PEH:Piping and Pipelines

Publication Information

Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume III – Facilities and Construction Engineering

Kenneth E. Arnold, Editor

Copyright 2006, Society of Petroleum Engineers

Chapter 9 – Piping and Pipelines

Ralph S. Stevens III and Don May, AMEC paragon’s Pipeline Group

Pgs. 317-394

ISBN 978-1-55563-116-1
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Once oil and gas are located and the well is successfully drilled and completed, the product must be transported to a facility where it can be produced/treated, stored, processed, refined, or transferred for eventual sale. Fig. 9.1 is a simplified diagram that illustrates the typical, basic "wellhead to sales" concept. The typical system begins at the well flow-control device on the producing "wing(s)" of the wellhead tree and includes the well "flowline," production/treating/storage equipment, custody-transfer measurement equipment, and the gathering or sales pipeline. Information and detailed discussions concerning petroleum production, treating, storage, and measurement equipment are located in various chapters of this Handbook.

• 

  Fig. 9.1—Wellhead to sales (courtesy of AMEC Paragon).

The piping and pipeline systems typically associated with producing wells include, but are not limited to, the well flowline, interconnecting equipment piping within the production "battery," the gathering or sales pipeline, and the transmission pipeline. A brief description of the associated piping/pipeline systems is given next.

Piping and Pipeline Systems

Well Flowline

The well flowline, or simply flowline, is the first "pipeline" system connected to the wellhead. The flowline carries total produced fluids (e.g., oil, gas, and production water) from the well to the first piece of production equipment—typically a production separator. The flowline may carry the well-production fluids to a common production battery, a gathering pipeline system, process facility, or other.

Interconnecting Piping

Interconnecting piping includes the piping between the various pieces of production/treating equipment such as production separators, line heaters, oil heaters, pump units, storage tanks, and gas dehydrators. The piping systems may also include headers, fuel systems, other utility piping, and pressure-relief/flare systems.

Gathering/Sales Pipeline

The pipe that delivers the well production to some intermediate or terminal location is the gathering or sales pipeline. The gathering pipeline literally "gathers" the production from producing wells and conveys the production to a collection system, a processing facility, custody-transfer (sales) point, or other.

Transmission Pipeline

The transmission pipeline is a "cross-country" pipeline that is specifically designed to transport petroleum products long distances. The transmission pipeline collects the specific petroleum products from many "supply" sources along the pipeline (such as gathering pipelines) and "delivers" the product to one or more end users. There are three general categories of transmission pipelines: natural gas, "product," and crude oil. Natural-gas transmission pipelines carry only natural gas. Product pipelines may carry a number of processed or refined petroleum products such as processed natural-gas liquids (e.g., butane and propane), gasoline, diesel, and refined fuel oils. Crude-oil pipelines convey unrefined crude oil from producing areas to large storage areas or directly to refineries.

Piping and Pipeline Systems’ Pressure-Drop Formulas

The simplest way to convey a fluid, in a contained system from Point A to Point B, is by means of a conduit or pipe (Fig. 9.2). The minimum basic parameters that are required to design the piping system include, but are not limited to, the following.

• The characteristics and physical properties of the fluid.
• The desired mass-flow rate (or volume) of the fluid to be transported.
• The pressure, temperature, and elevation at Point A.
• The pressure, temperature, and elevation at Point B.
• The distance between Point A and Point B (or length the fluid must travel) and equivalent length (pressure losses) introduced by valves and fittings.

• 

  Fig. 9.2—Fluid-flow system (courtesy of AMEC Paragon).

These basic parameters are needed to design a piping system. Assuming steady-state flow, there are a number of equations, which are based upon the general energy equation, that can be employed to design the piping system. The variables associated with the fluid (i.e., liquid, gas, or multiphase) affect the flow. This leads to the derivation and development of equations that are applicable to a particular fluid. Although piping systems and pipeline design can get complex, the vast majority of the design problems encountered by the engineer can be solved by the standard flow equations.

Bernoulli Equation

The basic equation developed to represent steady-state fluid flow is the Bernoulli equation which assumes that total mechanical energy is conserved for steady, incompressible, inviscid, isothermal flow with no heat transfer or work done. These restrictive conditions can actually be representative of many physical systems.

