6 bpm for soil crossings and up to 12 bpm for rock crossings where a large diameter mud motor is used.

L

=

The total drilled length in feet.

P

=

The estimated pilot hole production rate in feet per hour (fph). This is a production rate and not a penetration rate. It includes time spent redrilling, surveying, adding pipe, etc.

=

The pumping factor in minutes per hour. This indicates the actual time that the mud pump is pumping downhole. For example, a pumping factor of 35 indicates a pumping duration of 35 minutes for every hour of drilling. The remaining time is spent surveying, adding pipe, etc.

=

The pilot hole circulation loss factor.

Prereaming. The total volume, Vr, in barrels of drilling fluid consumed (not available for

recirculation) during a single prereaming pass is given by the following equation. In the event that multiple prereaming passes are to be executed, V r should be either calculated for each


68

pass or multiplied by the number of passes depending on the accuracy required for the quantity estimate.

Vr = Qr x (L/Tr) x f 1r

(6.2)

where,

Qr

=

The drilling fluid flow rate in barrels per minute (bpm). This will range from 6 to 20 bpm depending primarily on the diameter of the reamer.

L

=


Tr

=

The estimated prereaming penetration rate, or travel speed, in feet per minute (fpm). This is the speed at which the reamer is being pulled along the pilot hole. It is dependent on soil conditions and reamer size and can range from a lower value of 0.5 fpm in rock to a higher value of 3 fpm in soft soils.

f 1r

=

The prereaming circulation loss factor.

Pulling Back. The total volume, Vb, in barrels of drilling fluid consumed (not available for recirculation) during pull back (pipe installation) is given by,

Vb = Qb x (L/Tb) x f 1b

(6.3)

where, Qb

=

The drilling fluid flow rate in barrels per minute (bpm). This will range from 6 to 20 bpm depending primarily on the diameter of the pipe being installed.

L

=


Tb

=

The estimated pull back penetration rate, or travel speed, in feet per minute (fpm). This is the speed at which the pipe is being pulled into the reamed hole. It is dependent primarily on pipe diameter but can also be affected by the quality of the reamed hole. It can range from a lower value of 2 fpm to a higher value of 10 fpm.

f 1b

=

The pull back circulation loss factor.

The total estimated volume of drilling fluid consumed (V cons) for a given installation is then the sum of VP, Vr, Vb, and the fluid system line fill. The fluid system line fill is the volume of fluid remaining in surface piping, tankage and the reamed hole annulus at the completion of pull back. This will be well under 1,000 barrels for most installations.


69

It should be noted that this estimate does not take into account drilling fluid which has been discharged for disposal at the surface. The assumption is made for estimating purposes that all fluids which return to the surface are recirculated. This is valid given the inaccuracy of the circulation loss factors. In actuality, drilling fluid will be discharged with wet spoil from the solids control system (refer to Figure 6-7). Once the total volume of drilling fluid consumed is calculated, it can be broken down into its individual components. Formulas for accomplishing this are presented below. Viscosifier. The dry bulk volume, Vvis, in cubic yards of viscosifier consumed in the

installation can be determined from the following equation. The viscosifier will typically be bentonite. Vvis = [(Vcons /y) /Wdry] x 74.07

(6.4)

where, Y

=

The drilling fluid yield of the viscosifier in barrels per ton. Bentonite yields in excess of 85 barrels of 15 cps fluid per ton. High yield bentonites, those enhanced by the addition of polymers, yield in excess of 200 barrels of 15 cps fluid per ton. The yield will vary based on the viscosity of the final fluid. The values stated above are suitable for quantity estimating purposes.

Wdry =

The dry weight of the viscosifier in pounds per cubic foot. This is 55 pounds per cubic foot for packaged bentonite.

Water. For practical estimating purposes, the volume of water consumed is equal to the total volume of drilling fluid consumed. Drilled Spoil. The volume of the reamed hole, V spoil, in cubic yards, reduced by the average of the circulation loss factors for reaming and pulling back, is determined from equation 6.5.

This takes into account the fact that spoil is transported to the surface suspended in drilling fluid. If the fluid does not return to the surface, neither does the spoil. For a conservative estimate, the circulation loss factors can be set at 0 and V spoil will equal the volume of the reamed hole. General observations of the quantity of spoil on drilled crossings indicate it is typically less than the volume of the reamed hole. 2

Vspoil = [(L x D )/2200] x [ 1 - (f 1b + f 1r)/2]

(6.5)

where, D

=

The outside diameter (in inches) of the pipe being installed. The formula presented uses a factor of 1.5 to determine the reamed hole diameter from the pipe outside diameter.


70

L

=


Typical drilling parameters for use in formulas 6.1 through 6.3 are presented in the tables in Section 2. A Lotus spreadsheet routine for performing these calculations is included in the file labeled QTY.WK4 on the diskette attached to the back cover of this manual. A copy of an example from this routine is included at the end of this section. Recommended Disposal Methods

The primary method of disposal for excess drilling fluid on an HDD installation is dispersal at the drill site. As an alternative, excess fluid, or its components, may be hauled to a remote disposal location. Disposal of excess drilling fluid in a waterway is not recommended. The method of disposal applied to a specific crossing will be dependent on the size and location of the crossing as well as any applicable local regulations.

In addressing regulations, it is important to remember that HDD drilling fluid is composed typically of water, high yield bentonite, and drilled spoil. The major component of the fluid is water normally taken from a waterway or municipal source. For almost all applications, the only foreign material introduced to the location is a naturally occurring bentonite. Applicable disposal regulations should be similar to those governing sedimentation and erosion control, hydrotest water disposal, or general excess construction spoil disposal. The amount of excess drilling fluid involved in a given installation will govern the configuration of the drilling fluid system and whether or not the excess fluid must be separated into its component parts for disposal. For smaller applications, the amount of excess fluid may be minimal and can be discharged directly at the drill site. The site can then be restored in accordance with general construction specifications leaving no appreciable impact from the drilling fluid discharge. For larger applications, dewatering equipment may be employed to separate the solids (bentonite and spoil) from the water. The water can then be discharged and the solids handled as general excess construction spoil. Until the early 80’s, excess drilling fluid on HDD waterway crossings was, in most cases, discharged directly into the waterway. Surface returns were typically not recirculated but rather allowed to flow into the waterway from collection pits. Most crossings were in rural locations in the United States Gulf Coast region beneath rivers which carried a generally high sediment load. Return of river water containing additional suspended solids was not considered detrimental. This was particularly true when compared with the increase in suspended solids involved with a crossing installed by the open excavation methods HDD was replacing. Historical Background.

In recent years, three general trends have eliminated discharge into the waterway as a suitable disposal method. First, HDD began to be applied in locations with sensitive clear water streams. Deliberate introduction of suspended solids into these waterways had a negative


71

environmental impact and could not be allowed. Second, general sedimentation control on all construction operations became a requirement. It was not reasonable to protect a waterway with sedimentation control barriers and then bypass the barriers with a drilling fluid discharge line. Third, oil field drilling fluids were identified as substances requiring special disposal procedures. Although placing oil field drilling fluids and HDD drilling fluids in the same classification is not valid, concern and confusion regarding regulations governing oil field drilling fluids does exist. Recirculation. The first step in effectively dealing with excess drilling fluid disposal is to eliminate, or minimize, the excess. This is accomplished by recirculating drilling fluid returns

to the extent practical. Recirculation on an HDD waterway crossing is complicated by the fact that a significant portion of the drilling fluid returns occur at the exit point on the bank opposite of the drilling rig. This requires either two drilling fluid systems to be utilized or transportation of returns from the exit point to the drilling rig location. Transportation of drilling fluid returns can be accomplished by truck, barge or a temporary recirculation line drilled beneath the bottom of the waterway. Which system is most advantageous will be determined by site specific conditions. In some cases, temporary recirculation lines have been laid directly on the bottom of the waterway. However, this procedure involves the risk of rupture and resulting discharge of drilling fluid into the waterway. Collected surface returns should be processed through a solids control system which removes spoil from drilling fluid, allowing the fluid to be reused. Experience in the oil field has demonstrated that removal of drilled spoil enhances drilling performance by providing cleaner fluid with a minimum low gravity solids content (McKee, Geehan and Smolen, p. 38). A detailed discussion of solids control systems can be found in Chapter Y of the IADC Drilling Manual. The basic method used for unweighted water base HDD fluids is mechanical separation. Components of a typical mechanical separation system with general particle removal ranges from the IADC Drilling Manual are listed below. 1.

Standard Shale Shaker - 440 microns and larger.

2. Fine Screen Shaker - 74 microns and larger (weighted muds). 44 microns and larger (unweighted muds). 3. Mud cleaner - 74 microns and larger (weighted muds). 44 microns and larger (unweighted muds). 4. Desanders - 100 microns and larger.

