PETRONAS TECHNICAL STANDARDS PROJECT MANAGEMENT
MANUAL (SM)
COST ENGINEERING MANUAL
PTS 10.009 JANUARY 1995
PREFACE
PETRONAS Technical Standards (PTS) publications reflect the views, at the time of publication, of PETRONAS OPUs/Divisions. They are based on the experience acquired during the involvement with the design, construction, operation and maintenance of processing units and facilities. Where appropriate they are based on, or reference is made to, national and international standards and codes of practice. The objective is to set the recommended standard for good technical practice to be applied by PETRONAS' OPUs in oil and gas production facilities, refineries, gas processing plants, chemical plants, marketing facilities or any other such facility, and thereby to achieve maximum technical and economic benefit from standardisation. The information set forth in these publications is provided to users for their consideration and decision to implement. This is of particular importance where PTS may not cover every requirement or diversity of condition at each locality. The system of PTS is expected to be sufficiently flexible to allow individual operating units to adapt the information set forth in PTS to their own environment and requirements. When Contractors or Manufacturers/Suppliers use PTS they shall be solely responsible for the quality of work and the attainment of the required design and engineering standards. In particular, for those requirements not specifically covered, the Principal will expect them to follow those design and engineering practices which will achieve the same level of integrity as reflected in the PTS. If in doubt, the Contractor or Manufacturer/Supplier shall, without detracting from his own responsibility, consult the Principal or its technical advisor. The right to use PTS rests with three categories of users : 1) 2) 3)
PETRONAS and its affiliates. Other parties who are authorised to use PTS subject to appropriate contractual arrangements. Contractors/subcontractors and Manufacturers/Suppliers under a contract with users referred to under 1) and 2) which requires that tenders for projects, materials supplied or - generally - work performed on behalf of the said users comply with the relevant standards.
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CONTENTS INTRODUCTION SECTION A - ONSHORE PRODUCTION FACILITIES AND TERMINALS SECTION B - OFFSHORE FACILITIES SECTION C - OFFSHORE SUBSTRUCTURES SECTION D - SUBSEA PIPELINES SECTION E - MINOR PROJECTS (FUTURE) SECTION F - PROJECT LEAD TIMES SECTION H - WORKED EXAMPLES
INTRODUCTION This document is a modified version of the SIPM E & P Cost Engineering Manual (CEM) Volume II. SSB/SSPC inhouse data, like design manhour norms and cost rates, fabrication cost rates, installation and the duration norms and cost rates have been incorporated to customise the module for local applications. It provides type methods for preparing Type II cost (CAPEX) estimates for the following Hardware elements •
Onshore Facilities and Terminals
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Offshore Topside Facilities
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Offshore Fixed Substructures
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Sub-sea Pipelines
Purpose of This Document This document is intended to be used for preparing type II cost estimates (accuracy range ±25%). It is therefore suitable for projects that are in the Study/Optimisation and Conceptual design phases. The method may also be suitable for preparing Company estimates for fabrication costs. Method of Update This document will be updated by EDV/14 twice a year, i.e. June and December updates, with cost st st reference dates of 1 July and 1 January of each year respectively. The update will be based upon the following sources of data •
Feed back from EDV/1/2/3/4, EPO/2/4/5/6, ETS/1 /2/3, EGP
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Feed back from current and newly completed projects
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SIPM revised Cost Engineering Manual Volume II
1.1 COST ENGINEERING MANUAL USER GUIDE The manual contains Type II cost estimating method having an accuracy within ±25%. The improved accuracy of the Type II method is achieved by breaking projects into a larger number of smaller building blocks, by requiring more project specific input data, and by using more detailed algorithms to determine the engineering quantities for each building blocks, by requiring more project specific input data, and by using more detailed algorithms to determine the engineering quantities for each building block. Generally the manual employs SI unites modified for 'oil field' use. For example, pressure is in bar and pipeline diameter is in inches. For reference purposes, graphs have been provided with a secondary axis indicating units such as barrels per day and millions of standard cubic feet per day where appropriate. Unit cost rates and costs are in Ringgit Malaysia throughout. A detailed user guide for the Type II estimating method is provided in Section 5.1. The user guides outline the procedures to be followed from definition of the project and obtaining the minimum basic data required for the estimate through to the preparation of the final cost estimate and phased capital expenditure summary. further guidance and step by step procedures are provided within each of the various individual Hardware Category estimating methods. Sections 5.2 contain the descriptions and definitions of the Hardware Item and Project Function building blocks for the Type II methods.
Section 5.3 contain guidance on project definition, input data requirements, the selection of Hardware Items and the preparation of field development scenarios for prospect evaluation for Type II estimating methods. For the user familiar with the rest of the manual, the cost estimating process will normally start in this section. When using the manual it is important that the estimator be familiar with section 2 - Cost Engineering. This section outlines the principles and practices of cost engineering as adopted in this manual, and explains how a Project is broken down into building blocks, the relationships between the building blocks, and the terminology associated with cost engineering as used throughout this manual. Before proceeding, the user's attention is drawn to the following: •
This manual is confidential and all methods and data contained herein must be treated as such.
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The manual 'is for the preparation cost estimates and should not be used for design purposes.
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Users in E&P Operating Companies should contact their cost engineering focal point to obtain data which is particular to their Operating Company.
The user is also cautioned against using the manual for purposes for which it is not intended such as using individual engineering quantities or unit rates in isolation. Cost estimates prepared in these circumstances may not have the degree of accuracy normally associated with a Type II estimate for a complete Hardware Item.
1.3 DEFINITIONS AND TERMINOLOGY The following list of definitions and terminology is intended to provide the user with an overview of the most commonly used terms in the Cost Engineering Manual. In addition to the list below, descriptions of the various Hardware Items and Project Functions are found in Section 5.2, and descriptions of the numerous System Groups and Systems are provided within the sections of the manual in which the individual 'System Group or System is identified. ACCURACY The band width, expressed as +X%/-Y% relative to the 50/50 value of an estimate, outside which the probabilities of overrun and underrun are each less than 10%. ACTIVITY An item of work performed on (a part of) a Project, It can be represented as an Intersection on a Hardware Item/Project Function matrix. ACTIVITY ALLOWANCE An allowance added in the course of preparing a base estimated for an activity to cover identified but yet unquantified elements In this manual the activity allowances are built into the algorithms for deriving quantities and are not identified separately. BASE ESTIMATE Comprises the activity estimate plus the activity allowances (i.e. those uncertainties which are known historically will occur). In the manual this corresponds to the sum of all Project Function costs for a Hardware Item. CALM Catenary Anchored Leg Mooring. A chain and buoy based vessel mooring system or product loading terminal.
CEM Cost Engineering Manual. CONSTANT VALUE MONEY (CVM) Costs or revenue expressed on the basis of the value (purchasing power) or money at a stated point in time. CONTINGENCY Funds added to the Hardware item base estimate in order to take into account the degree of uncertainty in estimating and thus to provide an acceptable level of confidence in the total estimate. CRM The SIPM E&P Cost Reporting Manual (Report EP-90-3030). DSV Diving Support Vessel. ESTIMATOR The person using the CEM to obtain a cost estimate for a particular project. 50/50 ESTIMATE An estimate with an equal probability or overrun as underrun. Comprises .base estimate (which includes activity allowance) plus contingency. Basis for economics/sensitivity analysis. FPSU Floating Production and Storage Unit. FPU Floating Production Unit. FSU Floating Storage Unit. HARDWARE A physical component of a Project, which has defined physical and organisational interfaces with other Hardware Items. For example a jacket, a gathering station or a pipeline. Reference should also be made to Section 5.2. HARDWARE CATEGORY A heading for 'functionally similar hardware Items. For example onshore pipelines, floating substructures or offshore production facilities. A separate cost estimating method is provided for each of 10 Hardware Categories (Sections 5.4 to 5.13). HARDWARE ITEM/PROJECT FUNCTION MATRIX A technique for breaking down a Project into logical, manageable and controllable elements on the basis of Hardware Items and Project Functions. HLV Heavy Lift Vessel or crane barge.
MANHOURS Engineering manhours are the total engineering manhours including engineering contractors project management manhours. Construction, fabrication, and onshore commissioning manhours are the direct manhours only. Offshore hook-up and commissioning manhours are direct, indirect and nonproductive. MONEY OF THE DAY (MOD) Costs or revenue expressed on the basis of the value (purchasing power) or money at the time when each cost or revenue element is expected to occur. OPCO A Shell Group E&P Operating Company. OLU Offshore Loading Unit, using a CALM buoy to provide an in field or at shore product loading facility for shuttle tankers. PMG The SIPM E&P Project Management Guideline (Report EP 86-0500). PROJECT For the purposes of this manual, a Project is defined as being an exploration or development prospect, a field development project, a feasibility or screening study, a detailed engineering study, or any other activity related to oil or gas field development. PROJECT FUNCTION A discrete element of work performed on a Hardware Item such as design, procurement, construction or a discrete cost element related to the Hardware Item such as insurance and certification. Reference should also be made to Section 5.2. REGION Geographical areas which, for the purpose of the manual are defined as •
1. Europe
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2. Africa
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3. Middle East
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4. Far East
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5. Western Hemisphere, (North, South and Central America)
Reference should also be made to Section 3.6. RM Ringgit Malaysia ROV A remotely Operated Vehicle used to support underwater maintenance, inspection or construction activities.
SYSTEM GROUP A physical component of a Hardware Item and the smallest building block for a Type I estimate. Each Hardware Category has a fixed set of System Groups, some or all of which may be selected by the Estimator to make up a particular Hardware Item. For example, the fixed substructures category has jacket steel, piles and anodes as its three System Groups. SYSTEM A physical component of a System Group and the smallest building block for a Type II estimate. Each System Group has a fixed set of Systems, some or all of which may be selected by the Estimator to make up a particular System Group. For example the oil processing System Group has separation, heating, dehydration and water treatment as its four Systems. TAD Tender Assisted Drilling. A method to drill platform wells using a platform mounted derrick equipment set, and a tender support vessel moored alongside the platform on which additional drilling equipment and accommodation is located and from which drilling support services are provided. The use of Tender Assisted Drilling reduces the amount of drilling related equipment on the platform .and consequently the platform topside facilities and jacket weights. TYPE I The highest estimating level of a Project. Type I cost estimates are defined as having an accuracy within ±40%.. TYPE II The level below Type I for estimating a Project. Type II cost estimates have smaller blocks that Type 1, and are defined as having an accuracy within ±25%. USER The Person using the CEM to obtain a cost estimate for a particular project.
1.4 REVISIONS AND CHANGES The Cost Engineering Manual will be revised biannually. Individual sections, figures and forms will be updated to reflect changes in the technical and cost data, to incorporate estimating methods for new technology and to include corrections, additions, suggestions from users, etc. Updated sections and pages will be issued to all registered holders of the Cost Engineering Manual and will be identifiable from the revision number and date printed at the bottom of each page. The entire manual will be reissued periodically, dependent upon the extent of interim revisions and updates. A record of revisions will be maintained, and Will be recorded on Figure 1.1. Proposals for corrections, additions and other changes to the manual should be made to EDV/14. All proposed changes will be reviewed by, and be subject to the approval of the appropriate discipline engineering section within SSB/SSPC before being incorporated. Proposed changes should therefore be submitted to EDV/14 using a copy of Form 1.1. If the proposal involves amendments to existing pages of the manual, a copy of the marked-up pages should be attached to Form 1.1. Feedback from users regarding this update or the entire CEM would be appreciated, and can be noted on the User's Feedback Form 1.1.
1.5 BIBLIOGRAPHY The following list of references may be used in conjunction with this Manual. GENERAL •
SIPM E&P Project Management Guideline, SIPM EP90-4000, December l990
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Production Handbook, by Production Division, SIPM (updated June 1987)
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The use of S1 Units, PTS 00.00.20.10, (Revised March 1985)
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Guidelines for preparation of Field Development Plans, SIPM EP87-0879, March 1987
COST ENGINEERING •
Spreadsheet version of the Cost Engineering manual User's Guide, SIPM EP 91-0320, March 1991.
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Cost Engineering System Feasibility and Analysis Report, SIPM EP-91-0975, June 1991
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Engineering Benchmarks, SIPM EP 91 -1190, November 1991
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Introduction to Cost Engineering for E&P Projects, SIPM -EP/23.6, August 1982. SIPM EP56233 (now superseded by this Manual)
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Standard formats for Cost Engineering for E&P Projects, SIP EP/-23.6 June 1982. SIPM EP55420 (now superseded by this Manual)
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Applied Cost Engineering, Forest Clark and A. Lorenzoni, Marcel Bakker Inc. New York
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Cost estimating manual for pipelines and marine structures, J.S. Page, Gulf Publishing Company, Houston
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Estimator's equipment installation man-hour manual, J.S. Page, Gulf Publishing Company, Houston
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Estimator's piping man-hour manual, Page and Nation, Gulf Publishing Company, Houston
BUDGETS AND COST DATA •
SIPM E&P Cost Reporting Manual, SIPM EP 90-3030, November 1990.
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Programme data books (Procedure for the presentation of Programme and Budget Data) SIPM EP 89-000, November l990
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Capital Budget Manual SIPM EP 60-791, March 1987
Fig. 1.1 - Form EDV14: (Revisions Number / Cost Ref / Reasons for Revision)
Form 1.1- Form EDV14 (Ref Indicator / Page Number / Comments etc.)