The equation is stated as

....................(9.1)

where

Z	=	elevation head, ft,
P	=	pressure, psi,
ρ	=	density, lbm/ft3,
V	=	velocity, ft/sec,
g	=	gravitational constant, ft/sec2,
and
HL	=	head loss, ft.

Fig. 9.3 presents a simplified graphic illustration of the Bernoulli equation.

• 

  Fig. 9.3—Sketch four Bernoulli equation (courtesy of AMEC Paragon).

Darcy’s equation further expresses head loss as

....................(9.2)

and

....................(9.3)

where

HL	=	head loss, ft,
f	=	Moody friction factor, dimensionless,
L	=	pipe length, ft,
D	=	pipe diameter, ft,
V	=	velocity, ft/sec,
g	=	gravitational constant ft/sec2,
ΔP	=	pressure drop, psi,
ρ	=	density, lbm/ft3,
and
d	=	pipe inside diameter, in.

Reynolds Number and Moody Friction Factor

The Reynolds number is a dimensionless parameter that is useful in characterizing the degree of turbulence in the flow regime and is needed to determine the Moody friction factor. It is expressed as

....................(9.4)

where

ρ	=	density, lbm/ft3,
D	=	pipe internal diameter, ft,
V	=	flow velocity, ft/sec,
and
μ	=	viscosity, lbm/ft-sec.

The Reynolds number for liquids can be expressed as

....................(9.5)

where

μ	=	viscosity, cp,
d	=	pipe inside diameter, in.,
SG	=	specific gravity of liquid relative to water (water = 1),
Ql	=	liquid-flow rate, B/D,
and
V	=	velocity, ft/sec.

The Reynolds number for gases can be expressed as

....................(9.6)

where

μ	=	viscosity, cp,
d	=	pipe inside diameter, in.,
S	=	specific gravity of gas at standard conditions relative to air (molecular weight divided by 29),
and
Qg	=	gas-flow rate, MMscf/D.

The Moody friction factor, f, expressed in the previous equations, is a function of the Reynolds number and the roughness of the internal surface of the pipe and is given by Fig. 9.4. The Moody friction factor is impacted by the characteristic of the flow in the pipe. For laminar flow, where Re is < 2,000, there is little mixing of the flowing fluid, and the flow velocity is parabolic; the Moody friction factor is expressed as f = 64/Re. For turbulent flow, where Re > 4,000, there is complete mixing of the flow, and the flow velocity has a uniform profile; f depends on Re and the relative roughness (Є/D). The relative roughness is the ratio of absolute roughness, Є, a measure of surface imperfections to the pipe internal diameter, D. Table 9.1 lists the absolute roughness for several types of pipe materials.

• 

  Fig. 9.4—Friction-factor chart (courtesy of AMEC Paragon).

• 

  Table 9.1

If the viscosity of the liquid is unknown, Fig. 9.5 can be used for the viscosity of crude oil, Fig. 9.6 for effective viscosity of crude-oil/water mixtures, and Fig. 9.7 for the viscosity of natural gas. In using some of these figures, the relationship between viscosity in centistokes and viscosity in centipoise must be used

....................(9.7)

where

γ	=	kinematic viscosity, centistokes,
ϕ	=	absolute viscosity, cp,
and
SG	=	specific gravity.

• 

  Fig. 9.5—Standard viscosity/temperature charts for liquid petroleum products (courtesy of ASTM).

• 

  Fig. 9.6—Effective viscosity of an oil/water mixture (courtesy of AMEC Paragon).

• 

  Fig. 9.7—Hydrocarbon-gas viscosity vs. temperature (courtesy Western Supply Co.).

Pressure Drop for Liquid Flow

General Equation. Eq. 9.3 can be expressed in terms of pipe inside diameter (ID) as stated next.

....................(9.8)

where

d	=	pipe inside diameter, in.,
f	=	Moody friction factor, dimensionless,
L	=	length of pipe, ft,
Ql	=	liquid flow rate, B/D,
SG	=	specific gravity of liquid relative to water,
and
ΔP	=	pressure drop, psi (total pressure drop).

Hazen-Williams Equation. The Hazen-Williams equation, which is applicable only for water in turbulent flow at 60°F, expresses head loss as

....................(9.9)

where

HL	=	head loss because of friction, ft,
L	=	pipe length, ft,
C	=	friction factor constant, dimensionless (Table 9.2),
d	=	pipe inside diameter, in.,
Ql	=	liquid flow rate, B/D,
and
gpm	=	liquid flow rate, gal/min.