5. Desilters - 15 microns and larger.

6. Centrifuge - 4 to 8 microns and smaller (weighted muds); 4 to 8 microns and larger (unweighted muds). (1 micron = 0.00003937 inches)


72

Solids control systems are not 100% efficient. That is, spoil discharged is not dry and totally free of drilling fluid and fluid discharged is not totally free of drilled spoil. Observations on oil field drilling rigs indicate that the efficiency of solids control systems ranges from 60% to 80% (Beasley and Dear, p. 145). The consistency of the spoil discharged from a solids control system may be similar to ready mix cement or a very viscous drilling fluid depending on factors such as the subsurface material being penetrated, drilling fluid properties, or the skill of the operator. Land Farming. Land farming provides an efficient and effective way to dispose of excess

drilling fluids or drilled spoil. Basically, it involves distributing the excess material evenly over an open area and mechanically incorporating it into the soil. The degree of mechanical tilling will be dictated by the character and amount of the waste. Small quantities of whole fluid will dissipate with little or no tilling. If large quantities of fluid or wet spoil are involved, a significant tilling effort will be required to insure that the waste will not form a dry crust and remain in a semi-solid state over an extended period of time. The condition of the land farming site should typically be governed by standard construction clean-up and site restoration specifications. Dewatering. The objective of a dewatering system is to remove all of the solids from the

drilling fluid. Solids removed include not only drilled spoil, but also the commercial solids which have been added to enhance fluid properties (typically high yield bentonite). Dewatering can take place during drilling operations or after completion. If dewatering is concurrent with drilling, processed water should be returned to the active fluid system for mixing and reuse. If dewatering follows construction, processed water should be discharged in accordance with local regulations. Solids produced by an appropriate dewatering system should be “dry”. That is, they can be handled with standard earth moving and hauling equipment. They should be disposed of in accordance with local regulations. Typically, this will be in a similar manner to general excavation spoil. However, regardless of the disposal requirements for dry spoil, costs will be significantly reduced by eliminating liquid waste and minimizing the total mass of material requiring disposal. Briefly, dewatering involves injecting coagulants or flocculating chemicals into the drilling fluid as it enters a large clarifying centrifuge. This coagulates the fine drilled particles allowing them to be separated from the water. The basic steps in dewatering a typical HDD drilling fluid are listed below (West and Pharis, p. 84). 1. Drilling fluid from the active system is diverted into an injection unit and treated with flocculants.

2. The treated fluid is passed into a clarifying centrifuge where flocculated solids are separated from the water. The solids are disposed of in an appropriate manner.


73

3. The water passes into a quality control tank where it can be monitored and reprocessed if necessary. 4. Suitably processed water can then be passed back into the active system or disposed of in an appropriate manner.

If a weighted fluid is being used, provisions must be made to recover the weighting material before the fluid is diverted to the injection unit. Experimentation has demonstrated that larger centrifuges (bowl length 48 inches or longer) in combination with chemical injection can remove all of the solids from a drilling fluid to produce clear water. The combination of chemical injection and larger centrifuges differentiates a dewatering system from a conventional solids control system. A dewatering system removes solids that a conventional solids control system cannot (West and Pharis, p. 88).

However, dewatering systems are expensive. They are not appropriate for every HDD application. Economics will normally dictate that dewatering systems be used on projects involving large quantities of drilling fluids. Solidification. A method for treating excess oil field drilling fluids which has been used for a

number of years is solidification (stabilization). This method involves mixing the fluid with a reagent which initiates fixation and produces a stable, solid waste. Examples of materials used as reagents are fly ash, blast furnace slag, cement-kiln dust, and clays. The reaction can produce a concrete-like solid and the waste fluid does not need to be dewatered before treatment (Hinds, et al., p.618).

Solidification should not normally be required for an HDD application. Land farming and dewatering will typically provide more cost effective disposal solutions. However, if a job is located in a zero discharge area or involves drilling through contaminated material, solidification and transportation to a disposal site may be warranted. Environmental Impact

The overwhelming majority of research done into the environmental impact of drilling fluids has been focused on fluids used in the oil field. Drilling fluids used on HDD installations are similar to oil field drilling fluids. This similarity allows research on oil field fluids to be used to assess the environmental impact of HDD fluids. However, they are not the same. HDD drilling fluids are typically much simpler than oil field drilling fluids. This distinction should be borne in mind when considering data relative to the environmental impact of drilling fluids. Oil Field Muds. The simplest type of water based fluid suitable for drilling under many conditions in the oil field is lignosulfonate mud. The basic components of a lignosulfonate

mud are barite, bentonite, caustic soda, lignite, and chrome lignosulfonate. Since 1980, the trend in the oil field has been to use polymer muds. The basic components of a polymer mud


74

are barite, partially hydrolyzed polyacrylamide polymer, xanthan gum, carboxymethyl celluloses or starches, and caustic soda (Bleier, Leuterman and Stark, p. 7).

Disposal of drilling fluids in U.S. offshore waters is regulated by the mysid shrimp test. Briefly, this test involves placing mysid shrimp in specifically prepared mixtures of drilling fluid and sea water at various concentrations. The concentration which produces a 50% mortality rate in the mysids over a period of 96 hours is referred to as the LC 50 value. The lower the LC 50 value, the higher the toxicity. Ranges are listed in Table 6-l (Littleton, p. 53).

Table 6-l LC50 Value vs. Toxicity Classification

LC50 < 100 ppm 100 ppm < LC50 < 1,000 ppm 1,000 ppm < LC 50 < 10,000 ppm 10,000 ppm < LC 50

highly toxic moderately toxic slightly toxic practically non toxic

The U.S. Environmental Protection Agency prohibits the discharge of water based mud and cuttings in the Gulf of Mexico only if the mud’s LC 50 is less than 30,000 ppm (Bleier, p. 1192). Drilling fluids that contain only the components listed for the basic lignosulfonate and polymer muds tend to test favorably in bioassays with LC50 values in the 700,000 to l,000,000 ppm range (Bleier, Leuterman and Stark, p. 7). If these muds are not contaminated by petroleum or salts in the formations drilled through, they can be discharged at sea. HDD Drilling Fluids. As previously mentioned, drilling fluids typically used in HDD installations are simpler than oil field fluids. They will generally consist only of a high yield bentonite and fresh water. Possible sources of heavy metals such as barite and chrome lignosulfonate are rarely, if ever, used. HDD fluids do not typically drill through hydrocarbon

or brine bearing formations. Therefore, their environmental impact is deemed to be on the same level with general construction sedimentation or erosion, pipeline hydrotest water disposal, or general excess construction spoil disposal. Inadvertent Returns. HDD involves the uncontrolled subsurface discharge of drilling fluids.

Drilling fluid downhole will flow in the path of least resistance. This can mean dispersal into the surrounding soils or discharge to the surface at some random location. This is not a critical problem in an undeveloped location. However, in an urban environment or high profile recreational area, inadvertent returns can be a major problem. In addition to the obvious public nuisance, drilling fluid flow can buckle streets or wash out embankments. Drilling parameters may be adjusted to maximize circulation and minimize the risk of inadvertent returns. Nonetheless, the possibility of lost circulation and inadvertent returns cannot be eliminated. Contingency plans addressing possible remedial action should be made in advance of construction and regulatory bodies should be informed. Inadvertent returns are more likely to occur in less permeable soils with existing flow paths. Examples are


75

slickensided clay or fractured rock structures. Coarse grained, permeable soils exhibit a tendency to absorb circulation losses. Manmade features, such as exploratory boreholes or piles, may also serve as conduits to the surface for drilling fluids. References James L. Lummus and J. J. Azar, Drilling Fluids Optimization, A Practical Field Approach, (Tulsa, Oklahoma; Copyright PennWell Books, 1986)

J. D. A. McKee, T. Geehan, and B. Smolen, “Efficient Solids Control Key To Incentive Drilling Performance,” Petroleum Engineer International, vol. 62, no. 4, April 1990,38-48. IADC Drilling Manual, Eleventh Edition, (Houston, Texas; International Association of

Drilling Contractors, 1992). R. D. Beasley and S. F. Dear III, “A Process Engineering Approach to Drilling Fluids Management,” SPE 19532, Proceedings of the I989 SPE Annual Technical Conference and Exhibition, October 8-11, 1989, 143-152.

Gary West and Bob Pharis, “Dewatering cuts drilling mud and disposal costs,” Oil & Gas Journal, vol. 89, no. 39, September 30, 1991, 84-88. A. A. Hinds, D. M. Donovan, J. L. Lowell, and A. Liao, “Treatment Reclamation and Disposal Options for Drilling Muds and Cuttings,” IADC/SPE 14798, Published at the IADC/SPE 1986 Drilling Conference, February 10-12, 1986. Roger Bleier, Arthur J. J. Leuterman, and Cheryl Stark, “Drilling Fluids: Making Peace With the Environment,” Journal of Petroleum Technology, vol. 45, no. 1, January 1993, 6-10.

Jeff H. Littleton, “Regulations Complicate Offshore Mud Disposal,” Petroleum Engineer International, vol. 58, no. 3, March 1986, 53-56. Roger Bleier, “Predicting Mud Toxicity,” Journal of Petroleum Technology, vol. 43, no. 10, October 1991, 1192-1193.

