400 Design

AbstractThis section discusses the many considerations involved in the engineering design of pipelines. It covers the design scope for the pipeline facilitynot the associated station and terminal facility (although station and terminal piping are included in pipeline codes for transportation systems). This section relates regulatory jurisdic-tion to the selection of an appropriate design code. Hydraulic calculations, line sizing, stress analysis, pipe wall thickness calculations, pipe and coating selection, and ancillary considerations are discussed in relation to the various codes and the Companys preferred practices. Pipeline crossings, appurtenances, and cathodic protection facilities are also discussed.

Contents Page

410 Regulations and Codes 400-3411 Regulatory Jurisdictions

412 Codes

420 Hydraulics 400-6421 Basic Pressure Drop Calculations

422 Special Hydraulic Conditions

423 Hydraulic Profiles

430 Line Sizing 400-13431 Elements to Determine an Economic System

432 Preliminary Pipe Selection and Line Operating Pressure

433 Hydraulic Profiles and Pump Station Locations

434 Order-of-Magnitude Estimates for Investment Costs

435 Order-of-Magnitude Estimates for Operating Costs436 Economic Analysis for Line Sizing437 Improving Cost EstimatesChevron Corporation 400-1 July 1999

438 Sizing of Short Lines

440 Line Design 400-29

400 Design Pipeline Manual441 Pipe and Coating Selection

442 Pipe Stress and Wall Thickness Calculations for Liquid Pipelines per ANSI/ASME Code B31.4

443 Pipe Stress and Wall Thickness Calculations for Gas Transmission Pipelines per ANSI/ASME Code B31.8

444 Coating Selection

445 BurialRestrained Lines and Provision for Expansion446 Seismic Considerations

447 Crossings

448 Special Considerations

450 Pipeline Appurtenances 400-51451 Line Valves452 Scraper Traps453 Electronic Inspection Pigs454 Line Pressure Control and Relief455 Slug Catchers456 Vents and Drains457 Electrical Area Classification458 Line Markers460 Corrosion Prevention Facilities 400-62461 General462 Impressed Current System for Cathodic Protection463 Galvanic Sacrificial Anodes for Cathodic Protection

464 Insulating Flanges and Joint Assemblies465 Cathodic Protection Test Stations and Line Bonding Connections470 References 400-63July 1999 400-2 Chevron Corporation

Pipeline Manual 400 Design410 Regulations and Codes

411 Regulatory Jurisdictions

United StatesRegulations governing interstate hazardous liquid and gas pipeline facilities are established and enforced on a federal level. Intrastate pipeline facilities are subject to federal authority unless the state certifies that it will assume responsibility. The state must adopt the same regulations or more stringent, compatible regulations.

The Chevron Pipe Line Company Guide to Pipeline Safety Regulations provides information on federal and state jurisdiction for hazardous liquid and natural gas pipelines. The Operations Section of Chevron Pipe Line Company should be contacted for a copy of this guide.

Regulations for hazardous liquid pipelines are covered in Title 49, Code of Federal Regulations, Part 195 (49 CFR 195), Transportation of Hazardous Liquids by Pipe-line. Section 195.2 defines a hazardous liquid as petroleum, petroleum products, or anhydrous ammonia. Section 195.1(b) excludes onshore gathering lines in rural areas and onshore production facilities and flow lines. Pending regulations are expected to include supercritical CO2 pipelines under Part 195.

For gas pipelines, 49 CFR 191, covers annual reporting and incident reporting, and 49 CFR 192 deals with minimum federal safety standards for transportation of natural gas and other gas by pipeline.

Section 910 of this manual gives further details on the applicability of the various regulations to offshore pipelines.

CanadaIn Canada, jurisdiction for pipeline design and operation is either federal or provin-cial. In general, interprovincial transmission pipelines and pipelines designated as involving national priorities are regulated by the National Energy Board and are certificated pipelines. The Company is not, as yet, involved in transmission pipeline operations in Canada and therefore is not usually concerned with the National Energy Board regulations.

Intraprovincial transmission, interfield, and gathering system pipelines are provin-cially regulated. Alberta, British Columbia and Saskatchewan have well established government departments to handle pipelines. The other provinces impose varying degrees of control. Most of the Companys Canadian operations are in Alberta, British Columbia, Manitoba and Saskatchewan.

Albertas Pipeline Act is enforced by the Energy Resources Conservation Board. The Board issues its Pipeline Regulations and the Oil and Gas Conservation Regula-tions. These regulations govern pipeline design, licensing, construction, testing, and record keeping, and exercise influence over routing, measurement, and environ-mental issues. For information on other provinces, contact Chevron Canada Resources Limited in Calgary, Alberta.Chevron Corporation 400-3 July 1999

400 Design Pipeline ManualOther LocationsLegal requirements for pipeline design and operation in other geographical loca-tions must be determined individually. If regulations do not exist or are less restric-tive than U.S. regulations, the pipeline facilities should be designed to the applicable ANSI/ASME code.

412 Codes

ANSI/ASME Code B31.4ANSI/ASME Code B31.4, Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum Gas, Anhydrous Ammonia, and Alcohols is incorporated by reference in 49 CFR 195. It is also a sound basis, although not legally required, for cross-country water and water slurry pipelines, allowing their future conversion to oil or other hazardous liquid service. A copy of Code B31.4 may be found in this manual under Industry Codes and Practices.

Code B31.4 establishes requirements for safe design, construction, inspection, testing and maintenance of pipeline systems transporting liquids such as crude oil, condensate, natural gasoline, natural gas liquids, liquified petroleum gas, liquid alcohol, liquid anhydrous ammonia, and liquid petroleum products. The Company has used this code for Gilsonite and phosphate slurry pipelines. Figure 400.1.1 in Code B31.4 (1986 Addenda) shows the range of facilities covered by the code. Among these are pump stations, tank farms, terminals, pressure reducing stations and metering stations.

Code B31.4 does not apply to auxiliary station piping such as water, air, steam, lubricating oil, gas and fuel; piping at or below 15 psig, piping with metal tempera-tures above 250F or below -20F; or field production facilities and pipelines.

ANSI/ASME Code B31.8Incorporated by reference in 49 CFR 192 for natural and other gas, ANSI/ASME Code B31.8, Gas Transmission and Distribution Piping Systems, applies to field gathering, transmission and distribution pipelines for natural gas. It covers the design, fabrication, installation, inspection, testing, and safety aspects of gas trans-mission and distribution system operation and maintenance. Figure I8 in Appendix I of Code B31.8 shows the range of facilities covered by the Code, including gas compressor stations, gas metering and regulation stations, and closed-pipe gas storage equipment. A copy of Code B31.8 may be found in this manual under Industry Codes and Practices.

Code B31.8 does not apply to piping with metal temperatures above 450F or below -20F, vent piping operating at substantially atmospheric pressures, wellhead assem-blies, or control valves and flow lines between wellhead and trap or separator.

Canadian Standard CAN3-Z183Canadian Standard CAN3-Z183, Oil Pipeline Systems, is incorporated by reference into the National Energy Board Act of Canada and the pipeline regulations of all July 1999 400-4 Chevron Corporation

Pipeline Manual 400 DesignCanadian provinces. It covers the design, material selection, fabrication, installa-tion, inspection, testing, operation, maintenance, and repair of onshore pipelines carrying crude oil, multiphase liquids, condensate, liquid petroleum products, natural gas liquids, liquified petroleum gas, and oilfield water.

CAN3-Z183 applies to pump stations, tank farms, pressure reducing stations, and metering stations. It does not apply to auxiliary station piping such as water, air, steam, gas, fuel and lubricating oil, piping with metal temperatures above 120C or below -45C, production equipment or oil wells. A copy of the Standard may be obtained from Chevron Canada Resources or the Canadian Standards Association.

Canadian Standard CAN/CSA-Z184Canadian Standard CAN/CSA-Z184, Gas Pipeline Systems, is incorporated by reference into the National Energy Board Act of Canada and the pipeline regula-tions of all Canadian provinces. It covers the design, fabrication, installation, inspection, testing and safety aspects of operation and maintenance of gas pipeline system, including gathering lines, transmission lines, compressor stations, metering and regulating stations, distribution lines, service lines, offshore pipelines and closed-pipe gas storage equipment. It does not apply to liquified natural gas pipe-lines, auxiliary station piping such as water and air, metal temperatures above 230C or below -70C, production equipment, or gas wells. A copy may be obtained from Chevron Canada Resources or the Canadian Standards Association.

Producing Field Flow and Gathering LinesThe ANSI/ASME Codes do not clearly define the extent of producing field flow and gathering lines, and CFR regulations do not cover oil and gas gathering lines in rural areas. Therefore, the Company has not always been consistent in applying the codes when designing pipelines between producing facilities and pipeline transportation systems. Where practices have not already been established, it is suggested that designs for field liquid pipelines follow Code B31.4, and, for gas pipelines, Code B31.8.

49 CFR 192 and 195 apply within the limits of any incorporated or unincorporated city, town, village, or other designated residential or commercial area. They require compliance with ANSI/ASME B31.4 and B31.8.