• 

  Table 9.2

Pressure drop can be calculated from

....................(9.10)

Pressure Drop for Gas Flow

General Equation. The general equation for calculating gas flow is stated as

....................(9.11)

where

w	=	rate of flow, lbm/sec,
g	=	acceleration of gravity, 32.2 ft/sec2,
A	=	cross-sectional area of pipe, ft2,
V1‘	=	specific volume of gas at upstream conditions, ft3/lbm,
f	=	friction factor, dimensionless,
L	=	length, ft,
D	=	diameter of the pipe, ft,
P1	=	upstream pressure, psia,
and
P2	=	downstream pressure, psia.

Assumptions: no work performed, steady-state flow, and f = constant as a function of the length.

Simplified Equation. For practical pipeline purposes, Eq. 9.11 can be simplified to

....................(9.12)

where

P1	=	upstream pressure, psia,
P2	=	downstream pressure, psia,
S	=	specific gravity of gas,
Qg	=	gas flow rate, MMscf/D,
Z	=	compressibility factor for gas, dimensionless,
T	=	flowing temperature, °R,
f	=	Moody friction factor, dimensionless,
d	=	pipe ID, in.,
and
L	=	length, ft.

The compressibility factor, Z, for natural gas can be found in Fig. 9.8.

• 

  Fig. 9.8—Compressibility of low-molecular-weight natural gases (courtesy of Natl. Gas Processors Suppliers Assn.).

Three simplified derivative equations can be used to calculate gas flow in pipelines. The Weymouth equation, the Panhandle equation, and the Spitzglass equation are all effective, but the accuracy and applicability of each equation falls within certain ranges of flow and pipe diameter. The equations are stated next.

Weymouth Equation. This equation is used for high-Reynolds-number flows where the Moody friction factor is merely a function of relative roughness.

....................(9.13)

where

Qg	=	gas-flow rate, MMscf/D,
d	=	pipe inside diameter, in.,
P1	=	upstream pressure, psia,
P2	=	downstream pressure, psia,
L	=	length, ft,
T1	=	temperature of gas at inlet, °R,
S	=	specific gravity of gas,
and
Z	=	compressibility factor for gas, dimensionless.

Panhandle Equation. This equation is used for moderate-Reynolds-number flows where the Moody friction factor is independent of relative roughness and is a function of Reynolds number to a negative power.

....................(9.14)

where

E	=	efficiency factor (new pipe: 1.0; good operating conditions: 0.95; average operating conditions: 0.85),
Qg	=	gas-flow rate, MMscf/D,
d	=	pipe ID, in.,
P1	=	upstream pressure, psia,
P2	=	downstream pressure, psia,
Lm	=	length, miles,
T1	=	temperature of gas at inlet, °R,
S	=	specific gravity of gas,
and
Z	=	compressibility factor for gas, dimensionless.

Spitzglass Equation.

....................(9.15)

where

Qg	=	gas-flow rate, MMscf/D,
ΔhW	=	pressure loss, inches of water,
and
d	=	pipe ID, in.

Assumptions:

f	=	(1+ 3.6/ d + 0.03 d ) (1/100),
T	=	520°R,
P1	=	15 psia,
Z	=	1.0,
and
ΔP	=	< 10% of P 1 .

Application of the Formulas. As previously discussed, there are certain conditions under which the various formulas are more applicable. A general guideline for application of the formulas is given next.

Simplified Gas Formula. This formula is recommended for most general-use flow applications.

Weymouth Equation. The Weymouth equation is recommended for smaller-diameter pipe (generally, 12 in. and less). It is also recommended for shorter lengths of segments ( < 20 miles) within production batteries and for branch gathering lines, medium- to high-pressure (+/–100 psig to > 1,000 psig) applications, and a high Reynolds number.

Panhandle Equation. This equation is recommended for larger-diameter pipe (12-in. diameter and greater). It is also recommended for long runs of pipe ( > 20 miles) such as cross-country transmission pipelines and for moderate Reynolds numbers.

Spitzglass Equation. The Spitzglass equation is recommended for low-pressure vent lines < 12 in. in diameter (ΔP < 10% of P₁).