Costs Estimate(s) / Type(s) used / Completed Evaluations - Form EDV14
2 COST ENGINEERING 2.1 INTRODUCTION Cost estimates of progressively increasing accuracy are required at every stage of prospect appraisal and project planning, and provide the basis for economics analysis, management decisions, budgets and cost control. Each estimate must correspond to the recommended level of accuracy for the particular phase in the life of an exploration prospect or field development project. The CEM is designed to produce cost estimates for the screening and feasibility studies normally associated with the identification phase of prospective field development projects. The manual therefore relates primary" to the identification phase, but is of course also relevant to all other project phases. For specific guidance on cost engineering during the definition and execution phases of a project, reference should be made to Group literature such as the SIPM E&P Project Management Guideline, (EP 90- 4000), SIPM E&P Guidelines for the Preparation of Field Development Plans, (EP 87-0879), and SIPM E&P Programme and Budget Documentation, (EP 59-000), as well as local Operating Company practices. The basic general principles of cost engineering are described in Section 2.2 - Principles of Cost Engineering. The application of these principles in the CEM is explained in detail in Section 2.3 - Cost Engineering in Practice.
2.2 PRINCIPLES OF COST ENGINEERING 2.2.1 Key Steps in Cost Estimating Cost estimates are required to predict the final cost of a project at any point in time and play an essential role in the economic appraisal or, as a cost model, in the Optimisation of design, execution or operation of a project. Cost engineering covers the entire process by which a cost estimate is determined and includes the following key steps: •
Definition of the project for which the estimate is required.
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Division of the project into building blocks.
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Estimation of the cost of each building block.
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Summation of the individual costs to obtain the total cost estimate.
The availability of project specific data, the degree of definition of the scope of the project, the number and nature of the building blocks, and the method used to estimate the cost of each individual block all impact on the overall accuracy of the estimate, The need to formalise the estimating methods and to define the individual building blocks is therefore crucial, to ensure that cost estimates are both consistent and reliable, with an accuracy commensurate with the purpose for which the estimate is performed. 2.2.2 Uncertainty, Contingency and Accuracy Estimates are usually predictions of future events and therefore provision must be made for uncertainties. This is done by adding allowances and contingencies to the estimated cost of either individual building blocks or the project as a Whole. These additions increase the probability of the final actual project cost not overrunning the estimated cost. 'This probability is also referred to as the level of confidence in the estimate and increases as a function of the value of the allowances and contingencies included. As estimate with a 90% chance of the final cost not exceeding the estimate (and therefore only a 10% chance of overrun) is referred to as a 90/10 estimate to identify it's level of confidence. In such an estimate, allowances and contingencies will be greater than for an estimate to the same project with an equal chance of overrun and underrun, which would be called a 50/50 estimate.
The purpose of a particular estimate will decide which confidence level is required. Field development economics for instance are usually based on 50/50 estimates. Care should be taken in selecting contingency values. Unnecessarily high contingencies and allowances in cost estimates for prospect appraisal, for instance, may lead to good business opportunities being missed. On the other hand, as contingency provides a measure of protection against uncertainties and the unforeseen, insufficient levels of contingency in such a case may lead to overly optimistic expectations of profitability. Having established the value of the estimate with an equal chance of overrun and underrun (50/50 estimate), the extent to which final actual project cost may over or underrun this estimate must be specified. This is the accuracy of the estimate and is usually express a ±X%, for instance ±25% for a feasibility study estimate. To put practical limits on the accuracy range, its upper and lower boundaries are defined as having a probability of less than 10% of overrun or underrun, respectively. As a consequence, these boundaries coincide with the 90/10 and 10/90 values of the estimate. In Section 2.3, Cost Engineering Practice, this approach is discussed in more detail. 2.2.3 Cost Phasing Cost estimates may be phased over time in order to obtain a project expenditure profile based on the project schedule and the individual duration's associated with the completion of each of the project building blocks. This introduces the time factor in the estimate and is an essential exercise if the estimate is to be used for the analysis of field development economics on the basis of discounting. Furthermore, if in addition to the phased capital expenditure profile, a production profile and an estimate of the annual operating expenditure are available, then the estimated discounted unit technical cost of the project may also be derived. This is a useful preliminary indicator of profit ability when compared to the projected oil or gas price and may, in this form, be used to test the feasibility of the selected development scenario.
2.3 COST ENGINEERING IN PRACTICE 2.3.1 Cost Estimating The section of the manual expands the basic general principles outlined in Section 2.2 and demonstrates how these principles have been incorporated into the cost engineering practice adopted in this manual. The process by which a cost estimate is determined is further detailed below. The key steps in the preparation of a capital cost estimate for a project are : •
To define the nature and key parameters of 'scope' of the project or development scenario being considered.
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To breakdown the project into building blocks or 'Hardware Items', and to a level of details appropriate for the type of estimate required.
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To further breakdown each Hardware Item into discrete activities or "Project Functions'.
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To derive the engineering or physical quantities of each Hardware Item using a method which takes account of key parameters of the project.
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To estimate the cost of each Project Function by application of unit cost rates to the derived engineering quantities for each Hardware Item.
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To add appropriate allowances and contingencies to the individual estimates at Hardware Item or Project Function level.
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To phase the components of the total cost estimate to obtain an expenditure profile which reflects the project schedule.
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To summate and record the complete estimate from the definition of scope, through the derivation of quantities and the application of unit cost; rates to the final estimated cost of the project.
These steps are required in all estimates, however the reason for the estimate and the accuracy required will determine the degree of definition and the extent to which the project need be broken down into building blocks. The type of estimate performed should therefore be commensurate with the purpose for which it was prepared. The practice adopted in the Cost Engineering Manual is therefore 1. To select and estimate type based on the .purpose of the estimate and the accuracy required, 2. To adopt a pre-determined breakdown structure for the selected estimate type. 3. To follow a consistent estimating method across the complete breakdown structure. The above can be summarised in the following cost estimating elements which are addressed in the subsequent sections : 1. Estimate types and accuracy 2. Breakdown structure. 3. Estimating method. 4. Contingencies and allowances. 5. Cost phasing. 2.3.2 Estimate Types and Accuracy Estimates are classified as screening, study, budget or control estimates (also referred to as Type I to IV) to give an indication of the accuracy which may be assigned to the cost figures. The accuracy is a function of the engineering effort permitted by the scope definition. It is also a function of the variance in both the derived engineering quantities and the unit cost rates selected for the estimate. Figure 2.1 gives a summarised description to estimate types, their application and expected accuracy. The detail of engineering effort required to estimate cost within these levels of accuracy is indicated in this figure through reference to the "Technical data required for cost estimate'. The expected accuracy of an estimate is expressed as ± X%, for instance ± 25% for a study estimate. The upper and lower boundaries of the accuracy range are defined as having a probability of less than 10% of overrun and underrun respectively. In other words an estimate with a value of 200 and an expected accuracy of ±25% would have a probability of 10% that actual cost will exceed 250 or be less than 150. Estimates produced from this manual are expected to have an accuracy within ±25% for Type 11 estimate. As will be exploited in Section 2.3.5 - Contingencies and Allowances, the accuracy range as determined by the estimator (possibly with the aid of Figure 2.1) plays a role in the definition to the confidence level of the estimates.
2.3.3 Breakdown Structure The selection of building blocks from which to compose the hardware required for the particular development scenario under study is the second step in the estimating process. It this important that the boundaries of these building blocks are clearly defined, as this determines the estimating methods to be used. For the estimating methods contained in this manual, the boundaries are specified in the relevant chapters. The breakdown structure adopted for the cost engineering system of which this manual forms part (see also Section 2.4 - Cost Engineering System) is a Hardware Item/Project Function matrix, whereby Hardware Items form the physical building blocks of a project and Project Functions are the discrete elements of work performed on the Hardware Items (these definitions are further explained below). For 'Type II estimates a more detailed breakdown of hardware is used to obtain more accurate estimates. The structure of the Hardware Item/Project Function matrix is described in more detail in the following. Project The cast engineering methods in this manual are applicable to oil and gas field development Projects, either onshore or offshore. The Project is the provision, from engineering through to commissioning, of the facilities necessary to produce a field and deliver the products to the point of sale or to an existing transportation system. The Project facilities cover drilling of development wells, production facilities, in field and export pipelines, oil export terminals and new permanent infrastructure. Hardware Category Hardware Items are chosen and described by the Estimator in order to fully define the Project. In this manual, similar Hardware Items are grouped together into Hardware Categories. For example, a gathering station and a production station are two Hardware Items in the onshore production facilities category. To date a total of 5 Hardware Categories have been included in this manual as follows •
Production facilities - onshore
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Production facilities - offshore
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Substructures - fixed
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Pipelines - offshore
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Terminals
The purpose of grouping items into Categories is that there is one estimating method for each Category, applicable to all Hardware Items in that Category. It is quite possible that a Project will have more than one Hardware Item in a particular Hardware Category (e.g. a central jacket and a satellite jacket). This points to an important distinction between the terms Hardware Item and 'Hardware Category; a Hardware Item is a physical building block of a 'Project, whereas a Hardware Category is a subdivision of the estimating methods within this manual. Hardware Item The first breakdown of a Project is into Hardware Items. These are components with clearly defined physical and organisation boundaries. Examples of possible Hardware Items for an offshore oil field are a steel jacket substructure, the topsides production facilities, the wells drilled from the platform, the export oil and gas pipelines, an onshore storage terminal, a marine facility for supply vessels and a heliport.
System Group Hardware Items are broken down into System Groups, which are the smallest building blocks for a Type I cost estimate. Each Hardware Category has a fixed set of System Groups, some or all or which may be selected by the Estimator to make up a particular Hardware Item. For example, the fixed substructures category has jacket steel, piles and anodes as its three System Groups. It is helpful to conceive the breakdown described so far as a triangle. This triangle, shown in Figure 2.2 depicts the manner in which a Project is broken down into successively smaller components, each level of breakdown giving an estimate of greater accuracy. System The final breakdown used in this manual is that of System Groups into Systems. These are the smallest building blocks for a Type 11 estimate. Each system Group has a fixed set of one or more Systems, some or all of which may be selected by the Estimator to make up a particular System Group. For example, the oil processing System Group separation, heating, dehydration and water treatment as its four Systems. The Hardware Category breakdown structures are presented in Figures 2.4. to 2.5. The pre-defined System Groups and Systems are identified for each of the Hardware Categories, and are defined in more detail within the relevant Hardware Category sections. There are two further breakdowns shown in Figure 2.2. which are beyond the scope of this manual, The first is to break Systems into tagged equipment of the same type (e.g. piping, electrical, etc.). These equipment/materials group further broken down into •
Equipment list of all tagged equipment
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Piping broken down by size and specification
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Cabling broken down by size and specification
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Etc.
These breakdown levels are used for Types III and IV estimates. Project Functions Project Functions are discrete elements of work performed on a Hardware Item, e.g. procurement, or a discrete cost/budget element related to that item, e.g. insurance. The Project Functions are as follows: Onshore : •
Procurement
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Construction
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Commissioning
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Engineering and design
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Project Management
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Insurance and certification
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Drilling
Offshore : •
Procurement
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Fabrication
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Transportation and installation
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Hook-up and commissioning
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Engineering and design
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Project management
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Insurance and certification
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Drilling
Note that not all Hardware Items have all Project Functions, for example infrastructure has only construction and project management. 2.3.4 Estimating Method Once the estimate type and associated breakdown structure are selected on the basis of the desired accuracy of the estimate, as described in the previous two sections, the next step in the cost estimating process can be taken. This involves the definition of a minimum number of parameters, which together describe the scope of the development scenario in question. These parameters include location, reservoir depth, production plateau etc. When these have been determined, a selection can be made of Hardware Items and System Groups/System in order to compose an engineering development scheme. It is stressed that the cost of any development is decided to a large extent at this stage on scope definition and hardware selection. Optimisation of a development scenario and the selection of the most suitable and cost effective arrangement of hardware often have more impact on cost than the application of new, cost saving technology. Sufficient time should therefore be allowed for these front end activities, which in practice may involve the production of a number of estimates for different development scenarios in order to identify the optimum solution. The hardware selected for the development under study can be defined in terms of engineering quantities. These quantities include weight of substructure steel in tonnes, drilling time for wells in days, design time for production facilities in mandays etc. Each of the parameters defining the scope of the development will have an impact on one or more of the engineering quantities. For instance, water depth will impact an substructure weight and so forth. Each Project Function executed to realise the project will incur a cost depending on the quantities involved. These costs can be expressed as unit cost rates such as fabrication cost for substructures in RM $/tonne or drilling cost for wells in RM $/day etc. These rates are specific to both the Hardware Item and the Project Function in question. A cost estimate of a particular development is therefore produced by translating the scope of the development into engineering quantities which are then multiplied by unit cost rates per Project Function to arrive at cost. In summary : SCOPE --> QUANTITIES x RATES = COST This manual guides the user through this process by : •
Requesting the necessary information in to define the scope of a development (or part thereof, such as the user requires). This will be more detailed for Type II estimates than for Type I estimates.
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Offering guidance in the composition of a suitable engineering development scheme.