49 CFR 195.2 defines a liquid gathering line as a pipeline sized NPS 8 or smaller from a production facility. 49 CFR 195.1(b)(6) excludes transportation through onshore production facilities (including flow lines). 49 CFR 192.3 defines a gas gathering line as a pipeline that transports gas from a current production facility to a transmission line. Where a line handles liquid-gas two-phase flow, the more strin-gent requirements of each code should be applied, and special consideration should be given to the effects of slug flow along the system.

Producing Field FacilitiesFor on-plot production facilities such as wellhead piping, separators, traps, tank batteries and gas gathering compressors, the Company uses ANSI/ASME Code B31.3, Chemical Plant and Petroleum Refinery Piping (see the Piping Manual).Chevron Corporation 400-5 July 1999

400 Design Pipeline ManualPipeline Stations and TerminalsDesign and construction of piping at pump stations, compressor stations, and termi-nals should comply with Code B31.4 or B31.8, as appropriate. Former Chevron practice was to design piping for these facilities to the more conservative Code B31.3. It is entirely a local decision whether to continue this practice.

For descriptions of piping components, and guidelines for mechanical design, layout and construction for piping at stations and terminals, refer to the Piping Manual, which covers Code B31.3 piping for hydrocarbon services, and utility and auxiliary piping involved in station and terminal facilities. Terminal facilities within a refinery are designed to Code B31.3, unless they are confined to a separate and defined pipeline area adjacent to refinery facilities.

420 HydraulicsPressures required to move design flows through a pipeline system are calculated from the fluid properties, pipe diameter and line length. Pertinent fluid properties for basic hydraulic calculations are viscosity and specific gravity at the tempera-tures and pressures of the fluid in the line.

These calculations indicate a range of feasible pipe diameters and tentative spacing of pump or compressor stations along the line. Section 430 should be reviewed as a guide for initially selecting pipe diameters for a particular system. As design becomes final, hydraulic calculations are refined to determine conditions for over-pressure control during line shut-off and surges.

The design flow, or line throughput rate, is established by the operating organiza-tion, which should define as closely as possible the expected maximum and minimum rates, and forecast future yearly throughput requirements. This informa-tion is critical in determining the most economic line size. Once line size is deter-mined and pipe is selected, hydraulic calculations can be made to determine flows for variables in operating conditions, future expansion of system capacity by the addition of pump or compressor stations, and line capacity if the system is converted to different service.

421 Basic Pressure Drop CalculationsThe Fluid Flow Manual is a primary source of pressure drop data for most oils as well as water and natural gas. Refer to the following sections of it for guidance in making pressure-drop calculations:

400 Friction Pressure Drop 800 Surge Pressure 900 Pipeline Flow 1000 Fluid Properties

General hydraulics theory and development of formulas is covered in the Fluid Flow Manual, Section 400. The Fluid Flow Manual is recommended for both liquid July 1999 400-6 Chevron Corporation

Pipeline Manual 400 Designand gas transmission lines, although pipeline handbooks and general hydraulics texts may also be used.

Oil and Water Lines at Ambient TemperaturesHydraulic calculations are straightforward for pipelines with a single fluid stock and little variation in viscosity throughout the line at any given time, as is the case with many of the Companys field and transportation pipelines. Section 422 covers other situations; Section 932 discusses subsea hydraulics.

Except for certain crude oils and heavy fuel oils whose viscosity is sensitive to temperature, the annual mean ambient air temperature may be used as the average flow temperature for buried lines. If available, ground temperature data is preferred. If seasonal variations are great, calculations should be made for winter and summer temperature averages. The effect of seasonal variations must be carefully evaluated.

For crude oils it is necessary to know the pour point of the oilthe temperature at which viscosity of a cooling oil abruptly increasesto determine if special measures are needed to move the oil when ambient ground temperatures approach or fall below the pour point. An oil with pour point at or above the ambient tempera-ture requires special treatment, such as a pour point, depressant additive, dilution with lighter stock, or a heated pipeline system. If ground temperatures are close to the pour point reliable data on ground temperature is critical. A program to collect this data in the initial phase of the project is recommended.Design Throughput. The design throughput of an oil pipeline is its average annual pumping rate in barrels per calendar day (BPCD). Capacity requirements given in barrels per day (BPD) should be construed as meaning BPCD. The design flow that a system must be capable of attaining to compensate for lost capacity from shut-downs and reduced flow conditions is given in barrels per operating day (BPOD). The ratio of BPCD to BPOD is the load factor (see Equation 400-1). A well-oper-ated pipeline handling a single stock at any one time can be expected to have a load factor of at least 0.95. This figure should be used to arrive at the design BPOD rate from a given BPCD throughput unless special circumstances dictate a lower factor.

BPOD = BPCD/Load Factor= 1.05 BPCD for the usual oil pipeline system

(Eq. 400-1)In some areas BOPD and BWPD are common notations for barrels of oil and barrels of water per day. Do not confuse these with BPOD and BPCD.

Preliminary Hydraulic Calculations. To set the inside diameter of a line for preliminary hydraulic calculations for cross-country oil pipelines, a pipe wall thick-ness of 0.250 inch can generally be used for lines up through NPS 30, 0.375 inch from NPS 30 to NPS 42, and 0.500 inch over NPS 42. Heavier wall thicknesses should be used for offshore pipelines (see Section 930).For liquid pipelines, pressure drop data from Section 400 of the Fluid Flow Manual can be developed and plotted as in Figure 400-1. Because pressure drop data will be interrelated with ground elevations, allowable line pipe, and valve pressures and Chevron Corporation 400-7 July 1999

400 Design Pipeline Manualpump discharge heads, pressures are expressed in feet of the fluid in the line as well as pounds per square inch (psi). Formulas to convert to pressure units of pounds per square inch, or vice versa, are:

Ppsi =headft 0.4328 specific gravityheadft = (2.311 Ppsi)/specific gravity

(Eq. 400-2)

Gas Transmission LinesFlow calculations for gas transmission lines are covered in Section 400 of the Fluid Flow Manual.

Detailed design development for a high-pressure (ANSI 600# or higher) gas trans-mission system includes hydraulic analysis of transient pressure and temperature conditions in the pipeline, and of two-phase flow resulting from pressuring of the line from a high-pressure source and depressuring, whether intentional or resulting from line rupture. Low temperatures caused by autorefrigeration during depres-suring can significantly affect fluid properties (and influence material selection). Effects of normal flow variation that stem from the delay in system response at other locations must also be considered.

Unless seasonal ambient ground temperature variations are extreme, the annual mean ambient air temperature adequately approximates the average flow tempera-ture for long buried lines. For short lines, gas temperatures of the compressor station or wells may be considerably higher than ambient, and should be taken into account.

The design annual throughput of gas lines is usually expressed in standard cubic feet per calendar day (SCFCD). Seasonal throughput for gas lines can vary significantly because of demand fluctuations and should be considered in setting the load factor

Fig. 400-1 Pressure Drop and Head LossJuly 1999 400-8 Chevron Corporation

Pipeline Manual 400 Designthat determines design flow rate, expressed in standard cubic feet per operating day (SCFOD).

422 Special Hydraulic ConditionsSituations involving special hydraulic calculations follow, along with sources of guidance for appropriate calculation methods. Specialists in the Materials and Engi-neering Analysis Division of the Engineering Technology Department can provide further guidance and reference to similar systems. Situations covered in this section include multistock lines, hot oil pipelines, non-Newtonian fluids, mixed phase flow, and supercritical fluids.

Multistock FlowCalculations for crude lines handling a range of specific gravities and for product pipelines must allow for (1) the presence in the line of stocks with differing phys-ical properties and (2) deliveries from the line at several points. The latter consider-ably reduces the volume of products going through to the terminal compared to throughput at the initial station. To avoid excessive mixing of products, the line flow should be within the turbulent region. At low flow rates, batching pigs can be used to minimize interface mixing.

Slurry pipelines usually operate within a narrow range of flow rateswith the minimum rate adequate to keep solids in suspension and the maximum low enough to avoid excessive abrasion and erosion. A wide range of net solid throughput is achieved by frequent batching of slurry and water, or by displacing slurry with water at intervals, then shutting down and restarting. To establish maximum and minimum pressure drops, calculations should be made for slurry alone and water alone.

Hot Oil PipelinesIf it has a high pour point or very high viscosity, a waxy crude oil or heavy oil must be heated before it enters the pipeline, and must not be allowed to cool below a minimum temperature before it reaches the terminal or an intermediate reheating station. Maximum oil temperature entering the line is usually limited by allowable temperature for the pipe coating (see Section 340 of this manual and the Coatings Manual. See Section 900 of the Fluid Flow Manual for calculations for friction heating and external heat transfer coefficients. Heat traced pipeline electrical heating systems attached to the pipeline, or insulation on the pipe may be warranted to maintain oil temperatures above the allowable minimum. Design guides for these systems are not covered in this manual, though some Company installations are listed in Section 370.