The petroleum engineer will find that the general gas equation and the Weymouth equation are very useful. The Weymouth equation is ideal for designing branch laterals and trunk lines in field gas-gathering systems.

Multiphase Flow

Flow Regimes. Fluid from the wellbore to the first piece of production equipment (separator) is generally two-phase liquid/gas flow.

The characteristics of horizontal, multiphase flow regimes are shown in Fig. 9.9. They can be described as follows:

• Bubble: Occurs at very low gas/liquid ratios where the gas forms bubbles that rise to the top of the pipe.
• Plug: Occurs at higher gas/liquid ratios where the gas bubbles form moderate-sized plugs.
• Stratified: As the gas/liquid ratios increase, plugs become longer until the gas and liquid flow in separate layers.
• Wavy: As the gas/liquid ratios increase further, the energy of the flowing gas stream causes waves in the flowing liquid.
• Slug: As the gas/liquid ratios continue to increase, the wave heights of the liquid increase until the crests contact the top of the pipe, creating liquid slugs.
• Spray: At extremely high gas/liquid ratios, the liquid is dispersed into the flowing-gas stream.

• 

  Fig. 9.9—Two-phase-flow patterns in horizontal flow (courtesy of AMEC Paragon).

Fig. 9.10 shows the various flow regimes that could be expected in horizontal flow as a function of the superficial velocities of gas and liquid flow. Superficial velocity is the velocity that would exist if the other phase was not present.

• 

  Fig. 9.10—Horizontal multiphase-flow map (after Griffith).

The multiphase flow in vertical and inclined pipe behaves somewhat differently from multiphase flow in horizontal pipe. The characteristics of the vertical flow regimes are shown in Fig. 9.11 and are described next.

• 

  Fig. 9.11—Two-phase-flow patterns in vertical flow (courtesy of AMEC Paragon).

Bubble. Where the gas/liquid ratios are small, the gas is present in the liquid in small, variable-diameter, randomly distributed bubbles. The liquid moves at a fairly uniform velocity while the bubbles move up through the liquid at differing velocities, which are dictated by the size of the bubbles. Except for the total composite-fluid density, the bubbles have little effect on the pressure gradient.

Slug Flow. As the gas/liquid ratios continue to increase, the wave heights of the liquid increase until the crests contact the top of the pipe, creating liquid slugs.

Transition Flow. The fluid changes from a continuous liquid phase to a continuous gas phase. The liquid slugs virtually disappear and are entrained in the gas phase. The effects of the liquid are still significant, but the effects of the gas phase are predominant.

Annular Mist Flow. The gas phase is continuous, and the bulk of the liquid is entrained within the gas. The liquid wets the pipe wall, but the effects of the liquid are minimal as the gas phase becomes the controlling factor. Fig. 9.12 shows the various flow regimes that could be expected in vertical flow as a function of the superficial velocities of gas and liquid flow.

• 

  Fig. 9.12—Vertical-multiphase-flow map (after Yaitel et al.).

Two-Phase Pressure Drop. The calculation of pressure drop in two-phase flow is very complex and is based on empirical relationships to take into account the phase changes that occur because of pressure and temperature changes along the flow, the relative velocities of the phases, and complex effects of elevation changes. Table 9.3 lists several commercial programs that are available to model pressure drop. Because all are based to some extent on empirical relations, they are limited in accuracy to the data sets from which the relations were designed. It is not unusual for measured pressure drops in the field to differ by ± 20% from those calculated by any of these models.

• 

  Table 9.3

Simplified Friction Pressure-Drop Approximation for Two-Phase Flow. Eq. 9.16 provides an approximate solution for friction pressure drop in two-phase-flow problems that meet the assumptions stated.

....................(9.16)

where

ΔP	=	friction pressure drop, psi,
f	=	Moody friction factor, dimensionless,
L	=	length, ft,
W	=	rate of flow of mixture, lbm/hr,
ρM	=	density of the mixture, lbm/ft3,
and
d	=	pipe ID, in.

The formula for rate of mixture flow is

....................(9.17)

where

Qg	=	gas-flow rate, MMscf/D,
QL	=	liquid flow rate, B/D,
S	=	specific gravity of gas at standard conditions, lbm/ft3 (air = 1),
and
SG	=	specific gravity of liquid, relative to water, lbm/ft3.