ROUTINE FOR CALCULATING DRILLING FLUID QUANTITIES

PROJECT: Example DATE: l/15/95

PIPE DATA Diameter: Total Drilled Length:

24 inch 2,500 feet

PILOT HOLE DRlLLlNG Drilling Mud Flow Rate: Pilot Hole Production Rate: Pumping Factor: Circulation Loss Factor: Consumed Total =

5 barrels per minute 40 feet per hour 35 minutes per hour 0.5 5,469 barrels

PREREAMING Drilling Mud Flow Rate: Prereaming Penetration Rate: Circulation Loss Factor: Number of Passes: Consumed Total =

14 barrels per minute 2 feet per minute 0.5 1

8,750 barrels

PULLING BACK Drilling Mud Flow Rate: Pull Back Penetration Rate: Circulation Loss Factor: Consumed Total =

14 barrels per minute 8 feet per minute 0.5 2,188 barrels

COMPONENT QUANTITIES Viscosifier Yield: Viscosifier Dry Weight: Drilling Fluid Consumed = Viscosifier Consumed = Water Consumed =

Drilled Spoil =

200 barrels per ton 55 pounds per cubic foot 17,406 barrels 117 cubic yards 87 tons 17,406 barrels 731,063 gallons 655 cubic yards

SECTION 7 - CONTRACTUAL CONSIDERATIONS

77

SECTION 7 CONTRACTUAL CONSIDERATIONS

Previous sections have described factors which should be considered in deciding if HDD should be employed on a crossing, in designing an HDD installation, and in obtaining permits. Once these tasks have been accomplished, a set of contract documents must be prepared which can be used to solicit bids from contractors and govern construction of the crossing. Contract documents should be structured to clearly present technical, commercial, and legal requirements. Technical and commercial considerations are addressed in this section. Legal requirements should be addressed by an attorney and fall outside the scope of this design guide.

Contract forms applied to HDD projects can be separated into two basic categories: lump sum and daywork. As used in this design guide, a lump sum contract is one in which the contractor is paid a fixed amount for delivering a drilled segment in accordance with the plans and specifications. Payment is based on performance and does not vary with the time or effort. A daywork contract is one in which the contractor is paid a fixed amount per day, or some other unit of time, for providing a spread of equipment in accordance with the contract documents. Payment is based on the passage of time regardless of progress made in the installation. Lump Sum Contracts

In most cases, drilled river crossings are contractually feasible (refer to Section 2) and should be bid using standard lump sum contract forms. Standard technical specifications and drawings should also be used where applicable. Points specific to lump sum contracts for HDD installations are discussed in the following paragraphs. A sample technical specification covering horizontal drilling activities is also presented to illustrate how HDD performance may be defined. Pricing

Bid prices may be broken down for convenience or analysis, however, compensation should generally be on a lump sum basis as opposed to a fixed unit price. For example, confusion may result on a crossing priced on a per foot basis if drilling conditions dictate a slightly longer drilled length is easier to complete than the designed drilled length. It would not be reasonable for the owner to insist that the crossing be redrilled to a shorter length to reduce payment. It is also not reasonable for a contractor to unilaterally, and for his convenience, extend the drilled length and increase his compensation. Setting a lump sum price for a crossing installed in accordance with the plans and specifications eliminates these questions.

78


It should be noted that the technical specification presented later in this section includes a pilot hole over length tolerance. Unknown Subsurface Condition Risk

A site characterization for a drilled crossing will include a definition of the subsurface which, while reasonable, will still contain a degree of uncertainty. The state of the art in engineering subsurface survey methods does not allow, within practical economic limits, the detailed definition of every area of a broad subsurface space. In installation of a pipeline by HDD, there is a risk of operational problems occurring due to this uncertainty. This risk is assumed by the contractor in a standard lump sum contract. It is incumbent upon the contractor to calculate his bid with the appropriate contingency cost included to offset this risk. In order to do this with some success, he must have the results of the site characterization described in Section 3. He should be able to base his bid on all of the information gathered by the owner or his engineer. Under these circumstances, a contractor should not be entitled to extra compensation on the basis of changed conditions unless there is an extreme deviation from the conditions indicated by the site characterization (i.e., bedrock where only alluvial deposits were encountered). With a properly conducted subsurface survey, this is a remote possibility. On the other hand, changes such as encountering gravel where borings indicated coarse sand is not a changed condition. The presence of gravel in a formation containing coarse sand is not unforeseen. A more significant example would be encountering cobbles or boulders in a strata described by general geologic data as glacial in nature. Although site specific borings may not have penetrated a boulder, random cobbles and boulders can be a characteristic of glacially deposited soils. A competently executed subsurface survey program may serve as the benchmark from which to judge whether conditions are materially different from those indicated in the contract. It is important to remember that, unlike an open excavation, the conditions along a drilled path will never be visible. It will not be possible to look at, touch, or feel the soil encountered. Technical Specification

A sample technical specification defining HDD performance is presented in Figure 7 - 1. This specification is designed to fit within a set of standard technical specifications. Job specific conditions such as pilot hole tolerances, drilling water sources, drilling fluid disposal specifications, and drilling fluid disposal sites are spelled out in an accompanying General Requirements section. Plan & Profile Drawing

In addition to the HDD technical specification, the contract documents should contain a plan & profile drawing. The drawing should complement the technical specification by providing a clear presentation of the crossing design as well as the results of topographic, hydrographic,


79

and geotechnical surveys. This drawing will be used by the contractor to produce a working profile, upon which he must rely for downhole navigation; therefore, accurate measurements are essential. A sample plan & profile drawing for an HDD installation is presented in Figure 7-2. Figure 7-1 Sample Performance Specification for HDD

HORIZONTAL DIRECTIONAL DRILLING SCOPE This Specification covers the installation of pipe or conduit by horizontal directional drilling. Horizontal

directional drilling is a trenchless excavation method which is accomplished in two phases. The first phase consists of drilling a small diameter pilot hole along a designed directional path. The second phase consists of enlarging the pilot hole to a diameter suitable for installation of the pipe or conduit, and pulling the pipe or conduit into the enlarged hole. Horizontal directional drilling is accomplished using a specialized horizontal drilling rig with ancillary tools and equipment. PROTECTION OF UNDERGROUND FACILITIES CONTRACTOR shall undertake the following steps prior to commencing drilling operations in a location

which might contain underground facilities. 1.

Contact the utility location/notification service, if available, for the construction area.

2.

Positively locate and stake all existing lines, cables, or other underground facilities including exposing any facilities which are located within 10 feet of the designed drilled path.

3.

Modify drilling practices and downhole assemblies to prevent damage to existing facilities.

CONTRACTOR shall be responsible for locating any and all underground facilities regardless of COMPANY'S previous efforts in this regard. CONTRACTOR shall be responsible for all tosses and repairs occasioned by damage to underground facilities resulting from drilling operations.

INSTRUMENTATION CONTRACTOR shall at all times provide and maintain instrumentation which will accurately locate the pilot hole, measure drill string axial and torsional loads, and measure drilling fluid discharge rate and pressure.

COMPANY will have access to these instruments and their readings at all times. SUBMITTALS All procedure or material descriptions requiring COMPANY approval shall be submitted not less than 3 weeks prior to commencing any horizontal directional drilling activities at the crossing location. PILOT HOLE Directional Tolerance

The pilot hole shall be drilled along the path shown on the plan & profile drawing to the tolerances listed in the General Requirements. However, in all cases, right-of-way restrictions shall take precedence over the listed tolerances. Regardless of the tolerance achieved, no pilot hole will be accepted if it will result in any or all of the pipeline being installed in violation of right-of-way restrictions. In all cases, concern for adjacent utilities


80

and/or structures shall take precedence over the listed tolerances. Listing of tolerances does not relieve CONTRACTOR from responsibility for safe operations or damage to adjacent utilities and structures. Curve Radius

Curves shall be drilled at a radius equal to or greater than that shown on the plan & profile drawing. The drilled radius will be calculated over any three joint (range 2 drill pipe) segment using the following formula:

Where:

Rdrilled L drilled Aavg

= = =

drilled radius over L drilled

length drilled, no less than 75 feet and no greater than 100 feet total change in angle over L drilled

As-Built Survey

At the completion of pilot hole drilling, CONTRACTOR shall provide a tabulation of coordinates, referenced to the drilled entry point, which accurately describe the location of the pilot hole. REAM & PULL BACK Hydrostatic Pretest

The entire pull section shall be subjected to a four hour hydrostatic test prior to being installed In the hole. The test pressure shall be equal to or exceed that required for final certification. The hydrostatic pretest shall be conducted and documented in accordance with the applicable Specification. Prereaming Prereaming operations shall be conducted at the discretion of CONTRACTOR. All provisions of this

Specification relating to simultaneous reaming and pulling back operations shall also pertain to prereaming operations. Pulling Loads

The maximum allowable tensile load imposed on the pull section shall be equal to 90% of the product of the specified minimum yield strength of the pipe and the area of the pipe section. If more than one value is

involved for a given pull section, the lesser shall govern. Torsional Stress

A swivel shall be used to connect the pull section to the reaming assembly to minimize torsional stress

imposed on the section. Pull Section Support

The pull section shall be supported as it proceeds during pull back so that it moves freely and the pipe and corrosion coating are not damaged. External Collapse Pressure

The pull section shall be installed in the reamed hole in such a manner that external pressures are minimized. Any damage to the pipe resulting from external pressure during installation shall be the responsibility of

CONTRACTOR. Buoyancy Modification Buoyancy modification shall be used at the discretion of CONTRACTOR. Any buoyancy modification

procedure proposed for use shall be submitted to COMPANY for approval, No procedure shall be used which has not been approved by COMPANY. CONTRACTOR is responsible for any damage to the pull section resulting from buoyancy modification.


