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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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