A planned shutdown procedure for hot oil pipelines, either for maintenance or emer-gency shutdown, usually involves displacing the line with a lighter stock. Hydraulic calculations for a multistock situation should therefore be made for both displacing and restarting.Chevron Corporation 400-9 July 1999

400 Design Pipeline ManualNon-Newtonian FluidsNon-Newtonian fluids should be handled on a case-by-case basis. Their viscosity characteristics change significantly with flow rate and as a result of the fluids hydraulic and temperature history. Pretreatment, heating, addition of pour depres-sants or flow improvers, and a combination of strategies have been used success-fully to facilitate pumping of these oils through pipelines. Line restart after shutdown is likely to require special investigation and study.

Refer to the Materials and Engineering Analysis Division of the Engineering Tech-nology Department for assistance on any pipeline system involving an oil or slurry having non-Newtonian properties. See also Section 1000 of the Fluid Flow Manual for a discussion of non-Newtonian fluids.

Mixed Phase FlowField production systems often have mixed phase flow in lines handling oil, water, and gas. For two-phase flow (liquid-gas) refer to the Fluid Flow Manual, Section 400, or use the PIPEFLOW-2 computer program (see the Fluid Flow Manual, Section 1100 and Appendix E). These facilities usually have a slug-catcher at the line terminus.

Supercritical FluidsA supercritical fluid is a gas compressed to a pressure greater than the saturation pressure, at temperatures greater than the critical temperature. The critical temperature is the temperature at which the gas cannot be liquified at any pressure. Supercritical fluids behave like compressible liquids, or gases as dense as a liquid.

Pipeline transport of carbon dioxide as a supercritical fluid has become more common in recent years. The viscosity of supercritical CO2 is very low, but the density varies significantly with pressure, temperature and amounts of other gases present as impurities. Moreover, changes in pressure result in temperature changes. Hydraulic calculations can be made with the PIPEFLOW-2 computer program (see the Fluid Flow Manual, Section 1100 and Appendix E) incorporating density data for pressures and temperatures along the line. Calculations for supercritical hydro-carbons can be handled in a similar manner.

423 Hydraulic ProfilesWhen a pipeline route has been determined, elevation data and hydraulic pressure drop gradient data can be plotted in a hydraulic profile. The hydraulic profile can be used to establish line size and pump station spacing, and to show allowable pipe pressures (see Sections 433 and 434). Data on pipe grade and wall thickness, pipe coating, and locations of block valves, scraper trap manifolds, and major river cross-ings can conveniently be incorporated on the same plot.

Hydraulic profiles plot the following data:

Ground elevations along the route, including at least the significant high and low points, and pump station and branch line locationsJuly 1999 400-10 Chevron Corporation

Pipeline Manual 400 Design The approximate terminal pressure (in feet of head) at the end of the line (or section of line) required, for example, for the fluid to pass through terminal manifolding and piping and into tankage at design flow

Hydraulic gradient data, in feet of pressure drop per mile at design flow rate (or maximum and minimum rates), for one or several pipe sizes

A basic plot of this data is indicated in Figure 400-2.

A hydraulic control point is a high-elevation point that governs the inlet head for its section of line. Often, hydraulic control points are encountered, and the hydraulic gradient must clear the ground elevation control point. Two situations may result as indicated in Figure 400-3:

A slack line should be avoided because it results in erratic correlation of the line input and output meters, which makes leak detection by metering instrumentation impossible. For products pipelines the volume of interface mixture between succes-sive products is uncontrollable in a slack-line, and product mixing is severe in downhill sections downstream from the control point. In rare instances slack-line operation may be considered so that back-pressure control is not required.

The actual pressure in the pipeline at any point along the route equals the difference between the hydraulic gradient and the ground elevation (see Figure 400-4).With multistock flow where two or more stocks having appreciably different viscosities and specific gravities are in the same line, higher pressures may develop

(a) The hydraulic gradient is continued to the end of the line, resulting in a residual pressure at the end of the line, for which back pressure control must be provided.

(b) Without back pressure control, a length of line will flow only partially full, in what is called a cascade or slack-line condition.

Fig. 400-2 Hydraulic Gradients Fig. 400-3 Hydraulic Profile: Backpressure ControlChevron Corporation 400-11 July 1999

400 Design Pipeline Manualat intermediate points along the line than if there were only one stock. In Figure 400-5 the trailing stock has the lower viscosity and, therefore, a less steep hydraulic gradient than the leading stock. With pump station and terminal discharge pressures P1 and P2 fixed, the locus of pressures at the interface between the stocks is arched upwards. The pressure H in feet of stock A at a distance of x miles along the line of total length L is given by:

(Eq. 400-3)where:

R =

r =

H2 = 2.311 P2 / (sp. gr. stock A) in feet of stock A (not stock B)

Note that while the two hydraulic gradients vary, since the throughput will not be constant for fixed station and terminal pressures, their ratio is essentially constant.

If there are injection or take off points along the line, so that flow in the main line is increased or decreased, the different hydraulic gradients need to be plotted in succession along the line for the changed flow rates.

H R E2 H2 Ex+( )E1 H1 R E2 H2+( ) R 1( )Ex+ +

1 r xL x------------+---------------------------------------------------------------------------------------+=

Fig. 400-4 Hydraulic Profile: Line Pressure Fig. 400-5 Hydraulic Profile: Multistock Flow

(specific gravity stock B)specific gravity stock A( )--------------------------------------------------------------

hydraulic gradient stock A( )hydraulic gradient stock B( )--------------------------------------------------------------------July 1999 400-12 Chevron Corporation

Pipeline Manual 400 Design430 Line SizingAlthough different regulations and codes are involved, the following method for sizing long cross-country pipelines for liquid hydrocarbons is also applicable to natural gas transmission lines. It also applies to other pipelines which involve special conditions. There will, however, be significant differences in the facilities and economic factors.

This section is concerned with the pipeline itself and pumping facilities, not field gathering systems, storage at either end, or terminals. It helps determine the most economic system for a particular set of conditions; based on order-of-magnitude cost estimates for the installed systems and for variable operating expenses.

Preliminary design and cost estimating are not two separate and independent proce-dures; they are closely interrelated and must progress concurrently. Unlike process plant piping, a pipeline system is extremely flexible and a given throughput can be transported between two given points over a variety of routes and through different sizes of pipes.

The range of possible pipelines is almost limitless, even within the restricted scope of this guide. Consequently, the parameters, guidelines, design criteria and esti-mating criteria presented here are not applicable in all cases. However, they provide a starting point for a logical and realistic approach to the problem.

Note Short Lines. Relatively short lines such as field flow lines and gathering lines normally do not require the line sizing procedure covered in the major part of Section 430. Refer to Section 438 below for guidelines on sizing short lines.

431 Elements to Determine an Economic SystemTo size a pipeline, one must identify the significant elements necessary to evaluate and compare alternatives, estimate costs, and perform an economic analysis of the alternatives. Cost differentials for alternative line sizes must include the following elements:

Annual throughput rates for the period selected as the analysis basis Pipeline and pumping facilities with capacity to handle the throughput rates Pumping energy to transport the stock at throughput rates

Alternative forecast throughputs often consist of a most-likely case, and less likely cases at lower and higher rates. Sensitivity analyses should be made to determine the effects of the other casesor a composite casegiven the line size selected by the most-likely case analysis.

Sections 432 and 433 show how to establish the pipeline and pumping facilities for the alternative line sizes, while Section 434 covers order-of-magnitude cost esti-mates for the facilities. Section 435 discusses order-of-magnitude estimates for operating cost (for pumping energy). (Data presentation and calculations for multiple alternative designs and conditions can be greatly facilitated by using a computer spread sheet such as Lotus 1-2-3.)Chevron Corporation 400-13 July 1999

400 Design Pipeline ManualSection 436 discusses economic analysis for line sizing. Sensitivity analyses may be in order if the estimating basis for items such as construction costs and pumping energy costs is uncertain.

In some situations, other elements may affect economic evaluation of alternatives, such as:

Line routing

Heated-line facilities, heating method, initial line temperature, pipe insulation, and heating energy

Sensitivity analysis may be appropriate if alternative routes involve uncertainties in comparative construction costs or costs for permitting, right-of-way acquisition and damages, or if heated-line systems involve uncertainties in line heat losses and heating energy cost.

432 Preliminary Pipe Selection and Line Operating Pressure

Approximating Line SizeAn initial approximation for pipe size for liquid hydrocarbon pipelines can be made using the curves in Figure 400-6. These curves were not derived by a comprehen-sive study, but represent judgment based on Company and others experience over a period of years. Estimates should be made for at least three alternative pipe sizes.

Fig. 400-6 Design Flow vs. Nominal Pipe SizeJuly 1999 400-14 Chevron Corporation

Pipeline Manual 400 DesignPipe Wall ThicknessA preliminary determination of pipe wall thickness(es) is necessary since the cost of pipe is based on tonnage, a function of diameter and wall thickness. A more comprehensive discussion of pipe stress and wall thickness calculations is given in Section 440.

The basic pipe hoop stress formula relating internal pressure, pipe wall thickness, pipe diameter and stress value, as given in Section 404.1.2 of Code B31.4 for liquid lines, is:

(Eq. 400-4)where:

t = pressure design wall thickness, in.