81

Corrosion Coating Inspection

If the pull section is corrosion coated, it shall be inspected for holidays with a holiday detector as it enters the hole. Any coating damage found shall be repaired. Inspection and repair of corrosion coating shall be

conducted in accordance with the applicable Specification. DRILLING FLUIDS Composition

The composition of all drilling fluids proposed for use shall be submitted to COMPANY for approval. No fluid will be approved or utilized that does not comply with permit requirements and environmental regulations. Water CONTRACTOR is responsible for obtaining, transporting, and storing any water required for drilling fluids. COMPANY, at its option, may secure a water source for CONTRACTOR. Water sources secured by

COMPANY are listed in the General Requirements. Recirculation

CONTRACTOR shall maximize recirculation of drilling fluid surface returns. CONTRACTOR shall provide solids control and fluid cleaning equipment of a configuration and capacity that can process surface returns and produce drilling fluid suitable for reuse. COMPANY may specify standards for solids control and cleaning equipment performance or for treatment of excess drilling fluid and drilled spoil. COMPANY specified standards, if any, are listed in the General Requirements. Disposal

Disposal of excess drilling fluids is the responsibility of CONTRACTOR and shall be conducted in compliance with all environmental regulations, right-of-way and workspace agreements, and permit requirements. Drilling fluid disposal procedures proposed for use shall be submitted to COMPANY for

approval. No procedure may be used which has not been approved by COMPANY. COMPANY, at its option, may secure an excess drilling fluid disposal site for CONTRACTOR. Excess drilling fluid disposal sites

secured by COMPANY are listed in the General Requirements. Inadvertent Returns

CONTRACTOR shall employ his best efforts to maintain full annular circulation of drilling fluids. Drilling fluid returns at locations other than the entry and exit points shall be minimized.

In the event that annular

circulation is lost, CONTRACTOR shall take steps to restore circulation. If inadvertent surface returns of drilling fluids occur, they shall be immediately contained with hand placed barriers (i.e. hay bales, sands bags, silt fences, etc.) and collected using pumps as practical. If the amount of the surface return is not great

enough to allow practical collection, the affected area shall be diluted with fresh water and the fluid will be allowed to dry and dissipate naturally. If the amount of the surface return exceeds that which can be contained with hand placed barriers, small collection sumps (less than 5 cubic yards) may be used. If the

amount of the surface return exceeds that which can be contained and collected using small sumps, drilling operations shall be suspended until surface return volumes can be brought under control.

Figure 7-2

Sample Plan & Profile Drawing


83

Daywork Contract

Because of the evolving nature of HDD technology, the industry has employed many contract form variations. Typically, these variations involve negotiating some type of completion incentive into a daywork contract. Significant advances have been made because of owner willingness to assume the risk of cost overruns or completion failure for prospective installations which were not contractually feasible. However, a daywork contract requires much greater oversight by the owner than a typical lump sum contract. Serious misunderstandings are possible when a standard lump sum contract form is used for a daywork contract applied to a state of the art drilled river crossing. A sample daywork contract form entitled Drilling Bid Proposal and Daywork Drilling Contract - U.S. has been produced by the International Association of Drilling Contractors. Although this form is designed for use in drilling an oil well and is not directly applicable to pipeline installation, it does serve to illustrate the differences in lump sum and day work contracts. Review of this form is recommended in preparing a daywork contract for an HDD installation. Uniform Daywork Bid Sheet

Although a daywork contract may not specify contractor performance in terms of a completed installation, contractor performance is required and should be clearly defined. The required performance primarily involves the provision of equipment of a certain capacity. The components of equipment should be listed as well as conditions with respect to downtime, maintenance, crewing, fueling, etc. Additionally, items in the scope of work which can be contracted on a lump sum basis, such as mobilization and site preparation, should be broken out, priced lump sum, and governed by an appropriate performance specification. Sample bidding forms for use with a daywork contract are presented in Figures 7-3 and 7-4. Equipment Failure Risk

An often overlooked but crucial element of a daywork contract is the assumption of equipment failure risk. For example, a downhole survey system may fail requiring the bottom hole assembly to be tripped out and the survey probe replaced. Is the contractor entitled to compensation for operating time involved with the round trip or is this considered equipment maintenance? A more significant example involves failure of drill pipe downhole during pull back. The pipe may be at, or near, capacity. Adverse soil conditions may be encountered. The actual cause of the failure may be difficult to ascertain even if the failed components can be recovered. This concern applies to surface equipment as well. A drilling rig breakdown during pull back may result in stuck pipe and an abandoned hole. Responsibility for the failure of equipment should be clearly defined in the contract before operations commence and the owner must exert some control over the equipment and drilling procedures employed.


84

Figure 7-3

Sample Uniform Daywork Bid Sheet

UNIFORM DAYWORK BID SHEET CONTRACTOR proposes to furnish the equipment (fueled, lubricated and maintained), materials and

services described on Exhibit “A” for the following rates. 1.0

Mobilization and Rig-up to include all costs involved with transporting CONTRACTOR’S equipment, materials and labor to the jobsite and assembling it complete and ready for operation. $

2.0

Lump Sum

Pilot Hole Directional Drilling Operations to include items 1.1, 1.2, 1.3, 1.4, 1.5, and 1.7 on Exhibit “A”. Costs are to be based on a single 10 hour shift operating 7 days per week. Payment will be made based on actual hours working or on ready standby. downtime or maintenance.

No payment will be made for equipment

2.1

$

per operating hour

2.2

$

per standby hour

Pilot Hole Directional Drilling Operations conducted in excess of 10 hours per day. 2.3

$

per operating hour

3.0

Reaming and Pull Back Operations to include items 1.1, 1.2, 1.3, 1.5 and 1.7 on Exhibit “A”. Costs are to be based on a single 10 hour shift operating 7 days per week. Payment will be made based on actual hours working or on ready standby. No payment will be made for equipment downtime or maintenance.

3.1

$

per operating hour

3.2

$

per standby hour

Reaming and Pull Back Operations conducted in excess of IO hours per day. 3.3

$

per operating hour

4.0

Drilling Mud (not including fresh water) quoted in delivered units. $

5.0

Rig-down and Demobilization to include all costs involved with disassembling and removing

Contractor’s equipment, materials and labor from the jobsite. $

Lump Sum


85

Figure 7-4

Sample Exhibit “A” for use with Uniform Daywork Bid Sheet

EXHIBIT “A” To Daywork Bid dated CONTRACTOR 1.0

EQUIPMENT, MATERIALS AND SERVICES TO BE FURNISHED BY CONTRACTOR:

The machinery, equipment, tools, materials, supplies, instruments, services and labor listed below, including fuel, lubricants and maintenance, shall be provided at the expense of CONTRACTOR unless otherwise noted. 1.1

Horizontal Drilling Rig:

Complete horizontal drilling rig, designated by CONTRACTOR as Rig No. the major components being the ramp, carnage, turntable, vise system, power system and control system. Rig

performance parameters are listed below: Max. Tensile Capacity Max. Thrust Capacity Torsional Capacity Max. Travel Speed Max. Rotating Speed

pounds @ pounds @ foot-pounds @ feet per minute revolutions per minute

feet per minute feet per minute revolutions per minute

Engines: Make, Model, and H.P.

1.2

Drilling Mud System:

Complete drilling mud system consisting of water/mud intake system, mud tank with mixing system, mud

pumps and solids control system. Performance parameters are listed below: Mud Tank Capacity

Mud Pumps: Make, Model, Capacity

Engines: Make, Model, and H.P.

1. 3

Drill Pipe:

Specification and Quantity

1.4

Down Hole Survey System:

General Description

1. 5

Down Hole Drilling Tools:

General Description

bbls. bbls. bbls. bbls.


86

1.6

Drilling Mud (not including fresh water):

General Description

1.7

Labor:

Skilled labor required to operate the drilling rig and associated equipment provided by Contractor on single shift, ten (10) hour basis is listed below: Description

2.0

Number

EQUIPMENT, MATERIALS AND SERVICES TO BE FURNISHED BY OPERATOR:

The machinery, equipment, tools, materials, supplies, instruments, services and labor listed below, including any transportation required, shall be provided at the expense of the Company unless otherwise noted. 2. 1

Access to Rig site

2.2

Rig site Cleared and Graded

2.3

Fresh Water at Rig site

2.4

Transportation and disposal of excess drilling mud.

2.5

Fabricated and tested pipeline pull section ready for installation.

2.6

Equipment required to handle pipeline pull section prior to and during installation.

3.