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Providing methods to translate scope into quantities for a large variety of Hardware items and System Groups/Systems form which onshore and offshore engineering development schemes can be composed.
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Providing unit cost rates per Project Function for the spectrum of Hardware Items covered in the manual.
2.3.5 Contingencies and Allowances Through the process described in the previous chapters, an estimate is obtained of development cost associated with the particular scope defined for the estimate. There is a tendency, however, for the scope of the unique type of projects executed by E & P , to grow. As a consequence, typically greater quantities are required than estimated in a first approach; that is the base estimate (see also below).To cater for this growth of scope, contingencies and allowances are added at various points in the estimating process. The contingencies are therefore real cost elements, albeit for 'unspecified' scope and are thus related mainly to quantities. Obviously, a more detailed definition of scope not only improves the accuracy of the estimate but also reduces the levels of contingency to be applied. Contingency should never be used as comprehensive cover for each and every uncertainty, or as insurance against all conceivable disasters since this would lead to 'padded' estimates and inflated budgets. Contingencies are assigned at three stages in the estimating process : Activity Allowances Activity allowances are added by the estimator to the various cost Items to account for cut and waste, weather downtime, weight growth and to the such known uncertainties, which have a high probability of occurring. Activity allowances are added to the various cost items at the discretion to the estimator. The resulting estimate is named "base estimate'. When using this manual it may be assumed that activity allowances are included in the estimates so that these would quality as "base estimates". Contingency Contingency is added to the base estimate to allow for incomplete project definition (but riot for major scope changes, each of which would require a new project estimate). Current practice, in many cases, is to add what is considered reasonable at the discretion for the estimator, to cover the unknown uncertainties. The resulting estimate is named '50/50 estimate'. By definition of this estimate the project has an equal chance of overrunning the 50/50 estimate within its accuracy range. The estimate thus derived could be considered the "most likely" estimate and should therefore be used as the basis for the analysis of development economics and, in later stages, as the target for project expenditure. Overrun Allowance An allowance is added to the 50/50 estimate to allow for the risk of overrunning this estimate. A project estimated to cost for instance 200 with and accuracy of ±25% may require an actual expenditure of 250. Thus, the accuracy range could be taken as the monetary "exposure" of the project. Therefore, by adding a value representative of the accuracy range (and named the overrun allowance) to the 50/50 estimate, and estimate is arrived at with 10% probability of being exceeded by the actual cost. This estimate is named a "90/10 estimate" and could be considered a 'minimum risk' estimate. It may be sued for the setting of budget levels or the sensitivity analysis of field development economics.
Contingency may be assigned to the complete estimate to development cost or to the individual Hardware Items. In choosing the later approach the estimator has the possibility to assign different contingency percentages to different cost elements. For instance, sufficient well stream data may be available to allow the use of a modest contingency level to the cost of production facilities while uncertainties on the routing of the associated export pipeline may require a much higher percentage. When a large number of similar wells forms part of a development scheme then it may be considered mot to assign contingency at all to well cost in view of the repetitive nature of the drilling operation, etc. A further refinement could be applied by assigning individual contingencies to Project Functions for each Hardware Item, for instance 10% to design and 30% to hook up and commissioning, etc. The individual contingency percentages must be converted to absolute cost values, summed and then divided by the Base estimate to get an indication of the overall contingency in the form of a weighted percentage for the total cost estimate. The table below indicates typical overall contingency levels expected at the various stages of the project definition to which the estimator may compare the results of this exercise. Accuracy levels mentioned in Figure 2.1. are added for reference. Table of Typical Overall Contigency Levels
As stated before, allowances and contingencies are real cost elements in an estimate and therefore deserve proper attention. In practice, however, only a certain amount of time and resources will be available for any estimate. This should be assigned evenly to each step in the estimating process. The estimator should guard against the tendency, sometimes observed, to devote a disproportionate amount of effort in the area of contingency, thus neglecting the important areas of optimising the development scheme, gathering the maximum amount for input data, etc.
2.3.6 Cost Phasing and Escalation Once the project estimate of the required confidence level has been established, the expenditure of cost over time can be determined. This expenditure profile should reflect not only the durations associated with design, procurement, construction etc. of the individual Hardware Items but also the various lead-times as dictated by the overall project schedule. The manual contains methods which help to establish a profile which reflects these considerations. Cost estimates should be prepared initially in constant value money (CVM), referenced to a base reference date, and this should form the basis for the cost phasing. The CEM provides estimates in terms of CVM with a reference date. The phase cost estimate may then be presented in either CVM with a specified reference date, or escalated to Money of the Day, (MOD). Escalation, which estimates the future combined effect of general inflation and market conditions specific to the project, is necessary if the phased cost estimate is to be used for economics analysis.
2.4 COST ENGINEERING SYSTEM The manual provides methods for the translation of scope into quantities together with unit rates per Project Function (procurement, fabrication, ect.) for a variety of Hardware Items which can be combined to reflect any onshore or offshore development. To be able to generate the various methods and rates, a significant sample of technical and cost data must be available and be maintained for each to the building blocks addressed in the system. An integral part of the cost engineering system is, therefore, a Cost Engineering Data Base (CEDB). In this data base, technical and cost data of completed and ongoing projects will be stored, together with any other reliable data which may contribute to the derivation for methods and rates. The CEDB will be equipped with facilities which will allow manipulation of the cost data (such as adjustment for exchange rates, inflation, escalation, etc.) and updating and analysis of the technical data. In this way, every year an up-to-date CEM can be available to users. In addition to cost and technical information, the database will also contain information on expenditure phasing to support the phasing method given in this manual. The definition of a cost breakdown structure is a very important step in the development of a cost engineering system as it determines not only the structure on the database and the manual but also of the data gathering process required to obtain the necessary information for the CEDB. The majority of data will be obtained from the Operating Companies, Via the Cost Reporting Manual (CRM). Some effort may be required initially to make available project data fit the structure but in time if is expected that the breakdown structure will be used by all Operating Companies to estimate, record and report cost. Data gathering will then become a matter of routine, and the considerable benefits to be obtained form a consistent approach to cost engineering throughout SIPM and E & P Operating Companies will be realised. A computerised Cost Engineering system is being developed which will cover all aspects of the Cost Engineering scope providing user friendly facilities for the production of a prospect estimate, the recording of project estimates and actuals, the maintenance of reference and conversion data and the flexible analysis of all information held, (Cost Engineering System Feasibility and Analysis SIPM Report EP91 - 09 75)
2.5 NEW TECHNOLOGY AND COST REDUCTION For several years the oil industry has been faced with uncertain world oil market and increasing cost of recovery. Consequently there has been considerable effort spent to reduce the cost of developments. All aspects of design and project execution are being reviewed, e.g. new engineering technology, design codes, drilling practice and equipment, contracting strategy etc. As a result of these studies considerable potential has been identified to save development cost by the application of new engineering and drilling technology, once it becomes available for use in the field. To reach the stage of development, each prospect will have to go through the various stages of exploration and appraisal with the screening of economics at the major decision points. To meet the potential expected from the application of cost saving techniques, the associated cost engineering should incorporate these techniques, provided that the technology will be available at the time of prospect development. The following will be required therefore to integrate new technology into the cost engineering system •
development of cost estimating methods for new technology.
•
An assessment of the time scale within Which this technology may be assumed to be available for application in the field.
•
Guidance on the limitations to application of the new technology.
The development of new estimating methods will necessarily follow or run in parallel with the development of the associated technology. Inevitably, in the absence of such methods the envisaged cost saving potential will not be used to its full extent. The development of the estimating methods remains therefore as urgent a requirement as the development of the technology itself. The approach taken in the Cost Engineering Manual is to utilise mainstream, proven technology, Current practices and design codes. Changes in these areas will be incorporated into the CEM as soon as the particular technology becomes accepted for field application and data becomes available. The new technology discussed above includes such techniques as multiphase pumping and automated drilling, that is technology not yet available for application in field development. The studies mentioned in the foregoing also re-emphasised the need to carefully consider already available technology and to spend sufficient effort in identifying the optimal development scheme as early as possible in the life of a project. Particular attention has been drawn to areas like offshore tender assisted drilling, optimal use of satellite platforms, reduced offshore manning levels, optimised platform topside facilities etc. The contents of the current revision of the manual will allow the user to take the recommendation with regard to these areas into full account, even though in certain cases such as for an estimate for an optimised topsides, in the required level of detail may make it necessary to use Type II.
2.6 OTHER CONSIDERATIONS As explained in the previous chapters, estimates are classified as screening, study, budget or control estimates to indicate the expected accuracy of the estimate. Base, 50/50 and 90/10 estimates are terms used to specify the level of confidence to be assigned to an estimate. Allowances and contingencies are cost elements included in these estimates to arrive at certain levels of confidence. Strictly speaking these terms refer to two different methods of estimating; that is the conventional (also referred to as deterministic) and the probabilistic method. The intention of the latter is to produce a probability curve on the basis of a detailed probabilistic investigation for a conventionally derived base estimate. Such a curve also indicates the basis for the current definition of the conventional contingencies. A few years ago, probabilistic cost estimating, or cost risk analysis, began to receive increasing attention and was expected to rapidly replace conventional methods to estimating. In anticipation of this the concept of confidence level and associated terminology such as 50/50 and 90/10 estimates were introduced. A few practical but fundamental problems have hindered the advancement of the technique however, and it has not yet met the potential expected of it initially. Meanwhile terms like 50/50 and 90/10 have become household words in E&P, and provide a common understanding of the cost basis. More conventional terms such as "most likely' or 'minimum rusk" probably confusion, and are therefore best avoided. It is recognised that in the absence of reliable cost estimating probabilistic, the purpose of the definition given to confidence level indicators or the boundaries of the accuracy range is somewhat limited. It does, however, provide a basis for consistent use of estimating terminology and definitions and thus for the future validation of current practice with regard to accuracy and contingency. In order to validate currently applied contingencies and expected accuracy ranges, a comparison is required of original development plans and associated budget estimates with as built facilities and cost data for a significant number of projects. This in turn will require the collection of data on past and current projects in terms of scope and cost. The CRM contains cost reporting methods for this purpose, This data will be fed into the CEDB which will assist in determining if the correct values for accuracy and contingency are being applied. Until such time it is recommended that the cost engineering practice described in this manual be adhered to.
FIGURE 2.1 : PROJECT PHASE / IDENTIFICATION
FIGURE 2.2 : PROJECTS & ETC.
FIGURE 2.3 : PRODUCTION FACILITIES OFFSHORE
FIGURE 2.4 : STRUCTURES
Other Hardware Items / Group Combinations
SECTION A - ONSHORE PRODUCTION FACILITIES AND TERMINALS 5.5 PRODUCTION AND TERMINAL FACILITIES - ONSHORE 5.5.1 Introduction This section contains the methods and cost data to be used in preparation of Type II cost estimates for onshore production facilities and terminals. The System Groups available as building blocks for a Hardward Item in this category are shown below in the form of a System Group/Hardware Item matrix. Possible combinations of System Groups for common Hardware Items are shown as examples. Other Hardware Item/System Group combinations can be considered at the user's discretion.
For a Type II estimate many System Groups are broken down into Systems. The breakdown of Systems is given below, and guidelines for System selection are given in Section 5.5.2.2. System Group
System Separation Heating
Oil processing Dehydration Water treatment Export pumping Liquid export Metering Separation Heating Gas processing
Dehydration Dewpoint control Condensate stabilisation
Gas sweetening
Gas sweetening Power generation
Power generation & distribution Power distribution Process and personnel support Utilities Safety Atmospheric storage Storage tanks storage Control/ES D/F & G
Control/ESD/F & G
Telecommunications & telemetry
Telecommunications & telemetry
Bulks
Bulks
Civils
Civils
Jetty
Jetty
The method allows for the possibility of some of the equipment and associated bulks to be prefabricated at a yard remote from the site, then transported to the site for erection. An example is when a separator and associated piping and instrumentation are fabricated into a small module with some structural steel framing. It is then transported to site and hooked-up-to the piperack. The user is required to estimate the percentage of the total equipment weight that might be prefabricated in this 5.5.2 Method 5.5.2.1 Hardware Item Excel Spreadsheet Eform-6 Working Form Use the attached Excel spreadsheet, Eform 6, when preparing cost estimates for onshore production facilities and terminal. 5.5.2.2 System Selection Section 5.5.1 lists the System Groups and Systems within those groups which are available to the user for the Hardware Item being estimated. Some notes are provided here to aid the user in selection of Systems. Notes are provided only for those Systems where guidance is needed either for the selection of the System itself, or for the selection of a choice of processing equipment within the System. When a Project contains both production facilities and a terminal the user must exercise care in the allocation of Systems. For example a production facility and a terminal share common power generation, power distribution, process and personnel support, safety, control ESD/F & G, and telecommunications and telemetry systems. Similarly, care must be exercised when selecting System Groups for developments With both gathering and production stations. The spring philosophy of the project will dictate the requirement for multiple trains. In addition to this, should the required capacity of a system exceed the ranges given in this manual, multiple trains will be required. The following table shows national system capacity per train. Use this table to dictate the required number of trains. It should be noted that these limits are national only and in reality they will be influenced by a number of design parameter, e.g. GOR will influence separator system maximum capacity etc.