Pi = internal design gage pressure, psig

D = outside diameter, in.

S = allowable stress value, psi

Code B31.4, Section 402.3.1, establishes the allowable stress value S; Code B31.4, Table 402.3.1(a), tabulates allowable stress values for pipe of various specifica-tions, manufacturing methods and grades. As a preliminary design basis for line sizing, API Specification 5L Grade X60 pipe is suggested, for which S = 0.72 x 60,000 = 43,200 psi. For oil lines, which normally do not require any corrosion allowance, the nominal wall thickness tn equals the pressure design wall thickness t. The hoop stress formula then becomes:

(Eq. 400-5)Pipe wall thicknesses commonly manufactured are given in API SPEC 5L, Section 6, Table 6.2.

Minimum Handling ThicknessPipe wall must be thick enough to resist damage and maintain roundness during construction handling and welding. Other factors affect pipe wall thickness, but for line sizing suggested minimum thicknesses are as follows:

tPiD2S---------=

NPS Min. Wall, in.4 12 0.188

14 24 0.219

tnPiD

86,400-----------------=

or Pi 86,400tnD----=Chevron Corporation 400-15 July 1999

400 Design Pipeline ManualOther Pressure Level FactorsMechanical limits on pump discharge pressures and ratings for valves and flanges also influence maximum design pressure levels for the pipeline. Maximum oper-ating pressure (MOP) ratings for carbon steel pipeline valves conforming to API Spec 6D and valves and flanges conforming to ANSI Standards B16.34 and B16.5 often determine maximum pressure for pipeline design. Although valves and flanges do not usually comprise a significant portion of the system cost, going to the next higher rating to provide for only a slight increase in line pressures would not be incrementally economic.

Section 402.2.1 of Code B31.4 states that pressure ratings shall conform to ratings at 100F in the material standards. Accordingly, MOPs for valves and flanges are as follows:

433 Hydraulic Profiles and Pump Station LocationsTo plot hydraulic profiles for the feasible alternatives pump discharge pressures, allowable pressures for pipe wall thicknesses, and pressure ratings for valves and flanges must be converted to feet of fluid (headft = 2.311 x Ppsi/specific gravity).Developing reasonable hydraulic profiles may require several trials, but by using parallel rules gradients can be drawn rapidly and adjustments made to develop alter-native layouts. The principal characteristics of a reasonable layout are as follows:

Discharge pressures at pump stations are nearly balanced. Allow about 50 psi above the bubble point for the suction to each station

Hydraulic gradients pass close to control points, minimizing the pressure differ-ential needed for back pressure control

Gradients for expansion steps in capacity should be drawn to demonstrate the need for future intermediate pump stations to provide increased throughput. The corresponding throughputs should be shown

26 30 0.25030 36 0.28136 40 0.31242 48 0.375

Class Valves API 6DMOP, psi

Flanges ANSI B16.34ANSI B16.5 MOP, psi

300 720 740600 1440 1480900 2160 2220

1500 3600 3705

NPS Min. Wall, in.July 1999 400-16 Chevron Corporation

Pipeline Manual 400 DesignWhere back pressure control will cause high pressures in the pipeline beyond the control point, perhaps necessitating heavier wall pipe, two remedies are available:

Install one or more pressure reducing stations to dissipate the pressure and bring the gradient closer to the ground elevation

Reduce the pipe diameter to steepen the gradient

The second alternative may seem to be an economical solution, but is not suggested for preliminary estimates. The smaller diameter is likely to be a bottleneck in capacity expansion of the pipeline. However, it should be considered in a final design stage. A scraper trap station will be needed at the point of size change so that different size inspection pigs can be run. A power-recovery turbine should also be considered as an alternative to wasting power through a control valve.

Figure 400-7 shows gradients for a reasonable line size, with station locations, for:

An initial design throughput requiring an intermediate pump station (otherwise pump discharge head at the initial pump station would be excessive) and a pres-sure-reducing station to reduce line pressures upstream of the terminal.

Future system expansion by addition of a pump station, resulting in a new gradient and throughput rate. Pump discharge head at the intermediate pump station is higher, but now matches the initial station discharge head. Although the pressure-reducing station is not needed at the future maximum throughput, pressure-control facilities will still be needed there and at the terminal to prevent overpressuring the line at low flow rates in the lower-elevation section and in the terminal piping.

Figure 400-7 also indicates the effect on gradients of a reduced size pipe as an alter-native to the pressure-reducing station. Figure 400-8 shows gradients for a design throughput for three alternative line sizes, and corresponding station facilities.

Pipe allowable pressures, determined by calculations described in Section 432 and converted to head in feet of fluid, should also be shown on the hydraulic gradient diagram, as indicated on Figure 400-9. The dashed line indicating the calculated pipe allowable pressure for a particular wall thickness parallels the ground profile. In Figure 400-9, for the section of the pipeline between the initial pump station and the intermediate pump station, pipe with wall thickness a is needed for a distance downstream of the initial pump station, but at higher elevations, this allowable pres-sure rating is greater than required. Therefore, in the following section, thinner wall pipe (b and c) is satisfactory. If the line were to be blocked while pumps were running, the gradient at no flow would be horizontal, indicated as pump shut-off. Pipe wall thickness should be selected so that pipe allowable pressures are equal to or greater than line pressures under pump shut-off conditions. In Figure 400-9, only wall thickness e fails to meet this criterion. In this example, wall thickness e represents a considerable savings in weight and dollars compared to the wall thick-ness required for the shutoff condition against intermediate station pumps.

In many cases, wall thicknesses of older pipelines were telescoped; that is, pipe wall thickness for successive sections of line were only adequate for line pressures at flow conditions, not for a blocked line situation. At a time when the higher Chevron Corporation 400-17 July 1999

400 Design Pipeline Manualstrength grades of pipe were not available, appreciable savings could be realized by telescoping. Telescoping is also done by using lower grades of pipe. However tele-scoping introduces the hazard of overpressuring the line under pump shutoff condi-tions and often limits system expansion by adding intermediate pump stations. Telescoping should generally be avoided.

Pumping horsepower requirements for the various alternatives can now be calcu-lated (Equation 400-6). For preliminary estimates a pump efficiency of 70% can be used for centrifugal pumps in pipeline service. For reciprocating pumps, use 90%.

(Eq. 400-6)

Fig. 400-7 Hydraulic Profile: Initial and Future BPOD

bhpQbpod Hft SG

136,000 PE----------------------------------------=

Qgpm Ppsi1714 PE----------------------------=July 1999 400-18 Chevron Corporation

Pipeline Manual 400 Designwhere:bhp = pump brake horsepower

Qgpm = flow rate, gpmQbpod = flow rate, BPOD

H = pump discharge head, ft

SG = specific gravity

P = pump discharge pressure, psi

PE = pump efficiency

Other features can be indicated on the hydraulic profile, such as pipe coatings, major river crossings, line valves, scraper trap manifolds, cased crossings, and areas with special construction problems.

434 Order-of-Magnitude Estimates for Investment CostsFor line sizing, order-of-magnitude investment cost estimates are necessary for the overall systems, alternative line sizes and, possibly, alternative routes. Cost esti-mating data are not included in this manual, but sources of cost information are suggested). Besides Company sources, cost data is periodically published in the Oil

Fig. 400-8 Hydraulic Profile: Alternative Line SizesChevron Corporation 400-19 July 1999

400 Design Pipeline Manualand Gas Journal and other trade magazines. Costs that are functions of pipe size, number of pump stations and installed pumping horsepower are more important than costs that are essentially independent of line size. Cost analysis may also be required for selection of route alternatives, involving costs that are functions of line length, terrain, permitting and right-of-way problems, line access, construction damages, etc.

Line sizing must be known to make project cost estimates, and is therefore done in conjunction with cost estimates for feasibility studies and appropriation requests.

Fig. 400-9 Hydraulic Profile: Nominal Wall ThicknessJuly 1999 400-20 Chevron Corporation

Pipeline Manual 400 DesignLine sizing estimates should focus on the elements of cost that constitute the bulk of the investment cost differentials for the alternatives under consideration. Usually the pipeline itself represents 75% to 85% of the investment, and pump stations, termi-nals, etc., account for the balance. Consequently, a substantial error in estimating the cost of pump stations will have a minor effect on the overall estimate.

The two major elements in the cost of a pipeline are the cost of the pipe and the cost of construction. The cost of the pipe can generally be determined easily and quickly; therefore, the major portion of the time available should be directed toward devel-oping a construction cost.

Pipe CostThe cost of the pipe generally represents 25% to 50% of the total line cost, and the use of a reliable cost will go a long way toward assuring a realistic total estimate. For mill runs purchasing can usually obtain informal quotes from steel mills, based on total tonnage required, within a week. The price can be FOB mill or FOB desti-nation. In the former case, freight charges from mill to destination must be obtained. European and Japanese sources should be included, particularly for foreign projects. Experience has shown that market fluctuations make it risky to use pipe costs from previous jobs and escalate them by an index.In calculating the tonnage of steel required, allow for heavier wall pipe for river and highway crossings. Also allow for waste and for the difference between the hori-zontal length of the line and its actual slope length. Even for lines laid through mountainous terrain, an allowance of 1% to 2% is usually adequate. For short producing field lines, both allowances combined (wastage and slope length) are about 5%.