The density of the mixture is given by

....................(9.18)

where

P	=	operating pressure, psia,
R	=	gas/liquid ratio, ft3/bbl,
T	=	operating temperature, °R,
SG	=	specific gravity of liquid, relative to water, lbm/ft3,
S	=	specific gravity of gas at standard conditions, lbm/ft3 (air = 1),
and
Z	=	gas compressibility factor, dimensionless.

The formula is applicable if the following conditions are met:

• ΔP is less than 10% of the inlet pressure.
• Bubble or mist exists.
• There are no elevation changes.
• There is no irreversible energy transfer between phases.

Pressure Drop Because of Changes in Elevation. There are several notable characteristics associated with pressure drop because of elevation changes in two-phase flow. The flow characteristics associated with the elevation changes include:

• In downhill lines, flow becomes stratified as liquid flows faster than gas.
• The depth of the liquid layer adjusts to the static pressure head and is equal to the friction pressure drop.
• There is no pressure recovery in the downhill line.
• In low gas/liquid flow, the flow in uphill segments can be liquid "full" at low flow rates. Thus, at low flow rates, the total pressure drop is the sum of the pressure drops for all of the uphill runs.
• With increased gas flow, the total pressure drop may decrease as liquid is removed from uphill segments.

The pressure drop at low flow rates associated with an uphill elevation change may be approximated with Eq. 9.19.

....................(9.19)

where

ΔPZ	=	pressure drop because of elevation increase in the segment, psi,
SG	=	specific gravity of the liquid in the segment, relative to water,
and
ΔZ	=	increase in elevation for segment, ft.

The total pressure drop can then be approximated by the sum of the pressure drops for each uphill segment.

Pressure Drop Caused by Valves and Fittings

One of the most important parameters affecting pressure drop in piping systems is pressure loss in the fittings and valves, which is incorporated in the system. For piping systems within production facilities, the pressure drop through fittings and valves can be much greater than that through the straight run of pipe itself. In long pipeline systems, the pressure drop through fittings and valves can often be ignored.

Resistance Coefficients

The head loss in valves and fittings can be calculated with resistance coefficients as

....................(9.20)

where

HL	=	head loss, ft,
Kr	=	resistance coefficient, dimensionless,
D	=	pipe ID, ft,
and
V	=	velocity, ft/sec.

The total head loss is the sum of all K_r V²/2g.

The resistance coefficients K_r for individual valves and fittings are found in tabular form in a number of industry publications. Most manufacturers publish tabular data for all sizes and configurations of their products. One of the best sources of data is the Crane Flow of Fluids, technical paper No. 410. The Natural Gas Processors Suppliers Assn. (NGPSA) Engineering Data Book and Ingersoll-Rand’s Cameron Hydraulic Data Book are also good sources of references for the information. Some examples of resistance coefficients are listed in Tables 9.4 and 9.5.

• 

  Table 9.4

• 

  Table 9.5

• 

  Table 9.5 (continued)

• 

  Table 9.5 (continued)

• 

  Table 9.5 (continued)

Flow Coefficients

The flow coefficient for liquids, C_V, is determined experimentally for each valve or fitting as the flow of water, in gal/min at 60°F for a pressure drop of 1 psi through the fitting. The relationship between flow and resistance coefficients can be expressed as

....................(9.21)

In any fitting or valve with a known C_V, the pressure drop can be calculated for different conditions of flow and liquid properties with Eq. 9.22.

....................(9.22)

where

QL	=	liquid-flow rate, B/D,
and
SG	=	liquid specific gravity relative to water.

Again, the C_V is published for most valves and fittings and can be found in multiple sources, as well as the manufacturer’s technical data.

Equivalent Lengths

The head loss associated with valves and fittings can also be calculated by considering equivalent "lengths" of pipe segments for each valve and fitting. In other words, the calculated head loss caused by fluid passing through a gate valve is expressed as an additional length of pipe that is added to the actual length of pipe in calculating pressure drop.

All of the equivalent lengths caused by the valves and fittings within a pipe segment would be added together to compute the pressure drop for the pipe segment. The equivalent length, L_e, can be determined from the resistance coefficient, K_r, and the flow coefficient, C_V, using the formulas given next.