Oil Heating Oil heating is sometimes required to effect stabilisation and/or dehydration to the required export specification. Crude oil heating is often required upstream of electrostatic desalters to help break oil/water emulsions. If electrostatic dehydration is a part of oil processing then this System should be included. It is also usually required when processing waxy crude. Methods for two types of heating System are provided. There are : •
A heating medium System comprising a process heat exchanger, fired heater, expansion vessel, circulating pumps and associated bulks. Such a System should be provided for a production facility that has a number of process heat consumers.
•
A water bath type System comprising a water/glycol filled tank fitted with heat exchange tubes, fire tubes and associated bulks. This System should be provided at remote gathering or production stations where heat is required by a single process user only.
Oil Dehydration Most onshore production facilities are required to produce crude oil suitable for tanker loading, i.e. required water in oil specifications O.5%. B.S.& W and salt specification is 25 pounds per thousand barrels. Oil dehydration/desalting onshore may be effected in one of two ways: •
Dehydration using a wash tank type of system. An atmospheric storage tank with a long residence time (24 hours based on gross liquids throughput) is utilised to effect oil/water separation. This form of dehydration is used generally where land is readily available with few environmental restrictions and when the oil specific gravity is high.
•
Dehydration using a continuous wash tank type of system. An atmospheric storage tank system is utilised on a continuous basis to effect oil/water separation.
•
Dehydration based on the use of electrostatic coalescers. Depending on the salt content of the produced water and the required salt specification of he export oil, two stages of desalting may be required. This form of dehydration/desalting is used generally where land is less readily available.
Gas Separation This System is required for gas and gas/condensate developments. For developments that include 'both oil processing and gas processing the oil separation System should always be selected in favour of the gas separation System . Gas Dehydration Gas dehydration is required where it is necessary to •
Meet export gas specifications.
•
Recover condensate from the gas by refrigeration.
•
Avoid corrosion problems downstream caused by H2S or CO2 in the reservoir fluid.
•
Prior to NGL extraction to produce LPG from the gas
Dew Point Control Gas dew point control onshore is generally required for condensate recovery and to meet export gas specifications. If neither condensate recovery nor gas export is included in the development then this System is not required.
Condensate Stabilisation Condensate stabilisation is generally required Where associated gas contains sufficient recoverable condensate to justify the inclusion of this System. Condensate stabilisation would typically be required for gas/condensate developments and for oil development featuring a large amount of associated gas. Gas Sweet Gas sweetening is required for oil, gas and gas/condensate developments where the reservoir fluid contains H2S or CO2 . This System required to meet export specifications for gas. 5.5.2.3 Input Data With reference to Section 5.5.2.2 indicate on Eform 1A the selected System Groups and Systems by ticking the relevant boxes. Complete Eform-1A by entering the data required for the selected systems. 5.5.2.4 Calculated Quantities Proceed systematically through the Excel Spreadsheet Eform-6 as follows. Oil Heating Select the type of heating System required and determine the duty from Figure 5.5.4 From duty obtain equipment weight from Figure 5.5.5. Oil Dehydration Select the type of dehydration System required. if a wash tank type of System is required then determine tankage volume from Figure 5.5 6, using the net oil flowrate and record the storage volume on the equipment/bulks weight table of Form 5.5.2 (for bulks calculation) and the storage tank table. Determine the number and capacity of dehydration tanks from Figure 5.5.42. If electrostatic dehydrators are to be used then determine the equipment weight from Figure 5.5.7 using the net oil flowrate. Water Treatment From the produced water flowrate and the required effluent specification for oil in water determine the equipment weight from Figure 5.5.8. Pumping Select the export method (i.e. by rail or road or sea) Determine the loading rate using Fig. 5.12.3 and record on the Eform-6. From the required loading rate use Figure 5.12.4 to determine the loading pump power. Note the pump power on Eform-6. From tile required loading pump power use figure 5.12.5 to determine the pump equipment weight. Liquid Export Metering From the liquid product flowrate determine the metering System equipment weight from Figure 5.5.16. Gas Separation From the sum of gas export and gas injection flowrates (as appropriate) determine the gas separation System equipment weight from Figure 5.5.17. Gas Dehydration From the sum of gas export flowrate determine the weight of the gas dehydration equipment using Figure 5.5.19 sheet 1. Obtain the dehydration power from figure 5.5.19 sheet 2 and record on power summary table in Eform-6.
Dewpoint Control From the gas export and/or injection flowrate determine the weight of the dewpoint control equipment from Figure 5.5.20. sheet 1.Obtain the dehydration power from figure 5.5.20 sheet 2 and record on power summary table in Eform-6. Condensate Stabilisation From the condensate flowrate determine the condensate stabilisation equipment weight from Figure 5.5.21. Gas Sweetening From acid content of inlet gas, sweet gas specification and gas export flowrate determine the gas sweetening equipment weight from Figure 5.5.22 sheet 1. Obtain the power demand from Figure 5.5.22 sheet 2 and enter in the power summary table of Eform-6. If the development incorporate gas export compression in additon to gas lift then gas lift compression is covered in the gas export system weight. If the development excludes gas export then the gas lift equipment weight is estimated as follows. Determine the overall compression ratio from Figure 5.5.23 and record on Form 5.5.2, Sheet 5. From the compression ratio and the gas lift flowrate determine the required compression power either from Figure 5.5.24 or from Figure 5.5.25 and record this on Form 5.5.2 in the gas compression table. Record the number of trains/items in the civils table on Form 5.5.2. Gas lnjection If the development has gas injection without gas export then first determine compression requirements from the first stage separation pressure minus 4 bar to a typical intermediate pressure of 135 bara. This involves calculating the compression ratio from Figure 5.5.23 and hence the compression power from Figure 5.5.24 or Figure 5.5.25, and the equipment weight from figure 5.5.26 or Figure 5.5.27. Record the compression ratio and compression power on Form 5.5.2, sheet 5. This weight is then added to the equipment weight for compression from 135 bara to the injection pressure which is determined again by means of compression ration (Figure 5.5.23), compression power (figure 5.5.24 or Figure 5.5.25) and finally equipment weight, this time from Figure 5.5.28. Record the compression ratio and compression power on Form 5.5.2 sheet 3. Record the number of trains/iitemss in the civils table on Form 5.5.2. For a development with both gas injection and gas export the injection gas is compressed from the export gas pressure to the injection pressure. The export compression requirements must be calculated first (see below) to determine the export pressure. Then the injection equipment weight is determined by means of compression ratio (Figure 5.5.23), compression power (Figure 5.5.24 or Figure 5.5.25) and equipment weight (Figure5.5.28). Record the compression ratio and compression power on Form 5.5.2 in the gas compression table and in the power summary table (with reference to Figure 5.5.41). Record the weight in the weights table and the number of trains/items in the civils table on Form 5.5.2. If the final compression to the injection pressure utilises electric motor drivers then the required compression power (i.e. un-derated power) should be entered in the electrical consumers column of the power summary table. Gas Metering From the gas flowrate determine the metering equipment weight from Figure 5.5.34.
Liquid Metering If product is to be loaded into a tanker either via a jetty or via a pipeline and an offshore loading unit then only fiscal metering is required. In this case determine the metering equipment weight from the loading rate using figure 5.1 2.6 Power Generation Determine the power generation requirements for each system as determined by Figure 5.5.38 and enter on Eform-6 according to whether the system is electrically powered or turbine driven.. Eform-6 allows the user to enter a drive as either turbine driven or electrically driven to enable a power balance to be carried out. To allow for intermittent/standby loads and unidentified Systems, an electrical design factor is included. Where drives are turbine an allowance for parasitic loads is included. Total the electrical consumers, add the Electrical Design Factor and enter as the Required Power. Enter the values for Imported and Exported Power onto Eform-6. Calculated the Generated Power by subtracting the Imported Power and adding the Exported Power to the Required Power. If all the power is to be imported, then transfer the value for Required Power to the Imported Power. From Figure 5.5.31, determine the derating factor for gas turbines and enter on Eform-6. Derate by dividing by each of these factors and enter as the Turbine Power. Use the Turbine Power and Figure 5.5.39 to obtain the Power Generation equipment weight and enter on Eform-6. Power Distribution From the sum of the Required power and the Exported power determine the power distribution equipment weight from Figure 5.5.40 and enter on Eform-6. The cost derivations for cabling for imported and exported power are not included in the methodology. Process and Personnel Support (Utilities) The sum of system equipment weights obtained thus far give subtotal A on Eform-6. From subtotal A determine the process and personnel support System equipment weight from Figure 5.5.41 Sheet 1. From Figure 5.5.41 sheet 2, obtain the power demand and enter in power summary table of Eform-6. Atmospheric Storage Determine the required atmospheric storage capacity, the number of tanks and capacity per tank from Figure 5.5.42 and record these values on Eform-6. The storage capacity should be recorded on the equipment/bulks weight table of the Eform-6 (for bulks calculation) as well as the storage tank table. Pressurised Storage Determine the required pressurised storage capacity from Figure 5.5.42 and the pressurised storage equipment weight from Figure 5.5.43.
Civils Determine the foundation area for each System from Figure 5.5.44, and sum these to obtain foundation and paving area subtotal G. From Figure 5.5.45 determine the area for grading, the area for clearance and the equivalent area for civils bulks. These values are entered on Eform 6.
Safety If the development excluded product storage then from the total foundation area (subtotal G on Eform6) determine the safety system equipment weight from Figure 5.5.46, sheet 1. If the development includes product storage then determine the foundation area, subtotal G, less the atmospheric and pressurised storage foundation areas, and use this to determine the safety System equipment weight from Figure 5.5.46. sheet 1. In addition determine the safety System equipment weight from Figure 5.5.46, sheet 2, using the sum of the installed storage capacities for both atmospheric and pressurised storage. Use the larger of these two weights as the safety System equipment weight. Bulks weight Obtain the bulks factor for each System from Figure 5.5.47. Multiply the equipment weight by each bulk factor to obtain the bulks weights for piping, electrical, instruments and others. Sum the weights for each bulks category to obtain the total weight for piping, electrical, instruments and other. Prefabrication/Site Construction Determine the percentage of equipment to be prefabricated and enter this value on Eform-6. Apply this percentage to the equipment weight total B to determine the equipment weights for prefabrication and for site construction, respectively. Structural Steel Determine the structural steel requirements for both prefabrication and site construction from Figure 5.5.48. Jetty Determine the jetty Length using Figure 5.12.13. 5.5.2.5 Cost Estimate Procurement Cost The individual equipment and total bulks dry weights are transferred automatically to the procurement section of the Eform-6 where procurement cast rate of figure 5.5.49 have been incorporated and will be applied automatically to give the total procurement cost. The procurement costs for contrived/F & G and for telecommunications and telemetry are lump sum costs, and should be entered directly into the cost column. Construction Cost Apply the percentage of prefabricated equipment weight to the total bulks weights (totals C, D, E and F on Eform-6) to obtain the prefabrication weights for .piping, electrical, instruments and others. The prefabrication manhour rates from Figure 5.5.50, sheet 1 and the prefabrication labour rates from Figure 5.5.50, sheet have been incorporated into the Eform-6. The prefabrication costs is given by subtotal D. The sum of equipment, piping, electrical, instruments, others and steelwork prefabrication weights give the total weight for prefabrication. The manhour rate for erection of prefabricated units from Figure 5.5.50, sheet 4 and the site construction labour rate from Figure 5.5.50, sheet 2 have been incorporated in the Eform-6. Eform-6 multiplies the total weight for prefabrication by the manhour rate and by the labour rate to obtain subtotal E, the erection cost of prefabricated units.
The site fabrication weights for piping electrical, instruments and others are derived automatically by taking the appropriate percentage of totals C. D E and F on Eform-6. The manhour rates from Figure 5.5.50, sheet 4 and the construction labour rates from Figure 5.5.50, sheet 2 have been incorporated into the Eform-6 which will be used to determine the site construction cost. The erection rate for a single tank from Figure 5.5.50, sheet 5 which has been incorporated into the Eform-6, will be multiplied by the installed tank capacity and the number of tanks to obtain the cost. The costs in summed to obtain site mechanical construction cost subtotal F. The sum of prefabrication, erection and site construction costs to obtain the mechanical construction cost, subtotal G. Obtain the grading factor from Figure 5.5.50, sheet 5 and enter It on Eform-6 against 'Area for grading'. Similarly enter the clearing factor from Figure 5.5.50, sheet 5 against "Area for clearance'. The manhour rates from Figure 5.5.50, sheet 5 and the labour rates from 'Figure 5.5.50, sheet 2 have been incorporated in Eform-6. Eform-6 multiplies are by factor (if applicable), 'by manhour irate and by the labour rate to obtain cost. The sum of costs give the civils construction cost subtotal H. The total of mechanical and civils construction cost subtotals G and H give the construction cost total. Commissioning Cost The commissioning cost is a percentage of the mechanical construction cost, subtotal G. The percentage is given in Figure 5.5.51. Engineering and Design If the development incorporates oil production only then from the gas flowrate use Figure 5.5.52, sheet 1 to determine the manhours for engineering and design. If the development incorporates gas production only then from the gas flowrate use Figure 5.5.52, sheet 2 to determine the manhours for engineering and design. If the development incorporates both oil and gas production then determine the engineering and design manhours by summing the manhours obtained form both sheets 1 and 2 of Figure 5.5.52. Enter the engineering and design manhours on Eform-6 from Figure 5.5.3. The labour rates from Figure 5.5.52, sheet 3 has been incorporated in the Eform-6. Eform-6 calculates the cost from the total manhours and the labour rate. Insurance and Certification Insurance and certification is taken as a percentage of the costs for procurement, construction and commissioning. 'The percentage is given in Figure 5.5.53. The sum of costs for procurement, construction, commissioning, engineering and design, project management and insurance and certification give the total Hardware Item cost. Hardwater Item Cost Summary The Eform-6 summarises the total cost and cost by Project Function into the Project Function into the Project Cost Summary.