CoatingsAlthough final coating selection involves a thorough study of alternatives and design conditions, order-of-magnitude coating costs for line sizing can usually be based on the following:

For normal soils, preferably extruded plastic with fusion bonded epoxy (FBE) primer, plant-applied fusion-bonded epoxy or extruded polyethylene

For hot lines, plant-applied extruded polyethylene up to 150F, fusion bonded epoxy up to 200F, or extruded plastic with FBE primer to 230F

For wet or corrosive soil conditions, plant-applied extruded polyethylene, or extruded plastic with FBE primer, or fusion-bonded epoxy

Reference should be made to Section 340 of this manual and to Section 920 of the Coatings Manual for full descriptions of these coatings.

Purchasing can usually obtain informal quotes from coating material suppliers or plant applicators within a few days. When the coating is plant-applied the applica-tion cost as well as the material cost is included. The cost of unloading the bare pipe from the delivery cars and reloading the coated pipe onto rail cars or stringing trucks and the cost for shipping coated pipe to the job should be included.Chevron Corporation 400-21 July 1999

400 Design Pipeline ManualWhere circumstances favor coating applied over the ditch, the labor cost of applica-tion is part of the construction contract. When estimating the material cost allow-ances should be included for waste (15% to 20%) and for shipping costs.

Miscellaneous MaterialsBlock valve installations, scraper traps, cathodic protection equipment, line markers, casing pipe and other items of material may be required. It is generally accurate enough to estimate all these items together as a percentage of pipe cost. The figure should be at least 5%; for short lines or lines with an unusual number of appurte-nances the figure can be as high as 10%.

Taxes and DutiesApplicable sales or use taxes must be determined and included as a part of the mate-rial cost. In addition, foreign projects generally entail added costs for import duties, permits and custom clearances. This can be a very significant item.

Pipeline ConstructionA realistic estimate of the construction cost requires judgment in evaluating such factors as terrain, weather, availability of labor and competent welders, access, and remoteness from living and service facilities. In preparing an order-of-magnitude estimate it is not possible to evaluate these individually, but their composite effect on costs must be appraised.

The basic construction cost covers clearing and grading, stringing pipe, ditching, welding, application of coating as required for the particular coating system, lowering, backfilling, cleanup and testing. It is generally estimated on the basis of dollars per linear foot. Unit construction costs for many existing pipelines are avail-able from various sources, such as Company project cost statements and magazines such as the Oil and Gas Journal which publish data on pipeline projects.Methods for estimating basic construction cost include the following:

Review available data to find a similar size line crossing terrain similar to the area in question. Use judgment to make adjustments for the particular condi-tions

When time is available, consult with several pipeline contractors and obtain informal estimates. Their figures should be realistic, particularly if they have actual construction experience in the same geographical area

Develop a daily cost for the labor and equipment needed for a pipeline spread. An estimate is then required of the rate of construction progress over the route to determine the total length of the construction period. The daily spread cost multiplied by the days to construct represents the construction cost. The daily spread cost must include items such as contractors overhead and profit. On foreign jobs there may be an additional lump sum to cover mobilization

A special situation occurs if the pipeline is located in city or suburban streets. The contractor will be required to limit his daily operations to a short distance. He may not be permitted to leave any ditch open overnight. Delays are likely on account of July 1999 400-22 Chevron Corporation

Pipeline Manual 400 Designunanticipated underground interferences. He will therefore use a city spread that is much smaller in terms of the amount of equipment and number of men than the normal pipeline spread. Construction progress will be measured in terms of 500 to 1500 feet per day as compared to 5,000 to 10,000 feet per day for open country terrain. Also, the removal and replacement of paving will be a significant cost item.

Installation costs for major river crossings, line valves and scraper traps, casing, cathodic protection stations, and pipeline markers are generally estimated on a lump sum per unit basis. Cost data for these items is available from past Company jobs and the published data mentioned previously. By far the largest items are river crossings, which require special equipment and involvement with government agen-cies. If possible, contractors should be consulted in developing the lump sum cost for a major river crossing.

Pipeline Technical ServicesPipeline technical services include the following:

Project management Design engineering and drafting

Services for purchasing, inspection and expediting, governmental and public relations, etc.

Outside specialist technical services for environmental surveys; geophysical, geotechnical, hydrographic, hydrological and meteorological surveys; radio-graphic inspection; etc.

Route and land surveys, including aerial photography

Field supervision and inspection, including travel and living expenses

For order-of-magnitude estimates it suffices to lump all these technical services together and estimate their total cost as a percentage of total pipeline material and construction costs. The percentage will generally be 5% to 20% depending on the size and complexity of the pipeline. Experience on past Company jobs should be used as a guide in determining the percentage to use.

Permitting, Right-of-Way and Land AcquisitionPermits and rights-of-way are needed for the pipeline, and land must be acquired for stations and similar facilities. These costs are usually very difficult to estimate, and all available sources should be consulted past projects, published data, and, above all, Company land specialists and local operating organizations. Charges and expenses for agents and personnel involved in developing land information and acquiring rights-of-way and land are included in acquisition costs. For order-of-magnitude estimates, permitting and right-of-way acquisition costs are usually esti-mated in dollars per mile, and land for station and similar facilities in dollars per acre.Chevron Corporation 400-23 July 1999

400 Design Pipeline ManualConstruction Damages and RestorationConstruction damages pertain to the present use of the land, and the extent to which construction will damage crops or developments. Although route restoration, such as revegetation, is considered as a pipeline construction cost, the extent and type of restoration is usually determined by the special conditions of the permits and rights-of-way. Costs for construction damages and restoration are usually estimated in dollars per mile for the specific sections of line affected.

Pump StationsFor the preliminary estimate, four major decisions must be made regarding pump stations:

Type of pump. Although centrifugal pumps are the usual choice, reciprocating pumps may be indicated for high viscosity stock because of the centrifugal pumps low efficiency in this service. The Pump Manual provides criteria for choosing a pump and the Mechanical and Electrical Systems Division of the Engineering Technology Department can give advice

Type of driver. Electric motors are the usual choice unless electric power is unavailable or some other fuel, such as natural gas, is available at a signifi-cantly lower cost. Diesel engines can be modified to burn crude oil but this generally requires a substantial investment in equipment to filter and condition the crude oil. Turbines are used in remote areas where electric power is unavail-able because they require fewer auxiliary facilities, have lower maintenance requirements, and are adaptable to remote control

Type of operation. Remote operation of some or all intermediate pump stations should be considered. This is common practice in the United States, where labor costs are high. It is also desirable wherever nearby housing and associ-ated facilities are unavailable

Amount of standby capacity. The initial design of a line usually must consider standby capacity to assure the desired line operating factor. Standby capacity is less necessary in subsequent expansions as the consequences of the loss of a pump or even a station become less severe. The total installed horsepower is the basis for estimating investment cost

The investment cost of pump stations can be estimated by breaking the facility into components, as follows:

Fixed cost. This covers items that are largely independent of the amount of horsepower to be installed. These are land, site development, buildings, living quarters and maintenance facilities. These can be estimated as a lump sum applicable to each station

Variable cost. The remaining station facilities, such as pumps and drivers, manifolding, instrumentation, and power supply are related to the size of the station. These can be estimated on the basis of dollars per installed horsepower. This figure will also vary with the type of pump and driver. Diesel stations cost July 1999 400-24 Chevron Corporation

Pipeline Manual 400 Designmore than electric stations; reciprocating pump stations cost more than centrif-ugal pump stations

Technical services. The fixed cost plus the product of variable cost times installed horsepower equals the total station cost. These unit costs must include an allowance for the technical services required to design and construct the station, generally 10% to 25% of the total station cost

Other System FacilitiesPipeline system facility costs not required for line sizing include the following:

Supervisory control and data acquisition (SCADA) facilities and associated metering, instrumentation, and control facilities

Communications

Station tankage

Cathodic Protection

Contingency, EscalationContingencies must be provided for, including costs which have been overlooked and factors contributing to cost that have not been realistically evaluated. The percentage allowed for contingencies depends on the time available to prepare the estimate and the confidence in the figures developed. The minimum contingency should be 10%, although 15% is normally used and a higher figure may be appro-priate.

If the pipeline is an unusually large project, requiring two or three years to design and construct, an allowance for future escalation should be included. If no escala-tion is included, this should be clearly stated in the estimate.

435 Order-of-Magnitude Estimates for Operating CostsThe operating cost component most important for comparing alternatives in line sizing is the electric power or fuel required for pumping. Reduction in total pumping horsepower and, possibly, the number of stations, form the basis for justi-fying a larger line.

The cost of electric power is based on a rate schedule for demand and energy charges. Where a schedule is not available, an equivalent must be developed, on as sound a basis as possible, in conjunction with resources of the operations organiza-tion. Where the drivers use the same gas or oil being transported in the line, the cost is based on the value of the gas or oil at the point of consumption. The objective is to develop a cost for pumping power per horsepower per year, or per kilowatt hour per year.