OTHER PROVISIONS

SECTION 8 - CONSTRUCTION MONITORING

87

SECTION 8 CONSTRUCTION MONITORING

Preceding sections have presented engineering design considerations from initial feasibility assessment to production of final contract documents. This section describes construction monitoring requirements relative to specialized HDD operations. The primary objectives of an inspector involved in construction monitoring on an HDD installation are to assist in the interpretation of the contract documents and document conformance by the drilling contractor. In doing this, it is important for the inspector to document his observations and actions. Should a question or dispute arise after the installation is complete, the inspector’s notes will provide the only source of confirming data. Since a drilled installation is typically buried with deep cover under an inaccessible obstruction, its installed condition cannot be confirmed by visual examination. HDD construction monitoring effort is focused on two major areas: the drilled path and drilling fluid flow. Drilled Path Construction Staking

The drilling contractor will typically rely on the owner’s staking to locate the drilled segment. Two locations, the entry and exit points, should be staked. The elevations of the staked locations as well as the distance between them should be checked against the values on which the design is based. The contractor’s pilot hole accuracy is directly dependent on the accuracy of the relative location, both horizontally and vertically, of these two points. The exit point coordinates will also provide a benchmark for measuring downhole survey error. If possible, the contractor should have a clear line of sight between the entry and exit points for use in orienting the downhole survey instrument. If a clear line of sight is not possible, the owner should stake points so that the drilled path centerline, or reference line, can be established for survey instrument orientation. Pilot Hole

Monitoring of the drilled path is accomplished during pilot hole drilling. Initially, a reading of the magnetic heading is taken by the contractor to establish a reference line on which all drilled path data and calculations will be based. Other pertinent data which is needed to accurately locate the pilot hole drilling bit includes the bottom hole assembly length, the length from the drilling bit to the downhole probe, and the drilling rig setback distance from the entry point.


88

The actual path of the pilot hole is monitored during drilling by taking periodic readings of the inclination and azimuth of the downhole probe. Readings are typically taken after drilling a single joint, or approximately every 30 feet. These readings are used to calculate the horizontal and vertical coordinates of the downhole probe as it progresses along the pilot hole. Data and calculations from the readings typically include the following items: l

Survey. A point at which readings are taken by the downhole probe; surveys are usually

tracked in a numerical sequence (1,2,3,...) corresponding to the number of joints drilled. l

Course Length.

the distance between two downhole surveys as measured along the

drilled path. l

Measured Distance. The total distance of a downhole survey from the entry point as

measured along the drilled path; also the summation of the course lengths. l

Inclination. The angle at which the downhole probe is projecting from the vertical axis

at a particular downhole survey point; vertically downward corresponds to zero degrees. l

Azimuth. The angle at which the downhole probe is projecting in the horizontal plane at

a particular downhole survey point; magnetic north corresponds to zero degrees. l

Station. The horizontal position of a downhole survey measured from an established

horizontal control system. l

l

The vertical position of a downhole survey measured from an established vertical control system.

Elevation.

Right. The distance of a downhole survey from the design path reference line; positive

values indicate right of the reference line while negative values indicate left of the reference line. Additional data which should be recorded are listed below: l

l

l

Bit to Probe. The distance from the drilling bit (leading edge) to the downhole probe. Heading. The magnetic line azimuth to which the drilled path reference line corresponds.

Rig Setback. The distance from the drill bit when first placed on the drilling rig as

measured from the staked entry point. l

l

BHA Length. The length of the Bottom-Hole Assembly. TruTracker® Data. Coordinates measured by the TruTracker® surface monitoring

system (discussed in the following subsections).

Figure 8-1 General Observations and Progress

J . D . H A I R & A S S O C I AT E S D A I L Y P R O G R E S S R E P O R T

Figure 8-2

Survey Tabulation Sheet

J . D . H A I R & A S S O C I AT E S D A I L Y P R O G R E S S R E P O R T I

PROJECT:

NOTES:

RAW DATA

SURVEY

B.H.A.

RIG SETBACK:

BIT T0 PROBE:

JOINT

CALCULATIONS

DATA AZIMUTH

RIGHT

ELEVATION

MEASURED

S TATI ON

RIGH T

ELEVATION

Figure 8-3

Radius of Curvature Analysis

J . D . H A I R & AS S O C I A T E S D A I L Y P R O G R E S S R E P O R T

DATE:

PROJ ECT:


92

Sample daily progress reports presenting field recorded and analyzed data are shown in Figures 8-1, 8-2, and 8-3. Figure 8-l records general observations and progress. Figure 8-2 is a survey tabulation sheet for recording joint by joint survey readings and calculations. Figure 8-3 records joint by joint radius of curvature calculations made over various drilled segment lengths. Directional Drilling Performance

The inspector should be concerned with directional drilling performance in two basic areas; position and curvature. First, the contractor must install the pipeline so that the drilled length, depth of cover, and entry/exit angles specified by the contract are provided. Second, the contractor must not curve the drilled path in such a way that the pipeline will be damaged during installation or over stressed during operation. The actual position of the drilled path cannot be readily confirmed by an independent survey. Therefore, it is necessary for the inspector to have a basic understanding of the downhole survey system being used by the contractor and be able to interpret its readings. It is not necessary for the inspector to observe and approve the drilling of each joint. However, progress should be monitored on a daily basis and problems addressed so that remedial action can be taken as soon as possible. The inspector should insure that bends are not drilled which have a radius of curvature less than the minimum allowable. If a tight radius occurs, the joint or joints should be redrilled or reviewed with the design engineers as soon as possible to insure that the codes and specifications governing design of the pipeline are not violated. Downhole Survey Calculations

Downhole survey calculation methods are discussed in detail in API Bulletin D20 entitled Directional Drilling Survey Calculation Methods and Terminology. Three different methods from this bulletin are presented here for use on HDD pipeline installations. These are: Average Angle, Minimum Curvature, and Balanced Tangential. The equations for these three methods are used to calculate the horizontal and vertical distances from the entry point, as well as the distance from the reference line. Symbols used in the equations are illustrated in Figure 8-4 and defined as follows: CL

=

Course Length.

I1

=

Inclination angle of the previous survey point.

I2

=

Inclination angle of the current survey point.

A1

=

Deflection angle from the heading of the previous survey point.

A2

=

Deflection angle from the heading of the current survey point.

HD

=

Horizontal Distance between the previous and current survey points.

93


RT

=

Differential distance from the reference line between the previous and current survey points. Also called “RIGHT” to indicate the distance right (positive values) or left (negative values) of the original reference line.

VT

=

Vertical Distance between the previous and current survey points. Figure 8-4

3-Dimensional View of Current and Previous Survey Points

This method uses the average of the previous and current azimuth/inclination angles to project the measured distance along a path which is tangent to this average angle. The equations are as follows:

Average Angle Method.

HD = CL x cos [(A 1 + A2)/2] x sin [(I1 + I 2)/2]

(8.l)

RT = CL x sin [(A l + A2)/2] x sin [(I1 + I2)/2]

(8.2)

VT = CL x cos [(I 1 + I 2)/2]

(8.3)

Balanced Tangential Method. This method assumes that half of the measured distance is

tangent to the current inclination/azimuth projections and that the other half is tangent to the previous inclination/azimuth projections.

HD = (CL/2) x (sin I1 x cos A1 + sin I2 x cos A2)

(8.4)

RT = (CL/2) x (sin I1 x sin A1 + sin I2 x sin A2)

(8.5)

VT = (CL/2) x (cos I1 + cos I2)

(8.6)

Minimum Curvature Method. This method is similar to the Balanced Tangential Method;

however, the tangential segments produced from the previous and current azimuth/inclination


94

angles are smoothed into a curve using a ratio factor (RF). This ratio factor is defined by a dogleg angle (DL) which is a measure of the change in inclination/azimuth. -1

DL = cos {cos(I2 - I1 - sin I1 x sin I2 x [ 1 - cos (A 2 - A1)]}

(8.7)

RF = (2/DL) x tan (DL/2) ; RF = 1 for small angles (DL < 0.25°)

(8.8)

HD = (CL/2) x (sin I1 x cos Al + sin I2 x cos A2) x RF

(8.9)

RT = (CL/2) x (sin I1 x sin A1 + sin I2 x sin A2) x RF

(8.10)

VT = (CL/2) x (cos I 1 + cos I2) x RF

(8.11)

Any one of these three methods may be used to track the downhole probe position and ensure conformance to the directional tolerances of the design. To track the probe over a specified measured distance the values from these equations must be summed over the specified length. Radius of Curvature Calculations

The same angle readings used in the previous calculations are also used to determine the radius of curvature of the drilled path. The radius of curvature calculations are based on the relationship:

R=s/Q

(8.15)

where,

S

=

arc length in feet

Q

=

angular distance in radians

For a specific drilled length, the radius of curvature is calculated using the following formula: Rdrilled = (1drilled / qdrilled) x (180 /

(8.16)

where, Rdrilled =

the radius of curvature over a specified drilled length in feet

1drilled =

drilled length in feet

qdrilled =

change in angle over the drilled length in degrees

Typically, the radius of curvature is checked for conformance over any three joint (range 2 drill pipe) course length using the following equation:


95

R3 = (L3 /Q3) x =

(L3 / Q3) x 57.32

(8.17)

where, R3

=

the radius of curvature in feet over L3

L3

=

course length in feet over any 3 joints, no less than 75 feet and no greater than 100 feet

Q3

=

total change in angle in degrees over L 3

TruTracker® Surface Monitoring System

A surface monitoring system may be utilized to determine the location of the downhole probe during pilot hole drilling. TruTracker® is one such system. This system locates the downhole probe by inducing a magnetic field in a surface coil of known location. The probe senses its location relative to this magnetic field and communicates this information to the surface. Prior to drilling, the coil will be laid out on the ground surface and its corners accurately surveyed. When monitoring the coil layout, the following should be considered: 1.

A coil of width W can locate the downhole probe within a width of 3W at a depth of W.

2. A coil can have up to 32 corners.

3. The coil does not need to be perfectly centered over the proposed alignment. 4. The coil does not need to be rectangular.