Construction Cost Apply the percentage of prefabricated equipment weight to the total bulks weights (totals C, D, E and F on Eform-6) to obtain the prefabrication weights for .piping, electrical, instruments and others. The prefabrication manhour rates from Figure 5.5.50, sheet 1 and the prefabrication labour rates from Figure 5.5.50, sheet have been incorporated into the Eform-6. The prefabrication costs is given by subtotal D. The sum of equipment, piping, electrical, instruments, others and steelwork prefabrication weights give the total weight for prefabrication. The manhour rate for erection of prefabricated units from Figure 5.5.50, sheet 4 and the site construction labour rate from Figure 5.5.50, sheet 2 have been incorporated in the Eform-6. Eform-6 multiplies the total weight for prefabrication by the manhour rate and by the labour rate to obtain subtotal E, the erection cost of prefabricated units. The site fabrication weights for piping electrical, instruments and others are derived automatically by taking the appropriate percentage of totals C. D E and F on Eform-6. The manhour rates from Figure 5.5.50, sheet 4 and the construction labour rates from Figure 5.5.50, sheet 2 have been incorporated into the Eform-6 which will be used to determine the site construction cost. The erection rate for a single tank from Figure 5.5.50, sheet 5 which has been incorporated into the Eform-6, will be multiplied by the installed tank capacity and the number of tanks to obtain the cost. The costs in summed to obtain site mechanical construction cost subtotal F. The sum of prefabrication, erection and site construction costs to obtain the mechanical construction cost, subtotal G. Obtain the grading factor from Figure 5.5.50, sheet 5 and enter It on Eform-6 against 'Area for grading'. Similarly enter the clearing factor from Figure 5.5.50, sheet 5 against "Area for clearance'. The manhour rates from Figure 5.5.50, sheet 5 and the labour rates from 'Figure 5.5.50, sheet 2 have been incorporated in Eform-6. Eform-6 multiplies are by factor (if applicable), 'by manhour irate and by the labour rate to obtain cost. The sum of costs give the civils construction cost subtotal H. The total of mechanical and civils construction cost subtotals G and H give the construction cost total. Commissioning Cost The commissioning cost is a percentage of the mechanical construction cost, subtotal G. The percentage is given in Figure 5.5.51. Engineering and Design If the development incorporates oil production only then from the gas flowrate use Figure 5.5.52, sheet 1 to determine the manhours for engineering and design. If the development incorporates gas production only then from the gas flowrate use Figure 5.5.52, sheet 2 to determine the manhours for engineering and design. If the development incorporates both oil and gas production then determine the engineering and design manhours by summing the manhours obtained form both sheets 1 and 2 of Figure 5.5.52. Enter the engineering and design manhours on Eform-6 from Figure 5.5.3. The labour rates from Figure 5.5.52, sheet 3 has been incorporated in the Eform-6. Eform-6 calculates the cost from the total manhours and the labour rate. Insurance and Certification Insurance and certification is taken as a percentage of the costs for procurement, construction and commissioning. 'The percentage is given in Figure 5.5.53. The sum of costs for procurement, construction, commissioning, engineering and design, project management and insurance and certification give the total Hardware Item cost. Hardwater Item Cost Summary The Eform-6 summarises the total cost and cost by Project Function into the Project Function into the Project Cost Summary.
FIGURE 5.5.2
NUMBER OF SEPARATIONS STAGES
FIGURE 5.5.3 OIL SEPARATION EQUIPMENT WEIGHT
FIGURE 5.5.4 OIL HEATING WEIGHT
FIGURE 5.5.5 HEATING EQUIPMENT WEIGHT
FIGURE 5.5.6 OIL DEHYDRATION TANKAGE VOLUME (SHEET 1)
FIGURE 5.5.6 OIL DEHYDRATION TANKEGE VOLUME (SHEET 2)
FIGURE 5.5.7 OIL DEHYDRATION EQUIPMENT WEIGHT (SHEET 1)
FIGURE 5.5.7 OIL DEHYDRATION EQUIPMENT POWER (SHEET 2)
FIGURE 5.5.8 WATER TREATMENT EQUIPMENT WEIGHT
FIGURE 5.5.9 LIQUID EXPORT PUMPING
FIGURE 5.5.10 OIL EXPORT PIPELINE SIZING
FIGURE 5.5.11 OIL EXPORT PIPELINE SIZING
FIGURE 5.5.12 CONDENSATE/LPG EXPORT PIPELINE SIZING
FIGURE 5.5.13 CONDENSATE/LPG EXPORT PIPELINE SIZING
FIGURE 5.5.14 LIQUID EXPORT PUMPING POWER
FIGURE 5.5.15 LIQUID EXPORT EQUIPMENT WEIGHT
FIGURE 5.5.16 LIQUID EXPORT EQUIPMENT WEIGHT
I
FIGURE 5.5.17 GAS SEPARATION EQUIPMENT WEIGHT
FIGURE 5.5.19 GAS DEHYDRATION EQUIPMENT WEIGHT (SHEET 1)
FIGURE 5.5.19 GAS DEHYDRATION POWER REQUIREMENT (SHEET 2)
FIGURE 5.5.20 DEWPOINT CONTROL EQUIPMENT WEIGHT (SHEET 1)
FIGURE 5.5.20 DEWPOINT CONTROL ELECTRICAL POWER REQUIREMENT (SHEET 2)
FIGURE 5.5.21 CONDENSATE STABILISATION EQUIPMENT WEIGHT
FIGURE 5.5.22 GAS SWEETENING EQUIPMENT WEIGHT (SHEET 1)
FIGURE 5.5.22 GAS SWEETENING ELECTRICAL POWER REQUIREMENT (SHEET 2)
FIGURE 5.5.23 GAS LIFTING AND INJECTION COMPRESSION RATIOS
FIGURE 5.5.24 GAS COMPRESSION POWER
FIGURE 5.5.25 GAS COMPRESSION POWER
FIGURE 5.5.26 GAS COMPRESSION EQUIPMENT WEIGHT
FIGURE 5.5.27 GAS COMPRESSION EQUIPMENT WEIGHT
FIGURE 5.5.28 GAS INJECTION COMPRESSION EQUIPMENT WEIGHT
FIGURE 5.5.31 TEMPERATURE DERATING FACTOR FOR GAS TURBINE
FIGURE 5.5.32 ALTITUDE DERATING FACTOR
FIGURE 5.5.34 GAS METERING EQUIPMENT WEIGHT
FIGURE 5.5.38 POWER GENERATION SYSTEM REQUIREMENTS
FIGURE 5.5.39 POWER GENERATION EQUIPMENT WEIGHT
FIGURE 5.5.40 POWER DISTRIBUTION EQUIPMENT WEIGHT
FIGURE 5.5.41 PROCESS AND PERSONNEL SUPPORT EQUIPMENT WEIGHT
FIGURE 5.5.42 PRODUCT STORAGE REQUIREMENT
FIGURE 5.5.43 PRESSURISED STORAGE EQUIPMENT WEIGHT
FIGURE 5.5.44 CIVILS FOUNDATION AREA (SHEET 1)
FIGURE 5.5.44 CIVILS FOUNDATION AREA (SHEET 2)
FIGURE 5.5.44 CIVILS FOUNDATION AREA (SHEET 3)
FIGURE 5.5.44 CIVILS FOUNDATION AREA (SHEET 4)
FIGURE 5.5.44 CIVILS FOUNDATION AREA (SHEET 5)
FIGURE 5.5.45 CIVILS AREAS FOR GRADING AND CLEARANCE
FIGURE 5.5.46 SAFETY EQUIPMENT WEIGHT (SHEET 1)
FIGURE 5.5.46 SAFETY EQUIPMENT WEIGHT (SHEET 2)
FIGURE 5.5.47 BULKS FACTORS
FIGURE 5.5.48 STRUCTURAL STEEL
FIGURE 5.12.3 PRODUCT LOADING RATE
FIGURE 5.12.4 PUMPING POWER
FIGURE 5.12.5 PUMPING EQUIPMENT WEIGHT
FIGURE 5.12.6 METERING EQUIPMENT WEIGHT
FIGURE 5.12.13 MARINE LOADING JETTY
FIGURE 5.5.49 PROCUREMENT RATES (SHEET 1)
FIGURE 5.5.49 PROCUREMENT RATES (SHEET 2)
FIGURE 5.5.49 PROCUREMENT RATES (SHEET 3)
FIGURE 5.5.49 PROCUREMENT RATES (SHEET 4)
FIGURE 5.5.50 CONSTRUCTION RATES (SHEET 1)
FIGURE 5.5.50 CONTRUCTION RATES (SHEET 2)
FIGURE 5.5.50 CONTRUCTION RATES (SHEET 3)
FIGURE 5.5.50 CONTRUCTION RATES (SHEET 4)
FIGURE 5.5.50 CONSTRUCTION RATES (SHEET 5)
FIGURE 5.5.51 COMMISSIONING RATES
FIGURE 5.5.52 ENGINEERING AND DESIGN AND RATES (SHEET 1)
FIGURE 5.5.52 ENGINEERING AND DESIGN AND RATES (SHEET 2)
FIGURE 5.5.52 ENGINEERING AND DESIGN AND RATES (SHEET 3)
FIGURE 5.5.53 CERTIFICATION RATES
SECTION B - OFFSHORE FACILITIES 5.6 PRODUCTION FACILITIES - OFFSHORE 5.6.1 Introduction This section contains the methods and cost data required for the preparation of Type II cost estimates for offshore topsides facilities. The System Groups available as building blocks for a Hardware Item in this Category are shown below in the form of a System Group/Hardware Item matrix. Possible combinations of System Groups for common Hardware Items are shown as examples. Other Hardware Item/System Group combinations can be considered at the user's discretion. HARDWARE ITEM / SYSTEM GROUP COMBINATIONS
For a Type II estimate many System Groups are broken down into Systems. The breakdown of Systems is given below, and guidelines for System selection are given in Section 5.6.2.2. System Group
System
Wellhead facilities
Wellheads Separation Heating
Oil processing Dehydration Water treatment Export pumping Oil export Metering Separation Heating Gas processing Dehydration Dewpoint control Gas lift
Gas lift
Gas injection
Gas injection Gas export compression
Gas export Metering Water injection
Water injection Power generation
Power gen & dist Power distribution Process and personnel support Utilities
Safety Material handling
Quarters
Quarters
Drilling facilities
Drilling facilities
Control/ESD/F & G
Control/ESD/F & G
Telecommunications & telemetry
Telecommunications & telemetry
Bulks
Bulks
Interplatform bridges
Interplatform bridges
Structural steel
Structural steel
For fixed platforms, structural steel for either an integrated deck or for modules and a module support frame (MSF) is included in this production facilities category rather than in the fixed substructure category.
The offshore production facilities category does not included acid gas removal as this is not normally carried out offshore. The method also excludes the retrofit of new equipment to, or modification of , existing facilities. New technology such as membranes multiphase pumps etc., are not included. The method will be extended to include these items in the future when proven estimating methods and data are available. 5.6.2 Method 5.6.2.1 Hardware Item Excel Working Spreadsheet The following Excel Spreadsheets will be used when preparing type II cost estimate for offshore topside facilities. •
Input Data - Eform-1 B
•
Quantities and Cost - Eform-2
•
Hardware Item Cost Summary - SUMM
Eform-2 has incorporated the material cost rates, fabrication manhours norms and cost rates and HUC and installation spread day rates. 5.6.2.2 System Group and System Selection Some notes are provided in this Section to aid the user in selection of Systems, Notes are provided only for those Systems where guidance is needed either for the selection of a choice of processing equipment within the System. When a Project contains several platforms with distinct functions the user must exercise care in the allocation of System Groups. For example a shallow water gas development may have separate, bridge linked platforms for Wellhead, production, compression and quarters, all of which share common power generation and distribution, utilities, control/ESD/F & G and telecommunications and telemetry System Groups, and care should be taken to include these only once. Similarly, the interplatform bridges should be allocated to only one Hardware Item, and not covered twice. The sparing philosophy of the project will dictate the requirement for multiple trains. In addition to this should the required capacity of a system exceed the ranges given in the manual multiple trains will be required. The following table shows national system capacities per train. Use this table to dictate the required number of trains. It should be noted that this limits are national only in reality they will be influenced by a number of design parameters e.g. GOR will influenced separator system maximum capacity etc.
Oil Separation This System is required for all oil producing facilities. If some gas processing is also required then the gas separation System should not be selected in addition to the oil separation System. Crude oil exported from offshore production facilities is generally required to meet one of two vapour pressure specifications. There are : •
Dead crude - having a TVP of approximately 0.97 bara at 25°C.
•
Live crude - having a TVP of approximately 7.0 bara at 25°C.