Other operating costs, significant for comprehensive economic analysis but not for line sizing analysis, include the following:

Direct labor for station operationChevron Corporation 400-25 July 1999

400 Design Pipeline Manual Pipeline maintenance supplies, labor, and equipment Pump station and terminal maintenance supplies, labor, and equipment Property taxes Management and administration Services, such as communications

436 Economic Analysis for Line SizingThe objective of an economic analysis for line sizing is to establish the comparative attractiveness of different line sizes. Usually the system with the smallest feasible line size requires the smallest investment. The first alternative that should be analyzed is the system with the next larger line size, which costs more to build but less to operate for a given throughput. Where Company-owned stock is used to fill the line initially, the value of the line fill should be added to the estimated system investment.

The analysis requires calculation of the incremental cost of building the larger line and the incremental savings realized in operating it over the forecast life of the pipe-line. Operating costs may vary over time for both the base and alternate cases if the throughput varies (e.g., for an oil field with increasing, then declining production rates), or if power costs change (due to energy costs, inflation, etc.). If an increase in throughput requires adding pump stations or looping the line, the additional invest-ment costs must be included at the time these facilities are required. Cost elements which are the same for both cases (the incremental cost is zero) can be ignored for this comparative analysis.

An economic analysis computer program such as CASHFLO (sponsored by Corpo-rate Planning & Analytical) can calculate a rate of return (ROR) and payout (in years) for the incremental cost of the larger line based on the annual savings in oper-ating (pumping) costs. CASHFLO also incorporates the effects of depreciation and taxes on the annual cash flow. If the ROR on the increment meets or exceeds current standards for this type of investment, then the larger line size is economic. This analysis can be repeated for successive line sizes until the ROR no longer justifies the incremental investment.

437 Improving Cost EstimatesThis section recommends additional design and estimating work useful in upgrading order-of-magnitude estimates and making designs final. See also the design devel-opment guidelines contained in other sections of this manual.

Route and ProfileThe route and profile should be reviewed in detail. Detailed maps should be obtained, if available. Taking a reconnaissance trip over the route is important. The group making this trip should include someone familiar with right-of-way acquisi-tion, and environmental permitting, a Company engineer or contractor representa-tive familiar with construction problems, and the Company project engineer. They may suggest desirable route changes and will obtain first-hand knowledge useful in July 1999 400-26 Chevron Corporation

Pipeline Manual 400 Designestimating permitting, right-of-way acquisition, and construction costs more realisti-cally.

During the trip information should also be gathered on pipe storage and handling areas, construction camp sites, weather, labor availability, local regulations, import requirements, availability of services and supplies, etc. Although some of these items are not important on domestic projects, they are critical cost factors on foreign projects.Finally, the route should be analyzed from the viewpoint of construction progress. What rate of pipe laying can be expected? Which sections are the most difficult? Will construction be limited to a certain time of the year? What are the river condi-tions that will dictate design and construction of crossings? How much preparation work is needed? Must access roads be constructed? Are there environmental and ecological considerations that will affect construction progress and timing?

HydraulicsThe fluid characteristics and volumes used in the preliminary design should be reviewed and confirmed. The viscosity and pour point of a crude oil must be accurate; if there is any doubt, samples should be obtained and a pumpability study performed. Care should be taken to assure that the sample obtained is truly repre-sentative. The volumes to be transported, particularly the forecast of future require-ments, should be reviewed and confirmed. A forecast of future throughputs is essential.

Pipe and CoatingBids should be obtained for the pipe. These may be formal or informal, but should be based on specific requirements. At the same time, such items as freight and duties must be considered in detail. A proposed selection of the type of coating must be made, and applicable costs developed. Finally, a detailed list of other material requirements should be made and priced as accurately as possible.

Pipeline ConstructionImproving the estimate for pipeline construction should have the highest priority. Making a reconnaissance trip is particularly important, providing the engineer with a first-hand appreciation of the various conditions that will determine the construc-tion cost.

Preferably, one or more contractors should be asked to inspect the route and submit informal figures on construction costs, but it is best if the engineer conducts the inspection trip separately with each contractor. Contractors are generally willing to provide this service because it gives them an early look at a potential project. Varia-tions in the figures submitted by different contractors may reflect different evalua-tions of construction difficulties, or a difference in their interest in doing the job (or in their need for work). It is difficult but necessary to assess the effect of the overall construction market on bids.

The engineer should make an independent estimate of construction costs after he has seen the terrain and talked to contractors about the equipment and labor force Chevron Corporation 400-27 July 1999

400 Design Pipeline Manualthey would use. Construction elements such as river crossings, block valves, scraper traps, and cathodic protection facilities, should be re-estimated in light of any infor-mation that has been developed. The estimating methods and sources of cost data are the same ones discussed in Section 435. The daily spread method described there is particularly useful.

Technical ServicesTo develop a detailed estimate for each technical service element it is first neces-sary to prepare a schedule and a Company manpower forecast for the design and construction phases of the project.The construction period is fixed by the availability of pipe and the completion date. This dictates the number of spreads required for the job, which, in turn, affects the number of Company personnel assigned to the field for supervision and inspection.

Engineering and drafting. In estimating the cost of engineering and drafting for design, include the time already spent on preliminary estimates and feasibility studies.

Purchasing and expediting. The percentages of material costs to be used in calcu-lating purchasing, inspection and expediting burdens should be defined.

Specialists. A schedule and contracting plan for outside specialists should be made, and the anticipated scope of work for each defined. Reference to previous projects, informal discussions with technical service contractors, and consultation with Company organizations involved in environmental affairs and technical investiga-tions are recommended.

Pump Stations, SCADA, Communications, Etc.A piping and instrument diagram (P&ID) and plot plan should be prepared for each pump station. With these, a detailed estimate can be made in the same way as for process plants. Material and equipment is priced out and the construction cost is estimated as a percentage of each material category. Project cost statements on past projects will provide guidance on typical percentages. Technical services should be estimated as described above.

Permitting, Right-of-Way and Land AcquisitionAfter the route reconnaissance trip, a schedule and scope for permitting, right-of-way and land acquisition should be developed, and detailed advice on costs solic-ited from local Company Land Department people. It is usually difficult to develop an accurate estimate until the acquisition of right-of-way is well along. Be conserva-tive: common sense is likely to produce a figure that is too low, because land-owners often do not use common sense in granting rights of way. Costs for preparation and processing of an Environmental Impact Report (EIR) should also be estimated.July 1999 400-28 Chevron Corporation

Pipeline Manual 400 Design438 Sizing of Short LinesAs explained at the beginning of Section 430, the preceding sections apply to long-distance cross-country oil pipelines. Sizing of short lines (say, under 10 miles) such as field flow and gathering lines is normally much simpler for the following reasons:

Route selection is straightforward.

The terrain usually does not have large elevation differences.

Throughput forecasts are probably better defined.

Only one stock at a time is in the line.

No intermediate pump stations are required.

Cost elements are not as complex and are limited to differentials for pipe and coating, pipeline construction, pump station installed horsepower, and oper-ating power costs. All other costs are not significantly affected by pipe size or pumping requirements.

On short lines attention must still be given to:

Fluid properties, particularly if the temperature entering the line is higher than ambient, as from a production wellhead or gas compressor, and the fluid is cooled in the pipeline. See the Fluid Flow Manual, Section 900.

Hydraulic calculations and hydraulic profiles for alternative line sizes and corresponding pumping requirements. Note that pumping may not be required if adequate initial pressure is available. See the Fluid Flow Manual, Section 400.

Economic analysis involving pipeline and pump station costs, and operating power costs using criteria suitable for local conditions.

440 Line Design

441 Pipe and Coating SelectionSection 430 establishes line size based on a preliminary choice of pipe grade and coating, and wall thickness. Further studies are needed to make final selection of pipe and coating for the length of the pipeline. Selection must meet Code B31.4 or B31.8 requirements, and will be influenced by economics and timely availability of materials.

See Sections 310 and 630 regarding pipe and welding. Generally, economics will dictate use of the higher grades of line pipe, with resultant thinner wall and lower tonnage; the effect of incremental cost per ton for the higher grades is small compared to reduced tonnage of pipe. Also, consideration must be given to providing sufficient wall thickness to resist mechanical damage and structural flexing in handling during construction. If Grade X70 and higher pipe is considered Chevron Corporation 400-29 July 1999

400 Design Pipeline Manual(or for sour service Grade X60 and higher) consultation with the Materials and Engineering Analysis Division of the Engineering Technology Department is suggested.