5. The wire must be straight, both horizontally and vertically, from corner to comer.

TruTracker® data will generally be more accurate than the values calculated using inclination and azimuth readings. When monitoring the data provided by the TruTracker®, the following should be considered to insure accurate readings: 1. Radial Intensity should be between 1000 - 5000 gammas.

2. Radial Angle should be 270 ± 90 degrees.

3. Radial Angle Mismatch should be fractionally close to 0. 4. Radial Intensity Mismatch should be fractionally close to 0.

5. Axial Intensity Mismatch should be less than 10%.

96


Where the coil cannot be set directly on the obstacle being crossed, as with a major river, calculated values must be used. However, TruTracker® data from coils on each bank can be used to correct the magnetic line azimuth. This aids in providing more accurate calculated alignment values and enables the contractor to guide the probe with greater accuracy. Asbuilt Error Distribution

All of the downhole survey instruments used to track the pilot hole contain error. This error is indicated by comparing the actual exit point location with the anticipated exit point location. The owner’s inspector should make an independent comparison of these two points. If the topographical survey is accurate and the downhole survey calculations are correct, then the observed difference in the two points results from inaccuracies in the downhole tool itself. This error should be distributed over the drilled path to yield an “asbuilt” profile to be compared against the contract requirements. Pipe Installation Pull Section Handling

The inspector should review the contractor’s operations to insure that the pull section is adequately supported during pull back. Roller stands should be provided as well as lifting equipment capable of moving the string into the drilled hole. The section should not be dragged on the ground. All break over bends should be made with a radius long enough to insure that the pipe is not over stressed. Buoyancy Control

Buoyancy control may be utilized during pull back to lessen the required pulling loads. Prior to pipe installation, the inspector should review the buoyancy control plan with the owner’s design engineers. The inspector’s main goal is to insure that a suitable internal pressure is maintained in the pull section. The inspector should also insure that the contractor keeps accurate records of the pipe length installed and the amount of water injected. Coating Integrity

The coating should be inspected with a holiday detector immediately prior to entering the reamed hole. Additionally, field joints should be closely examined. Damage to yard-applied pipe coating imposed by drilled installation in most soils will be negligible if the hole has been properly drilled and reamed. However, loosely bonded field-coated joints may be subject to peeling off during pull back. Drilling Fluid Flow

The inspector should always bear in mind the possibility of inadvertent drilling fluid returns. The right of way should be examined regularly for inadvertent returns. Particular attention should be paid to locations of underground utilities (mud may migrate along a perpendicular


97

pipeline) and pile foundations. If inadvertent returns are found, they should be contained and cleaned up immediately and their locations monitored for continuing problems (particularly during pull back). If problems persist, engineering assistance should be called upon to review the contractor’s drilling program and institute preventative measures. References

API Bulletin D20, Directional Drilling Survey Calculation Methods and Terminology, First Edition, (Dallas, Texas; American Petroleum Institute, 1985)

Operating Instructions, Tensor Steering Tool System, Version 2.4, (Austin, Texas; Tensor, Inc., Undated)


BIBLIOGRAPHY

API Bulletin D11. December, 1965. First Edition. 1985. Directional Drilling Survey Calculation Methods and API Bulletin D20. Terminology, First Edition, (Dallas, Texas; American Petroleum Institute

API Recommended Practice 2A-WSD. July 1, 1993. Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms -- Working Stress Design.

12th

Edition. Dallas, Texas. American Petroleum Institute. ASME/ANSI B31.4-1986 Edition with 1987 Addenda. 1987. Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum Gas, Anhydrous Ammonia, and Alcohols.

New York, New York. The American Society of Mechanical Engineers. 1993. Classtfication of Soils for Engineering Purposes (Unified Soil Classification System). Philadelphia, Pennsylvania. American Society for Testing and Materials.

ASTM Standard D 2487 - 93.

Beasley, R. D. and S. F. Dear, III. 1989. “A Process Engineering Approach to Drilling Fluids Management”. SPE 19532, Proceedings of the 1989 SPE Annual Technical Conference and Exhibition.

Bleier, Roger, et al. 1993. “Drilling Fluids:

Making Peace With the Environment”.

Journal of Petroleum Technology.

Bleier, Roger. 1991. “Predicting Mud Toxicity”. Journal of Petroleum Technology Drilling Fluids in Pipeline Installation by Horizontal Directional Drilling. October 1994.

Prepared for the Offshore and Onshore Design Applications Supervisory Committee of the Pipeline Research Committee at the American Gas Association. Drilling Mud 1984. Unit II, Lesson 2. Third Edition. Rotary Drilling Series. Austin,

Texas. Petroleum Extension Service, University of Texas at Austin.

Fowler, J.R. and C.G. Langner. May 1991. “Performance Limits for Deepwater Pipelines”. OTC 6757, 23rd Annual Offshore Technology Conference. Hinds, A. A., et al. 1986. Treatment Reclamation and Disposal Options for Drilling Muds and Cuttings. IADC/SPE 14798, published at IADC/SPC 1986 Drilling Conference.

IADC Drilling Manual.

1992.

Eleventh Edition. Houston, Texas. International

Association of Drilling Contractors. Littleton, Jeff H. 1986. “Regulations Complicate Offshore Mud Disposal”. Petroleum Engineer International.

Loh, J.T. May 1990. “A Unified Design Procedure for Tubular Members”. 22nd Annual Offshore Technology Conference.

OTC 6310,

Lummus, J. L. and J. J. Azar. 1986. Drilling Fluids Optimization, A Practical Field Approach. Tulsa, Oklahoma. PennWell Publishing Company.

Maidla, E.E. December 1987. Baton Rouge, Louisiana. “Borehole Friction Assessment and Application to Oilfield Casing Design in Directional Wells”. Doctoral Dissertation, Department of Petroleum Engineering, Louisiana State University. McKee, J. D. A., T. Geehan and B. Smolen. 1990. Efficient Solids Control Key To Incentive Drilling Performance. Petroleum Engineer International.

Meijers, P. March 1993. “Review of a Calculation Method for Earth Pressure on Pipelines Installed by Directional Drilling”. Delft Geotechnics, Report CO-341850/4 commissioned by N.V. Netherlands Gasunie. Microtunneling & Horizontal Directional Drilling. November 1990. Proceedings of the

First Trenchless Excavation Center (TEC) Symposium.

NEN 3650. 1992. “Requirements for Steel Pipeline Transportation Systems”. Unofficial translation, Government/Industry Standards Committee 343 20, The Netherlands. NEN 3651. February 1994. “Supplementary Requirements for Steel Pipelines Crossing Unofficial Major Public Works (Dykes, High Level Canals, Waterways, Roads)“. translation, Government/Industry Standards Committee 343 20, The Netherlands.

Operating Instructions, Tensor Steering Tool System, Version 2.4. Austin, Texas. Tensor, Inc.

Roark, R.J. Formulas for Stress and Strain. Second Edition, 1943, & Fifth Edition, 1965. New York. McGraw-Hill. Rotary Drilling, Controlled Directional Drilling. Unit III, Lesson 1. Courtesy, Petroleum

Extension Service (PETEX), The University of Texas at Austin.

Spangler, M. G. and R. L. Handy. 1973. Soil Engineering. Third Edition. New York, New York. Intext Press, Inc. Timoshenko, S. P. and James M.,Gere. 1972. Mechanics of Materials. New York, New York; Van Nostrand Reinhold Company

West, Gary and Bob Pharis. 1991. “Dewatering cuts drilling mud and disposal costs”. Oil & Gas Journal.


METRIC “SI” UNIT CONVERSION TABLE

PROPERTY

TRADITIONAL UNIT

RECOMMENDED SI UNIT

SYMBOL

CONV. FACTOR

Multiply By:

Length Hole Diameter Pipe Diameter Bit Size Nozzle Size Nozzle Velocity Drilling Rate Volume Liner Size Rod Diameter Stroke Length Pump Output Pump Pressure Annular Velocity Slip Velocity Temperature Mud Weight Pressure Gradient Shear Stress Shear Rate Viscosity

feet inch inch inch l/32 inch feet/sec feet/hour barrels inch inch inch barrel/minute gallon/minute pound/sq inch feet/min feet/min degree Fahrenheit pounds/gallon psi/ft 2 lb/100 ft reciprocal second centipoise

meter millimeter millimeter millimeter millimeter meter/sec meter/hour cubic meter millimeter millimeter millimeter cubic meter/min cubic meter/min kilopascal meter/minute meter/minute Celsius kilogram/cubic meter kilopascal pascal reciprocal second centipoise

m mm mm mm mm m/s m/h 3 m mm mm mm 3 m3 /min m /min kPa m/min m/min °C 3 kg/m kPa Pa- 1 s cP

0.3048 25.4 25.4 25.4 0.79 0.3048 0.3048 0.159 25.4 25.4 25.4 0.159 0.00378 6.9 0.3048 0.3048 (°F-32)/1.8 120 6.9 0.48 1.0

PROPERTY

TRADITIONAL UNIT

RECOMMENDED SI UNIT

CONV. FACTOR

SYMBOL

Multiply By:

Yield Point Gel Strength Power Law Constants n K

2

lb/100 ft2 lb/100 ft

dimensionless n 2

dynes·s cm n

lb·s /100 ft

Additive Concentration Corrosion Rate

Pa Pa

pascal pascal

2

pound/barrel 2 lb/ft /yr mils/year

Bentonite Yield Hydraulic HP Screen Size Mesh Aperature Open Area

barrels/US ton horsepower

Weight of Drill Pipe

pound/foot

openings/inch micron

area percent

n

millipascal seconds / square centimeter n millipascal seconds / square centimeter kilogram/cubic meter kilogram/square meter/ year millimeter/year cubic meter/metric tonne kilowatt openings/centimeter micrometer square meter/square meter kilogram/meter

0.48 0.48 n

2

mPa·s /cm n

2

mPa·s /cm 3

100

479

kg/m2 kg/m /yr

2.85 49

mm/a 3 m /t kw

0.0254

0.175 0.746

openings/cm µm 2 2 m /m

0.254 0.01

kg/m

1.49

1

Reference

API Specification 13A, Specification for Drilling Fluid Materials, Fifteenth Edition, (Dallas, Texas; American Petroleum Institute, 1993)

GLOSSARY

i

GLOSSARY A

annulus: a structure or space resembling a ring. In drilling, the annulus refers to the space which surrounds the drill pipe and is enclosed by the borehole wall. API: American Petroleum Institute located in Dallas, Texas. ASTM: American Society for Testing and Materials located in Philadelphia, Pennsylvania. attapulgite: a fibrous clay mineral that is a viscosity-building substance, used principally in

saltwater drilling muds. horizontal direction expressed as an angle measured clockwise from any meridian. In drilling, azimuths are typically measured from magnetic north. azimuth:

B barite: natural barium sulfate used for increasing the density of drilling fluids.

barrel reamer: an enclosed cylindrical soft soil reaming tool with cutting teeth and fluid nozzles arrayed on the end faces. Barrel reamers may be designed with specific buoyancies to aid in hole enlargement. bedding plane: any of the division planes that separate the individual strata or depositional

layers in sedimentary or stratified rock. bent sub: a short threaded piece of pipe manufactured with an axial offset or angle. In

directional drilling, a bent sub is used to produce a leading edge asymmetry in a non rotating directional drill string. bentonite: a colloidal clay, composed primarily of montmorillonite, that swells when wet.

Because of its gel-forming properties, bentonite is a major component of drilling muds. bentonite extenders: a group of polymers that can maintain or increase the viscosity of

bentonite while flocculating other clay solids in the mud. With bentonite extenders, desired viscosity can often be maintained using only half the amount of bentonite that would otherwise be required. bottom hole assembly (BHA): the combination of bit, downhole motor, subs, survey

probe, and non magnetic collars assembled at the leading edge of a drill string.

boulder: a particle of rock that will not pass through a 12” (300 mm) square opening,

breakover: the over bend required to change the vertical orientation of a cross country pipeline without inducing plastic deformation or unacceptable flexural stresses in the pipe. bullet nose: an enclosed cylindrical soft soil reaming tool similar to a barrel reamer but

with minimal cutting teeth and fluid nozzles. A bullet nose functions more as a centralizer, expander, and fluid discharge point than a cutting tool and is typically used during pull back. buoyancy control: the act of modifying the unit weight of a cross country pipeline to

achieve a desired buoyancy. In HDD installation, this may be accomplished by placing water in the pipe during pull back. C carboxymethyl cellulose (CMC): a nonfermenting cellulose product used in drilling fluids

to lower the water loss of the mud and produce viscosity. carriage: the component of a horizontal drilling rig which travels along the frame and rotates the drill pipe. It is analogous to a top drive swivel on a vertical drilling rig. centrifuge: a device used for the mechanical separation of solids from a drilling fluid. A centrifuge uses high speed mechanical rotation to impart a centrifugal force to the fluid and achieve separation. Centrifuges and hydrocyclones (desanders, desilters) operate on the

same basic principle. However, centrifuges are distinguished from hydrocyclones by their use of mechanical energy. clay: soil made up of particles passing a No. 200 (75 µm) U.S. standard sieve that can be made to exhibit plasticity (putty-like properties) within a range of water contents. Clay exhibits considerable strength when air dry. cobble: a particle of rock that will pass through a 12” (300 mm) square opening and be

retained on a 3” (75 mm) U.S. standard sieve. colloid: a substance whose particles are so fine that they will not settle out of suspension or

solution and cannot be seen under an ordinary microscope. D density: the mass or weight of a substance per unit volume. For instance, the density of a 3

drilling mud may be 10 pounds per gallon (ppg), 74.8 pounds per cubic foot (lb/ft ), or 3 1198.3 kilograms per cubic meter (kg/m ). a centrifugal device (hydrocyclone) for removing sand from drilling fluid. Desanders are hydrocyclones larger than 5 inches in diameter. desander:

desilter: a centrifugal device (hydrocyclone) for removing very fine particles, or silt, from

drilling fluid. Desilters are hydrocyclones typically 4 or 5 inches in diameter. diamond bit: a drilling bit that has a steel body surfaced with industrial diamonds, i.e. Polycrystalline Diamond Compact (PDC) bit. downhole motor: a device which uses hydraulic energy contained in a drilling fluid flow stream to achieve mechanical bit rotation. downhole survey probe: a device containing instruments which read inclination, azimuth,

and tool face. A downhole survey probe is placed at the leading of a directional drill string and provides data which the driller uses to steer the string. E entry point: the point on a drilled segment where the pilot hole bit initially penetrates the

surface. The horizontal drilling rig is positioned at the entry point. exit point: the point on a drilled segment where the pilot hole bit finally penetrates the surface. The pipeline pull section is positioned at the exit point.

F filter cake: the layer of concentrated solids from the drilling mud or cement slurry that

forms on the walls of the borehole opposite permeable formations; also called wall cake or mud cake. filtration: the process of separating suspended solids from liquid by forcing the liquid

through a porous medium. flocculating agent: a material or chemical agent that enhances flocculation.

flocculation: the coagulation of solids in a drilling fluid, produced by special additives or by contaminants.

flow: to deform under stress or pressure without cracking or rupturing. fluid: a substance which will flow and readily assumes the shape of the container in which

it is placed. The term includes both liquids and gases. fluid loss: a measure of the relative amount of fluid lost (filtrate) by filtration of the drilling

fluid into a permeable formation. flycutter: an open circular, cylindrical, or radial blade soft soil reaming tool with cutting

teeth and fluid nozzles arrayed on the circumference and blades. fracture zone: zone of naturally occurring fissures or fractures that can pose problems with

lost circulation.

frame: the component of a horizontal drilling rig on which the carriage travels. It is

generally set at an angle of 6° to 20° with horizontal. It is analogous to the mast on a vertical drilling rig. G gel: a semisolid, jelly like state assumed by some colloidal dispersions at rest. When

agitated, the gel converts to a fluid state. bentonite.

Gel is also used informally as a name for

gel strength: a measure of the ability of a colloidal dispersion to develop and retain a gel

form, based on its resistance to shear. The gel strength, or shear strength, of a drilling mud determines its ability to hold solids in suspension. Sometimes bentonite and other colloidal clays are added to drilling fluid to increase its gel strength. gravel: particles of rock that will pass a 3” (75 mm) sieve and be retained on a No. 4 (4.75

mm) U.S. standard sieve. H hole opener: a rock reaming tool utilizing roller cutters to cut harder material than can be

penetrated with a flycutter. hole sizing: the act of moving a bit or reamer along a drilled hole one or more times to

insure that the hole is open and annular drilling fluid flow can take place. horizontal directional drilling (HDD): a two-phase trenchless excavation method for

installing buried pipelines and conduits. The first phase consists of drilling a directionally controlled pilot hole along a predetermined path extending from grade at one end of a drilled segment to grade at the opposite end. The second phase consists of enlarging the pilot hole to a size which will accommodate a pipeline or conduit and pulling the pipeline or conduit into the enlarged hole. The method is accomplished using a horizontal drilling rig. a conical device which directs drilling fluid flow in a spiraling manner thereby setting up centrifugal forces which aid in separating solids from the fluid. Hydrocyclones are also referred to as cyclones or cones. hydrocyclone:

hydrostatic head: hydrostatic pressure. hydrostatic pressure: the force exerted by a body of fluid at rest; it increases directly with

the density and the depth of the fluid and is expressed in psi or kPa. The hydrostatic pressure of fresh water is 0.433 psi per foot of depth (9.792 kPa/m). In drilling, the term refers to the pressure exerted by the drilling fluid in the wellbore.

I

IADC: International Association of Drilling Contractors located in Houston, Texas. inadvertent return: uncontrolled flow of drilling fluid to the surface at locations other than

the entry or exit points. inclination: the angular deviation from true vertical or horizontal. In drilling, inclination is typically measured from vertical. J

advancing a drilled hole by using the hydraulic cutting action generated when drilling fluid is exhausted at high velocity through the leading edge of a drill string.

jetting:

laminar flow: flow in which fluid elements move along fixed streamlines which are

parallel to the walls of the channel of flow. LCM: lost circulation material.

an organic drilling fluid additive derived from by-products of a papermaking process using sulfite; added to drilling mud to minimize fluid loss and to reduce the viscosity of the mud. lignosulfonate:

liquid limit: the water content at which a trapezoidal groove of a specified shape, cut in a

moist soil held in a special cup, is closed after 25 taps on a hard rubber plate. liquefaction: the process of making or becoming liquid. Liquefaction can occur in certain soils due to a build-up of pore pressure. lost circulation: the quantities of whole mud lost to a formation, usually in cavernous, fissured, or coarsely permeable beds, evidenced by the complete or partial failure of the mud to return to the surface as it is being circulated in the hole; also called lost returns. low clay solids mud: heavily weighted muds whose high solids content (as a result of the large amounts of barite added) necessitates the reduction of clay solids. low-solids mud: a drilling mud that contains a minimum amount of solid material (sand,

silt, etc.) and is used in rotary drilling when possible because it can provide fast drilling rates. lubricity: the capacity of a fluid to reduce friction.