Generally the oil separation System required for dead crude export requires more separation stages and different operating pressures to the oil separation System required for live crude export. If the required export oil specification is not known the user needs to select the oil separation equipment based on either dead crude export or live crude export. If the crude oil is to be loaded directly into a tanker or is transferred to atmospheric storage at a terminal then dead crude processing is required. If the oil is transferred by pipeline to an onshore complex where further oil and gas processing takes place then live crude processing is adequate.
Condensate Stabilisation Condesate stabilisation is generally required where a gas field sufficient recoverable condensate to justify inclusion of the system. It may also be required for oil development featuring a large amount of associated gas.
Gas Separation This System is required for gas and gas/condensate developments. For developments that include both oil and gas processing the oil separation System should always be selected in favour of the gas separation System. Wellstream Cooling Wellstream cooling is required for gas/condensate developments. Gas Dehydration Gas dehydration is required where it is necessary to •
Meet export gas specifications
•
Recover condensate from the gas by refrigeration
•
Avoid corrosion problems caused by H2S or CO2 in the reservoir fluid.
Dewpoint Control Gas dewpoint control is generally required to meet export gas specifications for both oil and gas/condensate developments. This System is not required if gas export is excluded from the field development. Compression Gas processing does not include compression. This is covered under gas lift, gas injection and gas export. If both gas lift and gas export are required for the development the use the gas export system Group only, with the combined flowrate for the gas export compression System. If both gas injection and gas export are required for the development then both System Groups must be used, with the combined flowrate for the gas export compression System. If there is only gas injection, then use the gas export System Group for the first level of compression to an intermediate pressure, then use the gas injection System Group to achieve the final pressure. Water Injection If the produced water profile of the reservoir is such that the produced water rate is in excess of the water injection rate then the produced water may be used for water injection. If produced water is used then filtration equipment only is required prior to water injection. If seawater is used however, then both filtration and deaeration is required prior to water injection. The water injection System required for seawater is this heavier than that required for produced water. 5.6.2.3 Input Data Complete Eform-1 B by entering the data required for the selected System Groups. 5.6.2.4 Calculated Quantities Proceed systematically through Eform-2 as follows Wellheads From the number of wells and the flowing wellhead pressure indicated on Excel Spreadsheet Eform-1, determine the wellheads System weight from Figure 5.6.1.
Oil Separation Determine the number of separation stages and the separation stage pressures from Figure 5.6.2 (sheet 1 for live crude export and sheet 2 for dead crude export). From the appropriate separation pressure determine the weight of each separator from Figure 5.6.3 using the gross (oil plus water) flowrate. An allowance for the test separator weight is included in Figure 5.6.3 Should only are required, then determined the equipment weight from Figure 5.6.3, Sheet 1. If multiply trains are required, then determined the equipment weight from Figure 5.6.3, multiply by the number of trains and delete the weight of the multiple test separators. Condensate Stabilisation From the condensate flowrate determine the condensate stabilasition equipment weight from Figure 5.6.6 Oil Export Pumping Standard pumps are used in SSB/SSPC's operation. Figure 5.6.12 gives the pump operating philosophies with respect to the production and the pump size and weight. Oil Metering From oil flowrate determine metering System equipment weight using Figure 5.6.13. Gas Separation From the sum of gas export and gas injection flowrates as appropriate determine the gas separation equipment weight from Figure 5.6.14. sheet 1 or 2 according to whether there is glycol injection upstream or not. If no glycol information is available, use sheet 1. Gas Cooling From the sum of gas export and gas injection flowrates (as appropriate) detetrmine the gas cooling duty and equipment dry weight from Figures 5.6.5 sheet 1. Use sheet 2 to obtain the electrical power requirement. Gas Dehydration From the sum of gas export, gas lift and gas injection flowrates as appropriate determine the weight of the gas dehydration equipment using Figure 5.6.16. Dew Point Control From the gas export and/or injection flowrate determine the weight of gas dewpoint control equipment from Figure 5.6.17. sheet 1 and the electrical power requirement sheet 2. Gas Lift If the development incorporates gas lift but excludes gas export then from the gas lift flowrate determine the gaslift compression ratio from Figure 5.6.18 and the compression power form either Figure 5.6.19 or Figure 5.6.20. From the power requirement obtain the equipment weight either form Figure 5.6.21 or from Figure 5.6.22. Record these on Eform-2. If the development incorporates both gas lift and gas export then the gas lift equipment weights not required as it is covered by the gas export System.
Gas Injection If the development has gas injection without gas export then first determine compression requirements from the first stage separator to 135 bara . This involves calculating the compression ratio from Figure 5.6.18, hence the compression power from Figure 5.6.19 or Figure 5.6.20, and the equipment weight from Figure 5.6.21 or 5.6.22. This weight is then added to the equipment weight It the development has gas injection without gas export then first determine compression requirements from the first stage separation pressure minus 4 bar to a typical intermediate pressure of 135 bara . This involves calculating the compression ratio from Figure 5.6.18, hence the compression power from Figure 5.6.19 or Figure 5.6.20, and the equipment weight from Figure 5.6.21 or 5.6.22. This weight is then added to the equipment weight compression ratio (Figure 5.6.18), compression power (Figure 5.6.19 or Figure 5.6 20) and finally equipment weight this time from Figure 5.6.23. For a development with both gas injection export, the injection gas is compressed from the export gas pressure to the injection pressure. The export compression requirements must be calculated first (see below) to determine the export pressure. Then the injection equipment weight is determined by means of compression ratio (Figure 5.6.18), compression power (Figure 5.6.19 or Figure 5.6.20) and equipment weight (Figure 5.6.23). If the final compression to the injection pressure utilises electric motor drivers then the compression power requirement should be entered on Eform-2. Export Gas Compression If gas injection or gas lift is incorporated in the development then add the gas lift or injection flowrate to the gas export flowrate and use the combined flowrate to determine the weight of the export gas compression equipment from Figure 5.6.24 to Figure 5.6.27 using the procedure specified in Figure 5.6.24. Figure 5.6.23 sheet 2 gives standard compression equipment weight for gaslift compression using reciprocating compressors i.e. TEK-A, SJK-A and TKK-A.
Gas Metering From the export gas flowrate determine the metering System equipment weight from Figure 5.6.28. Water Injection Determine whether produced water or seawater is to be used for water injection. From water injection flowrate use Figure 5.6.29 to determine the water injection treatment equipment weight. Determine the injection pump power from Figure 5.6.30. Use the injection pump power to determine the pump weight from Figure 5.6.31 and enter the combined treatment and pump weight on Eform-2. If electric motors are used then record the pump power on Eform-2. Power Generation Determine the power generation requirements for each system as determined by Figure 5.6.32 and enter on Eform 2 according to whether the system is electrically powered or turbine driven. Eform 2 allows the user to enter a drive as either turbine driven or electrically powered or turbine driven to enable a power balance to be carried out. Where drives are turbine, an allowance for parasitic loads is included. sum the totals on Eform 2. To allow intermittent/standby loads and unidentified systems, an electrical design factor in included. Add the Electrical Design Factor and enter as the Required Power. Enter the values for Imported and Exported Power. Calculate the Generated Power by subtracting the Imported Power and adding the Exported Power to the Required Power. If all the power is to be Imported then transfer the value for Required Power to the Imported Power. From Figure 5.6.27, determine the derating factor for gas turbines and enter on Form 5.6.2. Derate by dividing by the factor and enger as the Turbine Power. Use the Turbine Power and Figure 5.6.33 to obtain the Pwer generation equipment weight. Power Distribution From the sum of the Required power and the Exported power, determine the power distribution equipment weight from Figure 5.6.34. Determine the subsea power cable length from Figure 5.6.34 and record on Form 5.6.2.
Process and Personnel Support Eform-2 calculates the System equipment weights to obtain subtotal A. From subtotal A determine the process and personnel support equipment weight from Figure 5.6.35. Safety From the total of equipment dry weight determined so far, (subtotal B), determine the safety System equipment weight from Figure 5.6.36. Material/Handling From the equipment dry weight (subtotal B) determine the material handling equipment weight from Figure 5.6.37.
Drilling Select the type of drilling facility required and determine the drilling equipment weight from Figure 5.6.38 sheet 1 to 3 of 4. If the drilling equipment is not installed permanently the equipment weight given in Figure 5,6.38 sheet 3 of 4 should only be used to determine the overall bulk structural steel weight. Bulks Weight Eform 2 has been incorporated with the bulks factors for each System from Figure 5.6.39. Eform-2 multiplies the equipment weight by each bulks factor to obtain the bulks weight for piping, electrical, instruments and others. Add the equipment weight to the bulks weights for each System to obtain the equipment and bulks weight by System. Sum the combined weights for all Systems to arrive at subtotal D. Sum the weights for each of piping, electrical, instruments and others. Quarters From the total number of beds determine the accommodation module weight from Figure 5.6.41 (for facilities an fixed substructures). Helideck weight is obtained from Figure 5.6.42, Sheet 2 of 2. Interplatform Bridges Obtain the weight for interplatform bridges from Figure 5.6.42, multiply by the number of bridges, and enter the total weight in Eform-2. Establish which platform will carry the whole bridge load and then do not include bridge weight for the other bridge sharing platform.
Structural Steel From subtotal D equipment and bulks dry weight and the TAD drilling equipment weight (if platform associated with more than 15 wellheads or non-standard topsides), determine the topsides structural steel weight using Figure 5.6.42, sheet 1 of 2. For standard topsides, deck weights are given in Figure 5.6.42, sheet 2 of 2.
Total Topsides Weight (Dry) Eform-2 calculates the total equipment, bulks, quarters, interplatform bridges and structural steel dry weight (total E on Eform-2).
Total Topsides Weight (Operating) Eform-2 applies operating factors to the equipment and bulks weights for each System together with the System weights for quarters, interplatform bridges and structural steel to give the System operating weights. The Sum of the System operating weights gives the total topsides operating weight (total F). This total is used in estimating the cost of the substructure for water depth in excess of 90 m (see Sections 5.8). Number of Major Lifts From the total topsides dry weight (total E) and the lift strategy determine the number of major lifts for both modules and integrated decks form Figure 5.6.49. Transportation and Installation Durations From the total topside weight determine the total transportation and installation durations using Figure 5.6.49. compression ratio (Figure 5.6.18), compression power (Figure 5.6.19 or Figure 5-6.20) and equipment weight, this time from Figure 5.6.23.
5.6.2.5 Cost Estimate Complete Eform-2 as follows: Procurement Cost Eform-2 automatically applies the procurement cost unit rates from Figure 5.6.46 to the individual equipment and total bulks dry weights to give the total procurement cost for each System. Fabrication Cost Eform-2 calculates the total fabrication cost by applying the fabrication norms (manhour/tonne) from Figure 5.6.47 and fabrication cost rates (M$/manhour) from Figure 5.6.48 to the derived weight. Loadout and sea-fastening cost is taken as 5% of fabrication cost. Hook-up and Commissioning Cost The hook-up and commissioning rate depends on the topsides configuration. Choose which one of the following configurations characterises the topsides under consideration. For modular configurations the rate depends on the size of the heaviest module. •
Modules up to 2000 tonnes
•
Modules up to 6000 tonnes
•
Integrated decks
•
Wellhead platforms
Determine the hook-up and commissioning manhour rates for one of the above configurations from Figure 5.6.50, sheet 1 and the labour rate form Figure 5.6.50, sheet 2. Multiply weight by rate to obtain the hook-up and commissioning cost total. For simple standard platforms i.e. 6 JTS, 9 JTS, 15 DPS, Mini-Production station and 60,000 bpd oil capacity production facilities, standard installation durations are given in Figure 5.6.50. Barge/workboat spread day rates from Figure 5.6.50 has been incorporated in Eform-2. Engineering and Design Cost From the total topsides facilities dry weight (total E on Eform-2), Eform-2 derives the engineering and design manhours from Figure 5.6.51. It calculates the Engineering and Design Cost by applying the manhour cost rates (M$ per manhour) from Figure 5.6.51 to the total Engineering and Design Manhours. Certification Cost The certification cost is taken as a percentage of the procurement, fabrication, transportation, installation, hook-up and commissioning cost. The percentage factor is given in Figure 5.6.51. Hardware Item Cost Summary Transfer the total cost and the cost by Project Function from Eform-2 to the Project Cast Summary Spreadsheet SUMM. This completes the estimate for the Hardware Item. If an additional hardware item is required within the offshore production facilities Category the user should return to the beginning of Section 5.6.2.