442 Pipe Stress and Wall Thickness Calculations for Liquid Pipelines per ANSI/ASME Code B31.4

The following sections of Code B31.4 Chapter II (Design) are particularly impor-tant for pipeline design:

Part 1, Conditions and Criteria

Section 401, Design Conditions Section 402, Design Criteria

Part 2, Pressure Design of Piping Components

Section 403, Criteria for Pressure Design of Piping Components Section 404, Pressure Design of Components

Allowable Pipe StressesSection 402.3.1(a) of Code B31.4 establishes the allowable stress value S for new pipe as:

S = 0.72 E SMYS(Eq. 400-7)

where:0.72 = Design factor based on nominal wall thickness tn. In setting this

design factor, the code committee gave due consideration to and made allowance for the underthickness tolerance and maximum allowable depth of imperfections provided for in the specifica-tions approved by Code B31.4

E = Weld joint factor per Section 402.4.3 and Table 402.4.3 of Code B31.4. For pipe normally considered for new lines, E = 1.00

SMYS = Specified minimum yield strength, psi

Although mill tests for particular runs of pipe may indicate actual minimum yield strength values higher than the Specified Minimum Yield Strength (SMYS), in no case where Code B31.4 refers to SMYS shall a higher value be used in establishing the allowable stress value; (Section 402.3.1(g) of Code B31.4).Table 402.3.1(a) of Code B31.4 tabulates allowable stress values for pipe of various specifications, manufacturing methods, and grades, based on the above, for use with piping systems within the scope of Code B31.4.

Sections 402.3.1(b),(c), and (d) of Code B31.4 cover allowable stresses for used (reclaimed) pipe, pipe of unknown origin, and cold-worked pipe that has subse-quently been heated to 600F or higher. Section 402.3.1(e) limits allowable stress July 1999 400-30 Chevron Corporation

Pipeline Manual 400 Designvalues in shear and bearing. Section 402.3.1(f) limits tensile and compressive stress values for pipe and other steel materials when used in structural supports and restraints.

Section 402.3.2 of Code B31.4 covers allowable stress values due to sustained loads and thermal expansion for the following stresses:

Internal pressure stresses. The calculated stresses due to internal pressure shall not exceed the applicable allowable stress value S determined by 402.3.1 (a), (c), or (d) except as permitted by other subparagraphs of 402.3.

External pressure stresses. Stresses due to external pressure shall be consid-ered safe when the wall thickness of the piping components meets the require-ments of 403 and 404.

Allowable expansion stresses (as for heated oil lines). The allowable stress values for the equivalent tensile stress in 419.6.4(b) for restrained lines shall not exceed 90% SMYS of the of the pipe. The allowable stress range, SA, in 419.6.4(c) for unrestrained lines shall not exceed 72% of SMYS of the pipe.

Additive longitudinal stresses. The sum of the longitudinal stresses due to pressure, weight, and other sustained external loadings (see 419.6.4(c)) shall not exceed 75% of the allowable stress value specified for SA under allowable expansion stresses.

Additive circumferential stresses. The sum of the circumferential stresses from both internal design pressure and external load in pipe installed without casing under railroads and highways [see Code Section 434.13.4(c)] shall not exceed the applicable allowable stress value S determined by Code Section 402.3.1(a), (b), (c), or (d).

Section 402.3.3 of Code B31.4 covers limits of calculated stresses due to occa-sional loads in operation and test conditions.

Wall Thickness CalculationsSection 404.1.2 of Code B31.4 gives the basic pipe hoop stress formula relating internal pressure, pipe wall thickness, pipe diameter and stress value:

(Eq. 400-8)where:

t = pressure design wall thickness, in.

Pi = internal design gage pressure, psi

tPiD2S---------=

or

Pi2StD--------=Chevron Corporation 400-31 July 1999

400 Design Pipeline ManualD = nominal outside diameter, in.

S = allowable stress value, psi, (per Section 402.3.1(a) of Code B31.4)

Per Section 404.1.1 of Code B31.4 the nominal wall thickness tn of straight sections of steel line pipe shall be equal to or greater than the sum of the pressure design wall thickness, and allowances for threading and grooving, corrosion, and prudent protective measures:

tn t + A(Eq. 400-9)

where A = sum of allowances for:

Threading and grooving (per Section 402.4.2 of Code B31.4) (zero for welded line)

Corrosion (per Section 402.4.1 of Code B31.4) (zero if the line is protected against internal and external corrosion per Chapter VIII of Code B31.4). For stocks where corrosion (or slurry erosion) is expected, a corrosion allowance must be provided, and consultation with the Materials and Engineering Anal-ysis Division of the Engineering Technology Department is recommended

Increase in wall thickness as a reasonable protective measure (under Section 402.1 of Code B31.4) to prevent damage from unusual external conditions at river crossings, offshore and inland coastal water areas, bridges, areas of heavy traffic, long self-supported spans, and unstable ground, or from vibration, the weight of special attachments, or abnormal thermal conditions

The nominal wall thickness shall not be less than the minimum required by prudence to resist damage and maintain roundness during handling and welding. The appropriate minimum should be evaluated for the particular installation condi-tions. As a rough guide, the following is suggested:

0.188 inch wall for sizes up to and including NPS 12 0.219 inch wall for NPS 14 through 24 A maximum D/tn ratio of 120 for pipe over NPS 24

These represent minimums for reasonable cross-country laying conditions. Consid-eration must also be given to buckling of double-jointed lengths of pipe and to fatigue stresses if extensive cyclical loading is possible during transport from the mill to the job site. The latter problem is discussed in API Recommended Practices RP 5L1, Railroad Transportation of Line Pipe; RP 5L5, Marine Transportation of Line Pipe; and RP 5L6, Transportation of Line Pipe on Inland Waterways.

Canadian Standard CAN3-Z183, Oil Pipeline SystemsCanadian Standard CAN3-Z183 is similar to ANSI/ASME B31.4. The engineer must consult CAN3-Z183 to ensure compliance with it. In Alberta there is a lower allowable stress factor for sour service.July 1999 400-32 Chevron Corporation

Pipeline Manual 400 Design443 Pipe Stress and Wall Thickness Calculations for Gas Transmission Pipelines per ANSI/ASME Code B31.8

The organization and some aspects of the design procedure in Code B31.8 differ from Code B31.4. See especially Code B31.8 Chapter IV, Design, Installation, and Testing, Sections 840 and 841.

Population Density Index and Location ClassificationCode B31.8 relates calculations for allowable design pressures to damage resulting from the failure of a gas pipeline, and classifies locations by population density. For each mile of the pipeline, Section 840.2(a) of Code B31.8 defines a zone one quarter-mile wide (centered on the pipeline) and one mile long. Within each zone buildings intended for human occupancy are counted, with each separate dwelling unit in a multiple-dwelling-unit building counted as a separate building. Each zone is classified by the number of buildings it contains, as follows:

Class 1. 10 or fewer buildings; for example, wasteland, deserts, mountains, grazing land, farmland, sparsely populated areas, and offshore

Class 2. More than 10 but less than 46 buildings; for example, fringe areas around cities and towns, industrial areas, and ranch or country estates

Class 3. 46 or more buildings (except where a Class 4 location prevails); for example, suburban housing developments, shopping centers, residential areas, industrial areas, and other populated areas not meeting Class 4

Class 4. Areas where multistory buildings are prevalent, traffic is heavy, and where there may be numerous other utilities underground. Multistory is defined as four or more floors above ground, including the first or ground floor

A Class 2 or 3 location that consists of a cluster of buildings may be terminated one-eighth mile from the nearest building in the cluster. Section 192.5(f) of 49 CFR 192 further provides that Class 4 locations end one-eighth mile from the nearest building with four or more stories.

Section 840.3 of Code B31.8 advances additional criteria that take into account the possible consequences of failure near a concentration of people, such as in a church, school, multiple dwelling unit, hospital or organized recreational area. In estab-lishing location classes consideration must also be given to the possibility of future developments.

Steel Pipe Design FormulaSection 841.11 of B31.8 gives the hoop stress formula (Equation 400-10) relating internal design pressure, pipe wall thickness, pipe diameter, and factors applied to the specified minimum yield strength (SMYS) to establish a pipe stress value.Chevron Corporation 400-33 July 1999

400 Design Pipeline Manual(Eq. 400-10)where:

P = design pressure, psig

D = nominal outside diameter, in.

t = nominal wall thickness, in.

S = specified minimum yield strength (SMYS), psi, stipulated in the Specifications to the manufacturer

F = construction type design factor per Code B31.8 Table 841.1A, ranging from 0.72 to 0.40, for four construction types, deter-mined from Tables 841.15A, .15B, and .15C, and Sections 841.122 and 841.123. In setting the values for F, due consider-ation has been given and allowance has been made for the various underthickness tolerances provided for in the specifications approved by Code B31.8

E = longitudinal joint factor per Code B31.8 Table 841.1B. For pipe normally considered for new lines, E=1.0

T = temperature derating factor per Code B31.8 Table 841.1C. For temperatures of 250For less, T=1.0

Although mill tests for particular runs of pipe may indicate actual minimum yield strength values higher than the SMYS, in no case where Code B31.8 refers to SMYS shall a higher value be used in establishing the allowable stress value (see Section 841.121(f) of Code B31.8).Code B31.8 Section 841.121(d) warns that the minimum thickness, t, required for pressure containment by Equation 400-10 may not be adequate to withstand trans-porting and handling during construction, the weight of water during testing, and soil loading and other secondary loads during operation, or to meet welding require-ments. Table 841.121(d) gives least nominal wall thickness for all sizes through NPS 64, but Company practice is more conservative. Code B31.8 Section 816 requires pipe with a D/t ratio of 70 or more to be loaded in accordance with API RP 5L1 for rail transport, API RP 5L5 for marine, or API RP 5L6 for inland waterway. If it is impossible to establish that transporting has been done in accordance with the appropriate recommended practice, special hydrostatic testing must be done.