M Marsh funnel: a calibrated funnel used in field tests to indicate the viscosity of drilling mud. metastable structure: a soil structure which is stable only because of the existence of some

supplementary influence. A sand deposited simultaneously with silt may exhibit a metastable structure due to the silt particles interfering with the intergranular contact between the sand particles. A shock or sudden loading may cause the structure to break down and liquefy. montmorillonite: a clay mineral often used as an additive to drilling mud. It is a hydrous aluminum silicate capable of reacting with such substances as magnesium and calcium. mud: the liquid circulated through the wellbore during rotary drilling operations. Although

it was originally a suspension of earth solids (especially clays) in water, the mud used in modern drilling operations is a more complex, three-phase mixture of liquids, reactive solids, and inert solids. The liquid phase may be fresh water, diesel oil, or crude oil and may contain one or more conditioners. mud balance: an instrument consisting of a cup and a graduated arm with a sliding weight

and resting on a fulcrum. It is used to measure the unit weight of the mud. mud cleaner: a piece of equipment combining vibratory screens and hydrocyclones to achieve effective solids control.

to add solid materials (such as bentonite or other clay) to a drilling fluid composed mainly of clear water to obtain certain desirable properties. mud-up:

N the basic and simplest fluid (from the standpoint of viscosity consideration) in which the shear stress is directly proportional to the shear rate. These fluids will immediately begin to flow when a pressure or force in excess of zero is applied. Newtonian fluid:

non-Newtonian fluid: a fluid in which the shear force is not directly proportional to the shear rate. Non-Newtonian fluids do not have a constant viscosity. O organic clay: clay with sufficient organic content to influence the soil properties. organic silt: silt with sufficient organic content to influence the soil properties. over bend: a vertical bend in a cross country pipeline which progresses downward.

GLOSSARY

vii

P PAC: polyanionic cellulose.

peat: a soil composed of vegetable tissue in various stages of decomposition usually with an organic odor, a dark brown to black color, a spongy consistency, and a texture ranging from fibrous to amorphous. pilot hole: a small diameter hole directionally drilled along a designed path in advance of reaming operations and pipe installation. plastic: capable of being shaped or formed; pliable. plasticity index: the numerical difference between the liquid limit and the plastic limit of a soil. plastic limit: the water content at which a soil begins to break apart and crumble when

rolled into threads l/8” in diameter. plastic viscosity: an absolute flow property indicating the flow resistance of certain types of

fluids. Plastic viscosity is a measure of shearing stress. plunger effect: the sudden increase in borehole pressure brought about by the rapid movement of a larger pipe or cutting tool along a drilled or reamed hole. poise: the viscosity of a liquid in which a force of 1 dyne (a unit of measurement of small 2

amounts of force) exerted tangentially on a surface of 1 cm of either of two parallel planes 1 cm apart will move one plane at the rate of 1 cm per second in reference to the other plane, with the space between the two planes filled with the liquid. polyanionic cellulose: a chemical compound used to reduce water loss in muds that are affected by salt contamination. polymer: a substance that consists of large molecules formed from smaller molecules in

repeating structural units. In petroleum refining, heat and pressure are used to polymerize light hydrocarbons into larger molecules, such as those that make up high-octane gasoline. In drilling operations, various types of organic polymers are used to thicken drilling mud, fracturing fluid, acid, and other liquids. In petrochemical production, polymer hydrocarbons are used as the basis for plastics. polymer mud: a drilling mud to which has been added a polymer, a chemical that consists

of large molecules that were formed from small molecules in repeating structural units, to increase the viscosity of the mud. preream: the act of enlarging a pilot hole by pulling or pushing cutting tools along the hole

prior to commencing pipe installation.

pull back: the act of installing a pipeline along a horizontally drilled hole by pulling it to the drilling rig from the end of the hole opposite the drilling rig. pull back swivel: the device placed between the rotating drill string and tools and the pipeline pull section to minimize torsion transmitted to the section during pull back installation. pull section: a string of cross country pipeline prefabricated at an adjacent location prior to

being pulled into its final position. Q R rheology: the study of the deformation and flow of matter.

rock: any indurated material that requires drilling, wedging, blasting, or other methods of brute force for excavation. roller cone bit: a drilling bit made of two, three, or four cones, or cutters, that are mounted

on extremely rugged bearings. The surface of each cone is made of rows of steel teeth or tungsten carbide inserts. rotational viscometer: instrument used for assessing mud properties, returning values for both plastic viscosity and yield point. Rock Quality Designation (RQD): an indication of the fractured nature of rock determined

by summing the total length of core recovered counting only those pieces which are 4” or more in length and which are hard and sound. RQD is expressed as a percentage of the total core run. S sag bend: a vertical bend in a cross country pipeline which progresses upward. sand: particles of rock that will pass a No. 4 (4.75 mm) U.S. standard sieve and be retained

on a No. 200 (75 µm) U.S. standard sieve. shale shaker: a device which utilizes vibrating screens to remove larger solid particles from

circulating drilling fluid. The fluid passes through the screen openings while solids are retained and moved off of the shaker by the vibrating motion. side bend: a horizontal bend in a cross country pipeline.

silt: soil passing a No. 200 (75 µm) U.S. standard sieve that is nonplastic or very slightly plastic and that exhibits little or no strength when air dry. slickenside: a smooth surface produced in rock or clay by movement along a fault or joint.

GLOSSARY

iv

soil: any unconsolidated material composed of discrete solid particles with gases or liquids between. spoil: excavated soil or rock.

an indication of the density or consistency of soils given by counting the number of blows required to drive a 2” OD split spoon sampler 12” using a 140 lb. hammer falling 30”. The sampler is driven in three 6” increments. The sum of the blows required for the last two increments is referred to as the “N” value, blow count, or Standard Penetration Resistance. Standard Penetration Test (SPT):

spud in: to begin drilling; to start the hole. sub: a short threaded piece of pipe used in a drill string to perform a special function.

a substance that affects the properties of the surface of a liquid or solid by concentrating on the surface layer. Surfactants are useful in that their use can ensure that the surface of one substance or object is in thorough contact with the surface of another substance. surfactant:

suspension: a mixture of small non settling particles of solid material within a gaseous or

liquid medium. swabbing effect: a phenomenon characterized by formation fluids being pulled or swabbed

into the wellbore when the drill stem and bit are pulled up the wellbore fast enough to reduce the hydrostatic pressure of the mud below the bit. T thixotropy: the ability of a fluid to develop gel strength with time; that property of a fluid

which causes it to build up a rigid or semirigid gel structure if allowed to stand at rest, yet can be returned to a fluid state by mechanical agitation. tool face: the direction of the asymmetry of a directional drilling string. A directional

drilling string will progress in the direction of the tool face. Tool face is normally expressed as a angle measured clockwise from the top of the drill pipe in a plane perpendicular to the axis of the drill pipe. transition velocity: the velocity at which the flow in a particular fluid flowing in a particular channel shifts between laminar and turbulent. trip: the act of withdrawing (tipping out) or inserting (tripping in) the drill string. turbulent flow: fluid flow in which the velocity at a given point changes constantly in

magnitude and direction.

twist off: to part or split drill pipe or drill collars, primarily because of metal fatigue in the

pipe or because of mishandling. V velocity: the rate of linear motion per unit of time. vices: the devices mounted on the frame of a horizontal drilling rig which grip the drill pipe

and allow it to be made up (screwed together) or broken (unscrewed). viscometer: an apparatus to determine the viscosity of a fluid. viscosity: a measure of the resistance of a liquid to flow. Resistance is brought about by the

internal friction resulting from the combined effects of cohesion and adhesion. W wall cake: the solid material deposited along the wall of a drilled hole resulting from

filtration of the fluid part of the mud into the formation. wash pipe: a drill pipe which is run, or rotated, concentrically over a smaller drill pipe so that the smaller (internal) pipe can be freely moved or rotated. water-back: to reduce the weight or density of a drilling mud by adding water or to reduce

the solids content of a mud by adding water. weight up: to increase the weight or density of drilling fluid by adding weighting material.

X X-C polymer: a biopolymer produced from a particular strain of bacteria on carbohydrates

that produces large increases in apparent viscosity while maintaining fairly good control of filtration. Y yield point: the maximum stress that a solid can withstand without undergoing permanent deformation either by plastic flow or by rupture. References API Bulletin D11, First Edition, December 1965.

Drilling Mud, Unit II, Lesson 2, Third Edition, Rotary Drilling Series, (Austin, Texas;

Petroleum Extension Service, University of Texas at Austin, 1984).

Hdd

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