Figure 5.6.1 WELLHEADS EQUIPMENT WEIGHT
FIGURE 5.6.2 NUMBER OF SEPARATIONS STAGES (SHEET 1)
FIGURE 5.6.2 NUMBER OF SEPARATIONS STAGES (SHEET 2)
FIGURE 5.6.3 OIL SEPARATION EQUIPMENT WEIGHT (SHEET 1)
FIGURE 5.6.3 OIL SEPARATION EQUIPMENT WT (SHEET 2)
FIGURE 5.6.5 GAS COOLING EQUIPMENT WEIGHT (SHEET 1)
FIGURE 5.6.5 GAS COOLING ELECTRICAL POWER REQUIREMENT (SHEET 2)
FIGURE 5.6.6 CONDENSATE STABILISATION EQUIPMENT WEIGHT
FIGURE 5.6.7 OIL DEHYDRATION EQUIPMENT WEIGHT (SHEET 1)
FIGURE 5.6.7 OIL DEHYDRATION EQUIPMENT POWER (SHEET 2)
FIGURE 5.6.8 CRUDE OIL EXPORT-PIPELINE SIZING
FIGURE 5.6.9 CRUDE OIL EXPORT - PIPELINE SIZING
FIGURE 5.6.10 OIL EXPORT PUMPING
FIGURE 5.6.11 EXPORT PUMPING POWER
FIGURE 5.6.12 EXPORT PUMPING EQUIPMENT WEIGHT
FIGURE 5.6.13 OIL METERING SYSTEM
FIGURE 5.6.14 GAS SEPARATION EQUIPMENT WEIGHT (SHEET 1)
FIGURE 5.6.14 GAS SEPARATION EQUIPMENT WEIGHT (SHEET 2)
FIGURE 5.6.15 GAS HEATING SYSTEM DUTY
FIGURE 5.6.16 GAS DEHYDRATION ELECTRICAL POWER REQUIREMENT (SHEET 1)
FIGURE 5.6.16 GAS DEHYDRATION ELECTRICAL POWER REQUIREMENT (SHEET 2)
FIGURE 5.6.17 DEWPOINT CONTROL EQUIPMENT WEIGHT (SHEET 1)
FIGURE 5.6.17 DEWPOINT CONTROL ELECTRICAL POWER REQUIREMENT (SHEET 2)
FIGURE 5.6.18 GAS LIFT AND INJECTION COMPRESSION RATIOS
FIGURE 5.6.19 GAS COMPRESSION POWER
FIGURE 5.6.20 GAS COMPRESSION POWER
FIGURE 5.6.21 GAS COMPRESSION EQUIPMENT WEIGHT
FIGURE 5.6.22 GAS COMPRESSION EQUIPMENT WEIGHT
FIGURE 5.6.23 GAS INJECTION COMPRESSION EQUIPMENT WEIGHT (SHEET 1)
FIGURE 5.6.23 GASLIFT COMPRESSION EQUIPMENT WEIGHT (SHEET 2)
FIGURE 5.6.24 GAS EXPORT COMPRESSION (SHEET 1)
FIGURE 5.6.24 GAS EXPORT COMPRESSION (SHEET 2)
FIGURE 5.6.25 GAS EXPORT PIPELINE SIZING
FIGURE 5.6.26 GAS TURBINE ISO RATINGS
FIGURE 5.6.27 TEMPERATURE DERATING FACTOR FOR GAS TURBINE
FIGURE 5.6.28 GAS METERING EQUIPMENT WEIGHT
FIGURE 5.6.29 WATER INJECTION EQUIPMENT WEIGHT
FIGURE 5.6.30 WATER INJECTION PUMP POWER
FIGURE 5.6.31 WATER INJECTION PUMP EQUIPMENT WEIGHT
FIGURE 5.6.32 POWER GENERATION AND DISTRIBUTION
FIGURE 5.6.33 POWER GENERATION EQUIPMENT WEIGHT
FIGURE 5.6.34 POWER DISTRIBUTION EQUIPMENT WEIGHT
FIGURE 5.6.35 PROCESS AND PERSONNEL SUPPORT EQUIPMENT WEIGHT (SHEET 1)
FIGURE 5.6.35 PROCESS AND PERSONNEL SUPPORT (SHEET 2)
FIGURE 5.6.36 SAFETY EQUIPMENT WEIGHT
FIGURE 5.6.37 MATERIAL HANDLING EQUIPMENT WEIGHT
FIGURE 5.6.38 DRILLING FACILITIES EQUIPMENT WEIGHT (SHEET 1)
FIGURE 5.6.38 DRILLING FACILITIES EQUIPMENT WEIGHT (SHEET 2)
FIGURE 5.6.38 DRILLING FACILITIES EQUIPMENT WEIGHT (SHEET 3)
FIGURE 5.6.38 DRILLING FACILITIES EQUIPMENT WEIGHT (SHEET 4)
FIGURE 5.6.39 BULKS FACTORS
FIGURE 5.6.41 ACCOMODATION
FIGURE 5.6.42 DECK STRUCTURAL STEEL (SHEET 1)
FIGURE 5.6.42 DECK STRUCTURAL STEEL (SHEET 2)
FIGURE 5.6.43 OPERATING FACTORS
FIGURE 5.6.45
FIGURE 5.6.46 PROCUREMENT RATES (SHEET 1)
FIGURE 5.6.46 PROCUREMENT RATES (SHEET 2)
FIGURE 5.6.46 PROCUREMENT RATES (SHEET 3)
FIGURE 5.6.46 PROCUREMENT RATES (SHEET 4)
FIGURE 5.6.47 FABRICATION MANHOURS (SHEET 1)
FIGURE 5.6.47 PROJECT MANAGEMENT (SHEET 2)
FIGURE 5.6.47 FABRICATION COST RATES (SHEET 3)
FIGURE 5.6.47 PROCUREMENTS RATES (SHEET 4)
FIGURE 5.6.49 TRANSPORTATION AND INSTALLATION DURATION (SHEET 1)
FIGURE 5.6.49 TRANSPORTATION AND INSTALLATION DURATION (SHEET 2)
FIGURE 5.6.50 HOOK-UP AND COMMISSIONING DURATION (SHEET 1)
FIGURE 5.6.50 HOOK-UP AND COMMISSIONING DURATION (SHEET 2)
FIGURE 5.6.50 HOOK-UP AND COMMISSIONING DURATION (SHEET 3)
FIGURE 5.6.51 ENGINEERING AND DESIGN MANHOURS (SHEET 1)
FIGURE 5.6.51 ENGINEERING AND DESIGN MANHOURS (SHEET 2)
FIGURE 5.6.51 ENGINEERING AND DESIGN MANHOURS (SHEET 3)
FIGURE
SECTION C - OFFSHORE SUBSTRUCTURES 5.8 SUBSTRUCTURES - FIXED 5 8.1 Introduction This section contains the methods and cost data to be used in the preparation of Type II cost estimates (accuracy ± 25%) for fixed substructures. The System Groups available as building blocks for a Hardware Item in this category are listed below. There is a single Hardware item, multileg jacket, which requires all three System Groups. THE SYSTEMS GROUPS
For a Type II estimate the System Groups are normally broken down into Systems. For Type II fixed substructures the Systems are the same as the System groups. Aspects associated with fixed substructures which are not included in this method but are covered elsewhere in this manual are: Item
Reference
Risers
Section 5.11 Pipelines -Offshore
Module support frame
Section 5.6 Production Facilities - Offshore
The method covers only fixed steel piled jackets, and does not consider gravity based structures, tripod tower platforms, or jack-up type substructures. The method will be extended to include these items in the future when proven estimating methods and data are available. 5.8.2 Method 5.8.2.1 Hardware Item Excel Working Spreadsheet The following Excel Spreadsheets will be used for the preparation of Type II cost estimates for substructures. • • •
Input Data - Eform-1C Quantities and Costs - Eform-3 Hardware Cost Summary - SUMM
Eform-3 calculates conductor weight automatically and it has been incorporated with cost rates for material, fabrication, installation and HUC Spreads.
5.8.2.2 Input Data Complete Eform-1C by entering the data indicated. In the Type II estimate it is necessary to differentiate between various environmental conditions to establish the System Group weights. These environmental conditions are described in SIPM CEM Section 3.3 (attached) and the description is reproduced here for reference purposes.
5.8.3 ENVIRONMENTAL DATA The fixed and floating substructures cost estimating methods require the environmental condition of the site as input. For the purposes of the Cost Engineering Manual, the environmental conditions are defined as follows.
Since environmental criteria vary considerably, no only by region but also by country and distance from land, water - depth, etc., it is considered prudent not to provide detailed data in this Manual. However, as an aid to the user who has no other information available, an overview of the type of criteria presently available and an indication of the Environmental Conditions found in various locations is provided below. In case of any queries regarding actual design values, the reader is advised to contact in the first instance their local metocean focal point or secondly the SIPM Metocean-Services section (EPD/55). It should be noted that the reliability of the 100 year estimates of the wind and wave criteria sensitive to the quality and quantity of field data available. For initial cost estimates, it is normal practice to make as much use as possible of any data from climatically similar areas as well as any archive data available in reference publications. The resulting criteria are known as "level-1" metocean criteria. In certain well established areas where the Company has been operating for many years, (e.g. in East Malaysia, Brunei, UK) higher level criteria (e.g. "level-2") may be readily available. The level of metocean criteria given in the tables below are intended to indicate the stage of field development for which the data should be used, as follows :
Level of Metocean Criteria
Typical Applications
4 - joint probability criteria
Significant field extensions(comprehensive databases needed)
3 - windcast study criteria
Mid-term field developments
3 - field data criteria
Initial field development plans
1 - desk study criteria
New areas
Form 5.8.1 INPUT DATA
Form 5.8.2 QUANTITIES (SHEET 1)
Form 5.8.3 COSTS (SHEET 1)
FORM 5.8.3 COSTS (SHEET 2)
5.8.2.4 Calculated Quantities Proceed systematically through Eform-3 as follows Jacket Weight - Environmental Condition 3 (Typical for SSB/SSPC Jackets) The milder environmental parameters assigned to condition 3 are often associated with leg piled structures, hence the determination fo numbers of legs is relatively important in defining the weight of the structure. Determine the jacket type using the tabulation in Figure 5.8.6, sheet 2, incorporate platform type and number of conductors into the Eform-3. Determine the jacket steel weight from the appropriate curve on sheets 2 to 9 of Figure 5.8.3. The jacket curves of Fig. 5.8.3 are only good for water depth not exceeding 90m because these curves are derived based on data from existing jackets, which are normally installed in less than 90m of water, Refer to Figure 5.8.2 sheet 1 and 2 of 2 for water depth in excess of 90m.
Piles Weight Determine the piles weight/jacket weight ratio from Figure 5.8.6 sheet 2 of 2 and insert in Eform-3. The later calculate the pile weight using the correlations given in Figure 5.8.6 sheet 1 of 2. Anode's Weight Eform-3 determine the anodes weight using the factor given by Figure 5.8.7, sheet 1 of 3. Conductor Weight Enter the number of conductors in Eform-3. This spreadsheet determined the conductor weight form the Correlation in Figure 5.8.7, sheet 1 and 2 of 3 Boat Fender Determine the boat fender weights from Figure 5.8.7, sheet 3 of 3 and insert it in Eform-3. Transportation and Installation Durations Determine the transportation and installation durations using Figure 5.8.8 and insert them in Eform-3. 5.8.2.5 Cost Estimate Complete Form 5.8.3 as follows Procurement Cost Eform-3 applies procurement rates for each system and bulk from Figure 5.8.9 to the quantities derived, to obtain the procurement cost. Fabrication Cost Eform-3 applies the fabrication norms (manhours/tonne) to the quantities derived, to obtain the total fabrication manhours. Fabrication cost rate (cost/manhour) is applied to the total manhours to obtain the fabrication cost. Transportation and Installation Cost Based on the jacket tonnage, Eform-3 derives the total design manhours. It applies the design cost rate to the total design manhours to obtain the design cost. Engineering and Design Cost Based on the jacket tonnage, Eform-3 derives the total design manhours. It applies the design manhours to obtain the design cost. Pre design (Soil Investigation) Enter the lump sum cost form Figure 5.8.9 in Eform-3 if soil investigation is required (refer to Figure 5.8.12). Certification Cost The insurance and certification cost is taken as a percentage of the procurement, fabrication, transportation and installation cost and the percentage is given in Figure 5.8.1 1. Hardware Item Cost Summary Transfer .the total cost and the cost by Project Functions from Eform-3 to the project Cost Summary Spreadsheet, SUMM. This completes the estimate for the Hardware Item. If an additional Hardware Item is required within the fixed substructure category the user should return to the beginning of Section 5.8.2.
FIGURE 5.8.2 JACKET WEIGHT ENVIRONMENTAL CONDITION 3 DEEPER WATER SUBSTRUCTURES (SHEET 1)
A:
Water Depth < 90m To arrive at weight for lift/launched jackets with topside > 2500 MT in SSB/SSPC waters (environment 3), the weight obtained from the above curves are to be multiplied by the following factor: Environment 2-3 adjustment factor = 0.75
B:
Water Depth > 90 m To arrived at weights for launched jackets in SSB/SSPC waters (environment 2), the weights obtained from the above curves are to be multiplied by the following factor: Adjustment factor = 1.40 The above weights (from A & B) are to be multiplied by the conductor correction factor (if applicable) as given in Figure 5.8.4, sheet 2 of 2, in addition to the adjustment factor.
FIGURE 5.8.2 JACKET WEIGHT ENVIRONMENTAL CONDITION 3 DEEPER WATER SUBSTRUCTURES (SHEET 2)
FIGURE 5.8.3 JACKET WEIGHT ENVIRONMENTAL CONDITION 3 (SHEET 1)
The jacket steel weight for SSB/SSPC environmental condition (condition 3) can be determined from EDV/2 generated jacket curves in Figure 5.8.3, sheets 2 to 12. These curves are to be used for standard SSB/SSPC configuration in water depths less than 90 m. The equivalent mathematical expression for each curve is given in the figure. In these expressions : W
= jacket steel weights [metric tonnes].
d
= Water depth (metres).