Code B31.8 makes no specific reference to internal corrosion allowance, but Section 863 in Chapter VI, Corrosion Control, discusses internal corrosion control in general.

Code B31.8 Section 841.121(b) limits the design pressure P for pipe not furnished to specifications listed in the Code or for which the SMYS was not determined in

P 2StD-------- F E T =

t PD2S F E T ------------------------------=July 1999 400-34 Chevron Corporation

Pipeline Manual 400 Designaccordance with Section 811.253 of the Code. Section 841.121(e) covers allowable stress for cold-worked pipe that has subsequently been heated to 900F for any period of time or over 600F for more than one hour.

Section 841.13 of the Code B31.8 covers protection of pipelines from hazards such as washouts, floods, unstable soil, landslides, installation in areas normally under-water or subject to flooding, submarine crossings, spans, and trestle and bridge crossings.

Canadian Standard CAN/CSA-Z184, Gas Pipeline SystemsThe provisions of Canadian Standard CAN/CSA-Z184 are similar to those of ANSI/ASME Code B31.8. The engineer must consult CAN/CSA-Z184 to ensure compliance with it. In Alberta there is a lower allowable stress factor for sour gas service.

444 Coating SelectionSee the Coatings Manual and Section 340 of this manual for coating selection. Different coatings may be required to suit different terrain and soil conditions along the line. There are often a number of acceptable coatings, and the type and applica-tion method will depend primarily on the following:

Ground corrosivity and effectiveness of cathodic protection Line temperature Cost of coating

In selecting coatings, attention should be given to factors such as:

Data obtained from a field soils resistivity survey made early in the design phase of the project

Level of ground water table throughout the year

For cohesive clay soil, data on pipe-to-soil friction

In rock excavations, damage to the coating caused by the pipe hitting the trench walls while being lowered, and by rocks in the backfill

In tropical locations, termite attack

Potential damage to plant-applied coating in transit to job site For plant-applied coating:

Cost of plant application, and incremental shipping and handling costs Incremental field handling costs, and cost of repairs in the field Cost of field joint materials and application Availability, feasibility, and cost of setting up and operating a modular

coating plant near the job site For over-the-ditch coating:Chevron Corporation 400-35 July 1999

400 Design Pipeline Manual Cost of coating materials, and shipping and storage costs Construction costs for coating, including pipe cleaning Capability of a construction contractor to apply the coating satisfactorily Standard over-the-ditch coatings are far less reliable than plant-applied

systems, particularly at higher-than-ambient temperatures and under wet conditions

Use of additional coating thickness or higher quality coatings at highway, road and railroad crossings, either cased or uncased, and in developed areas

Service life anticipated for the pipeline

Comparative quality of the coatings over the service life the pipeline

Differential cost, if any, for the cathodic protection system

445 BurialRestrained Lines and Provision for ExpansionLong cross-country pipelines are generally buried for several obvious reasons:

Allows surface use of land by private owners and the public

Protects the line from accidental and intentional damage

Protects the line against temperature expansion and contraction from ambient temperature changes and radiant energy gains and losses

Minimizes effects of temperature changes on fluid viscosity

Provides restraint along the length of line

Aboveground installation may not be allowed by governmental authorities

On the other hand, in undeveloped areas some major pipelines and, often, flow and gathering lines are designed and installed aboveground for one or more of the following reasons:

Economy of construction, especially where ditching is costly, since there are savings in both excavation and pipe coating

Benefit of solar radiation in keeping waxy oils above the pour point

Use of insulation and tracing arrangements on heated lines that would not be feasible for burial

Designs of hot lines and aboveground lines need to incorporate restraints and provi-sion for thermal expansion, and must be examined individually.

Burial CoverSufficient cover to protect the pipeline should be provided both for existing condi-tions and for any anticipated grading, cultivation, or developments that would require a very costly lowering of the line in the future. Company practice in many areas, especially for production field lines, is to increase cover over required mini-July 1999 400-36 Chevron Corporation

Pipeline Manual 400 Designmums, since the cost of a deeper ditch in normal excavation is small compared to the added protection; five feet is recommended. Deeper burial is usually required for heated lines to provide restraint, and water and slurry lines should be buried below the ground frost depth.

In some areas, it is advisable to place a yellow warning tape about a foot above the pipe to serve as a marker to anyone excavating across the right-of-way. Yellow Terra-Tape is one such tape and can be purchased with a metallic strip for burial over fiberglass pipe.

Minimum Cover for Liquid Lines. Section 434.6 of Code B31.4 requires the cover over the top of a line to be appropriate for surface use of the land and for a normal depth of cultivation, and sufficient to protect against loads imposed by road and rail traffic. Code B31.4 Table 434.6(a) gives minimum requirements for cover. See Figure 400-10.

If these minimums cannot be met, additional protection must be provided to with-stand anticipated loads and minimize damage by external forces.

Minimum Cover for Gas Lines. Section 841.142 of Code B31.8 gives minimum covers for gas transmission lines and discusses special considerations. See Figure 400-11.

Fig. 400-10 Minimum Cover Requirements for Liquid Lines

Normal ExcavationBlasted Rock

ExcavationLPG and NH3

Normal Excavation

Developed areas 36 in. 24 in. 48 in.

River and stream crossings

48 in. 18 in. 48 in.

Drainage ditches at roads and railroads

36 in. 24 in. 48 in.

Any other area 30 in. 18 in. 36 in.

Fig. 400-11 Minimum Cover Requirements for Gas Lines

Blasted Rock Excavation

Location Normal Excavation NPS 20 and Smaller Over NPS 20

Class 1 24 in. 12 in. 18 in.

Class 2 30 in. 18 in. 18 in.

Class 3 and 4 30 in. 24 in. 24 in.

Drainage ditches at roads and railroads 36 in. 24 in. 24 in.Chevron Corporation 400-37 July 1999

400 Design Pipeline ManualRestrained LinesIt is important to examine the effect of temperature differentials in a heated line restrained by burial or equivalent anchorage, and the resulting combination of tensile (positive) hoop stresses and compressive (negative) longitudinal stresses.Section 419 of Code B31.4 deals with expansion and flexibility; the following anal-ysis will indicate whether detailed study is advisable. The Materials and Engi-neering Analysis Division of the Engineering Technology Department can assist in these calculations.

The net longitudinal compressive stress due to the combined effects of internal pres-sure and temperature rise are computed using the following equation from Section 419.6.4(b) of Code B31.4:

SL = E T SH(Eq. 400-11)

where:SL = longitudinal compressive stress, psi

SH = hoop stress due to fluid pressure, psi (=PD/2t)T = T2 - T1T1 = temperature at time of installation, F

T2 = maximum operating temperature, F

E = modulus of elasticity of steel, psi (= 30 106 psi) = Linear coefficient of thermal expansion of steel, in./in./ F (= 6.5

10-6/ F) = Poissons ratio for steel (= 0.3)

so:

SL = (30 106 6.5 10-6 T) - 0.3 SH= 195 T - 0.3 SH

If the temperature rise is great enough, the compressive stress caused by the restraint on pipe growth will exceed the tensile stress due to internal pressure. If the net longitudinal stress, SL, becomes compressive, then absolute values are used for pipe stresses in accordance with the Tresca Maximum Shear Theory, as follows:

| SH | + | SL | = equivalent tensile strength allowable stress(Eq. 400-12)

Adding the absolute values of hoop stress and longitudinal stress when the values are of opposite sign to arrive at an equivalent tensile stress is a departure from sepa-rately comparing hoop stress and longitudinal stress to allowable values.July 1999 400-38 Chevron Corporation

Pipeline Manual 400 DesignThe allowable value for equivalent tensile stress is limited to 90% of SMYS (per Section 402.3.2(c) of Code B31.4). Using this limit and Equations 400-11 and 400-12 the maximum temperature difference (F) for a fully restrained pipe oper-ating at a maximum allowable pressure at 0.72 SMYS is:

Tmax = 0.002 SMYS(Eq. 400-13)

If the design temperature difference is greater, the maximum allowable pressure will have to be reduced below 0.72 SMYS, or, alternatively, higher grade pipe used.

When lowering or repositioning pipelines, or in portions of a restrained line above-ground, beam bending stresses must be included in the net compressive longitu-dinal stress calculation.

The burial depth required to provide restraint is a function of pipe diameter, soil and backfill strength properties, bend configuration (overbend or sidebend), bend radius and angle, temperature difference, and pipe-soil friction. Given operating tempera-ture and soil type, diagrams for a specific pipeone for overbends and one for side-bendsshould be developed relating depth of cover to angle of bend, as indicated in Figure 400-12. See Appendix F for method used to develop these diagrams.

Provision for Expansion or AnchoringThe pipeline transition zone from underground to aboveground represents a change in conditions from fully restrained to unrestrai