Basis of Curve : EDV/2 weight estimating system.
FIGURE 5.8.3 JACKET WEIGHT ENVIRONMENTAL CONDITION 3 (SHEET 2)
FIGURE 5.8.3 JACKET WEIGHT ENVIRONMENTAL CONDITION 3 (SHEET 3)
FIGURE 5.8.3 JACKET WEIGHT ENVIRONMENTAL CONDITION 3 (SHEET 4)
4 Pile (JT) Drilling Jacket (MWD) If the 4 pile drilling jacket (JT) is a multi-waterdepth (WMD) design, a typical weight penalty of 15% applies as a result of using a standard inventory of materials in a non-optimized design. Hence, weights derived form Figure 5.8.3, sheet 3 of 11 need to be multiplied by 1.15 for multi-waterdepth designs. 4 and 6 Pile (DP) Drilling Platforms (Water Depth < 90 m) Jacket steel weights of 4 and 6 pile drilling platforms in water depths < 90 meter are derived by multiplying the weights obtained form Figure 5.8.3, sheet 5 of 11 (8 pile DP) with the following adjustment factors. These factors covers topside weight reduction and launch-to-lift conversion. Adjustment factor
=
0.5 (Conductor < 12)
=
0.6 (12 < Conductor < 20)
=
0.65 (Conductor > 20)
FIGURE 5.8.3 JACKET WEIGHT ENVIRONMENTAL CONDITION 3 (SHEET 5)
FIGURE 5.8.3 JACKET WEIGHT ENVIRONMENTAL CONDITION 3 (SHEET 6)
FIGURE 5.8.3 JACKET WEIGHT ENVIRONMENTAL CONDITION 3 (SHEET 7)
FIGURE 5.8.3 JACKET WEIGHT ENVIRONMENTAL CONDITION 3 (SHEET 8)
FIGURE 5.8.3 JACKET WEIGHT ENVIRONMENTAL CONDITION 3 (SHEET 9)
FIGURE 5.8.3 JACKET WEIGHT ENVIRONMENTAL CONDITION 3 (SHEET 10)
FIGURE 5.8.3 JACKET WEIGHT ENVIRONMENTAL CONDITION 3 (SHEET 11)
FIGURE 5.8.4 JACKET WEIGHT ENVIRONMENTAL CONDITION 3 DEEPER WATER SUBSTRUCTURES
FIGURE 5.8.6 PILE WEIGHT ENVIRONMENTAL CONDITION 3 (SHEET 1)
FIGURE 5.8.6 PILE/JACKET WEIGHT ENVIRONMENTAL CONDITION 3 (SHEET 2)
FIGURE 5.8.7 ANODES WEIGHT ENVIRONMENTAL CONDITION 3 (SHEET 1)
FIGURE 5.8.7 CONDUCTOR STEEL WEIGHT ENVIRONMENTAL CONDITION 3 (SHEET 2)
FIGURE 5.8.7 FENDER WEIGHT ENVIRONMENTAL CONDITION 3 (SHEET 3)
FIGURE 5.8.8 PROCUREMENT AND FABRICATION RATES (SHEET 1)
FIGURE 5.8.8 PROCUREMENT AND FABRICATION RATES (SHEET 2)
FIGURE 5.8.9 TRANSPORTATION AND INSTALLATION DURATION ENVIRONMENTAL CONDITION 3
FIGURE 5.8.10 TRANSPORTATION AND INSTALLATION RATES
FIGURE 5.8.11 ENGINEERING AND DESIGN MANHOURS ENVIRONMENTAL CONDITION 3 (SHEET 1)
FIGURE 5.8.11 ENGINEERING AND DESIGN MANHOURS ENVIRONMENTAL CONDITION 3 (SHEET 2)
FIGURE 5.8.11 ENGINEERING AND DESIGN MANHOURS ENVIRONMENTAL CONDITION 3 (SHEET 3)
FIGURE 5.8.12 PRE-DESIGN - DURATION ENVIRONMENTAL CONDITION 3 (SHEET 1)
FIGURE 5.8.12 PRE-DESIGN (SIDE INVESTIGATION) LUMP SUMP COST (SHEET 2)
SECTION D - SUBSEA PIPELINES 5.11 SUB-SEA PIPELINES 5.11.1 Introduction This section contains the methods and cost data to be used in the preparation of Type II cost estimates for offshore pipelines. The method contains data for pipelines in a variety of services, these being oil, gas, water and flowlines (oil or gas). For each pipeline a separate cost estimate should be prepared. A typical pipeline hardware element can be broken down into the following components. System Group
System
Linepipe
Linepipe Flexible pipe Special alloys Cathodic protection
Coating
External/anti-corrosion Insulation Concrete
Risers
Fixed Flexible Special alloys
Further included are pipeline crossings and tie-ins. The sub-sea pipelines method does not include rock dumping, as the requirement for, and cost impact of , this Item can only be assessed when details of the pipeline route has been established. 5.11.2 Method 5.11.2.1 Hardware Item Excel Working Spreadsheet The following Excel Spreadsheet will be used for the preparation of Subsea pipeline type II cost estimates, The forms are •
Input Data
- Eform-1
•
Quantities and Costs
- Eform-4
•
Hardware Item Cost Summary - SUMM
Eform-4 already incorporates the lay rate [day/km], cost rates for material, design and Cat I spread.
5.11.2.2 Input Data Complete Eform-1D by entering the pipeline data. The following notes are provided as a guide. •
Use of flexible pipe could be considered for short length field lines in corrosive service where either low installation cost or redeployment within the field are development parameters.
•
Special alloy materials have application where internal corrosion rates of carbon steel pipe are expected to be high unless chemical injection or fluid treatment is incorporated upstream of the Pipeline. Where such pretreatment/injection is difficult to achieve then use of duplex stainless steel or inconel clad carbon steel pipe should be considered for wet gas transportation service where the partial pressure of carbon dioxide exceeds 2 bar.
•
Cathodic protection is provided to reduce corrosion rates. The rate of corrosion dependent on the environmental conditions and also on product temperature. Offshore pipelines are generally protected cathodically by a system of sacrificial anodes.
•
External coating of pipe is generally required as an anti-corrosion barrier between the environment and the pipe. A nominal thickness of 6 mm of asphalt coating or 400 micron of fusion bonded epoxy coating is normally sufficient. Internal coating of pipe is not considered in this Type II method; for corrosive services selection of special alloy materials is recommended (see above).
•
Insulation should be considered when heat conservation is required. This will apply to oil lines where the fluid exhibits high viscosity or high pour point (e.g. high wax content) or where the downstream processing unit required temperature maintenance. Lines transporting wet gas or 2 phase mixtures should be maintained above 25 °C for pressures above 1 00 bar to prevent hydrate formation, otherwise hydrate inhibitors will be required.
•
Concrete coating may be required to provide on-bottom stability of the line, particularly for line 10" diameter and larger.
•
Tie-in refers to subsea tie-in existing pipelines only and does not encompass tie-in of pipelines to risers. This is covered in the riser System Group.
•
Fixed risers are used with a fixed substructures.
•
Flexible risers are used with floating production facilities. Flexible risers normally find application in water depths greater than 60m and for line diameters fo 2" to 16". For low pressure loading lines, diameters up to 24" are available, but these are not covered as separate items in this manual.
•
Special alloy materials are used for the riser when chosen for the pipeline.
•
For flowlines, injection lines etc., to/from wells enter the sum of all the individual line lengths.
5.11.2.3 Calculated Quantities Proceed systematically through Eform-4 as follows: Pipeline Length Enter the pipeline length in Eform-4. Pipeline Diameter Determine the pipeline diameter from one of the following figures, according to the service. Oil and gas export pipelines may have already been sized while estimating the offshore production facility. If so, enter the size directly on Eform-4.
Pipeline Service
Figure Number
Oil pipeline (to existing trunkline)
5.11.1
Sheet 1
Oil pipeline (to terminal facility)
5.11.1
Sheet 2
Gas pipeline
5.11.2
Sheet 1
Water pipeline
5.11.3
Sheet 1
Flowline (low GOR oil)
5.11.4
Sheet 1
Flowline (high GOR oil and gas; also gas injection and gas lift)
5.11.4
Sheet 2
Pipeline Weight Eform-4 calculates the linepipe steel weight based on the linepipe length and wall thickness using the procedure given in Figure 5.11.5. Pipeline Construction Eform-4 uses the appropriate pipelay rate for rigid pipelines from Figure 5.11.6 and multiply length by rate to obtain the duration. Obtain the unit durations for mob/demob, start- up/terminations and pipeline crossing from Figure 5.11.6. Enter the number of mob/demobs, start-up/terminations and pipeline crossings in Eform-4, where it will be multiplied by their respective unit durations. Eform-4 sums the durations to obtain the unfactored laybarge duration. The material factor from Figure 5.11.6 will be added, as appropriate, to obtain the total laybarge duration. Trenching The pipeline may require to be trenched if it is less than 16" diameter and in a region where there is considerable fishing activity (or where it is known that existing pipelines are trenched). If trenching is required, obtain the trenching rate from Figure 5.11.6, multiply by the pipeline length and by the same regional factor as used for construction to obtain the total trenching duration. Free Span Rectification Obtain the Cat I duration for free span rectification. Assumed one rectification required per 50 km length of pipeline. Subsea Tie-in to Existing Pipeline Eform-4 will use either DSV or Cat I duration norms, whichever is assumed, from Figure 5.11.6 and 5.11.7 respectively to calculate the tie-ins duration. There is an option to choose between DSV and Cat I. Pipe Crossing Obtain Cat I duration from Fig. 5.11.6. Assume one crossing per 50 km length of linepipe. Riser Installation and Subsea Tie-ins Duration Eform-4 calculates the installation duration by applying the installation rate [day/riser] form Figure 5.11.6 or Figure 5.11.7, whichever is assumed, to the number of risers. There is an option to choose between DSV and Cat I vessel.
5.11.2.5 Cost Estimate Complete Excel Spreadsheet Eform-4 as follows Procurement Cost The Spreadsheet calculates the procurement cost by applying the unit cost form Figure 5.11-3 to the derived quantities, i.e. line pipe tonnage, number of risers, etc. The Spreadsheet also calculates the following pre-fabrication cost by applying unit cost rates form Figure 5.11.8. Prefabrication Item
Figure 5.11.8 Sheet Number
Anti-corrosion coating
1
Concrete coating
1
Cathodic Protection
2
Insulation
3
For fixed riser, the Eform-4 applies the unit cost rates for the riser and fittings from Figure 5.11.9 to the number of risers. Eform-4 finally adds together the linepipe cost, prefabrication cost and riser cost to obtain the procurement cost total. Construction Cost The Eform-4 applies Cat I or DSV spread day rates form Figure 5.11.10 to the derived installation durations. Engineering and Design Cost Obtain the engineering and design manhours form Figure 5.11.11 and enter on Eform-4. Eform-4 applies the design cost rate to the total design manhours to obtain the design cost. Certification Cost The insurance and certification cost is taken as a percentage of the procurement, construction and commissioning cost and the percentage is given in Figure 5.1 1.1 1. Pre-design (Seismic and route Survey) Eform-4 calculates the pre-design cost based on the expression in Figure 5.11.12. Cost Summary Transfer the total cost and the cost by Project Function form Eform-4 to the Hardware Item Cost Summary Spreadsheet SUMM. This completes the estimate for the pipeline. If an additional pipeline estimate is required for offshore pipelines category the user should return to the beginning of Section 5.11.2.
FIGURE 5.11.1 OIL PIPELINE DIAMETER (SHEET 1)
FIGURE 5.11.1 OIL PIPELINE DIAMETER (SHEET 2)
FIGURE 5.11.2 GAS PIPELINE DIAMETER
FIGURE 5.11.3 WATER PIPELINE DIAMETER
FIGURE 5.11.4 FLOWLINE DIAMETER (SHEET 1)
FIGURE 5.11.4 FLOWLINE DIAMETER (SHEET 2)
FIGURE 5.11.5 PIPELINE WEIGHT (SHEET 1)
FIGURE 5.11.5 PIPELINE WEIGHT (SHEET 2)
FIGURE 5.11.6 RIGID PIPELINE INSTALLATION DURATION
FIGURE 5.11.7 RISER INSTALLATION AND PIPELINE TIE-IN DURATION
FIGURE 5.11.8 PROCUREMENT RATES (SHEET 1)
FIGURE 5.11.8 PROCUREMENT RATES (SHEET 2)
FIGURE 5.11.8 PROCUREMENT RATES (SHEET 3)
FIGURE 5.11.9 RISER PROCUREMENT RATES
FIGURE 5.11.10 INSTALLATION AND COMMISSIONING RATES (SHEET 1)
FIGURE 5.11.10 PRE-DESIGN SEISMIC AND ROUTE SURVEY (SHEET 2)
FIGURE 5.11.11 ENGINEERING, DESIGN AND SUPERVISION (SHEET 1)
FIGURE 5.11.11 ENGINEERING AND DESIGN, AND INSURANCE AND CERTIFICATION RATES (SHEET 2)
SECTION E MINOR PROJECT FUTURE
SECTION F STANDARD PROJECT LEAD TIMES
ATTACHMENT 1
EFORM 1
;
EFORM 2
EFORM 3
EFORM 4
P
SECTION H WORKED EXAMPLE