....................(9.23)

....................(9.24)

and

....................(9.25)

where

Kr	=	resistance coefficient, dimensionless,
D	=	diameter of the pipe, ft,
f	=	Moody friction factor, dimensionless,
d	=	pipe ID, in.,
and
CV	=	flow coefficient for liquids, dimensionless.

Table 9.6 shows equivalent lengths of pipe for a variety of valves and fittings for a number of standard pipe sizes.

• 

  Table 9.6

Selecting Pipe Wall Thickness

The fluid flow equations and formulas presented thus far enable the engineer to initiate the design of a piping or pipeline system, where the pressure drop available governs the selection of pipe size. (In addition, there may be velocity constraints that might dictate a larger pipe diameter. This is discussed in Sec. 9.5.)

Once the ID of the piping segment has been determined, the pipe wall thickness must be calculated. There are many factors that affect the pipe-wall-thickness requirement, which include the maximum and working pressures, maximum and working temperatures, chemical properties of the fluid, the fluid velocity, the pipe material and grade, and the safety factor or code design application.

If there are no codes or standards that specifically apply to the oil and gas production facilities, the design engineer may select one of the industry codes or standards as the basis of design. The design and operation of gathering, transmission, and distribution pipeline systems are usually governed by codes, standards, and regulations. The design engineer must verify whether the particular country in which the project is located has regulations, codes, and standards that apply to facilities and/or pipelines.

The basic formula for determining pipe wall thickness is the general hoop stress formula for thin-wall cylinders, which is stated as

....................(9.26)

where

HS	=	hoop stress in pipe wall, psi,
t	=	pipe wall thickness, in.,
L	=	length of pipe, ft,
P	=	internal pressure of the pipe, psi,
and
do	=	outside diameter of pipe, in.

Piping Codes

The following standards from the American Natl. Standards Inst. (ANSI) and the American Soc. of Mechanical Engineers (ASME) specify wall-thickness requirements.

• ANSI/ASME Standard B31.1, Power Piping. This standard applies to steam piping systems.
• ANSI/ASME Standard B31.3, Chemical Plant and Petroleum Refinery Piping. This standard applies to major facilities onshore and offshore worldwide.
• ANSI/ASME Standard B31.4, Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum Gas, Anhydrous Ammonia, and Alcohols. This standard applies to onshore oil pipeline facilities.
• ANSI/ASME Standard B31.8, Gas Transmission and Distribution Piping Systems. This standard applies to gas transmission, gathering, and distribution pipelines onshore.

In the U.S, piping on offshore facilities is mandated by regulation to be done in accordance with ANSI/ASME Standard B31.3. Most onshore facilities are designed in accordance with ANSI/ASME Standard B31.4 or B31.8, depending on whether it is an oil or gas facility. respectively. Some companies use the more stringent ANSI/ASME Standard B31.3 for onshore facilities.

In other countries, similar standards apply with minor variations. For simplicity, we will discuss only the U.S. standards in this chapter. The engineer should check to see if there are different standards that must be applied in the specific location of the design.

Pipe Materials-Basics

There are some applications where plastic, concrete, or other piping materials are both desirable and acceptable. Utility systems such as those for water, sanitary or storm water, air, draining or low-pressure oil or gas service applications often use the nonsteel piping material systems. However, for the vast majority of the "pressure" piping systems encountered, steel pipe is required.

For petroleum applications, pipe materials that meet American Petroleum Inst. (API), American Soc. for Testing and Materials (ASTM), ASME, and ANSI standards are used most often. All of these standards have very rigid design, specification, chemistry, and testing standardization and manufacturing requirements. Modern steel pipe manufactured to these exacting standards assures both high quality and safety in design.

Steel pipe is available in a variety of commercial sizes ranging from nominal 1/8 up to 60 in. or greater. Table 9.7 illustrates a number ANSI pipe schedules, for reference. The "nominal" commercial pipe sizes from 1/8 through 12 in. refer to the approximate ID measurement of Schedule 40 or "standard" wall, whereas nominal 14 in. and larger sizes refer to the outside diameter. A variety of steel pipe sizes, wall thicknesses, and material grades are available for petroleum piping and pipeline applications.

• 

  Table 9.7

Please note that the allowable internal pressure is the maximum pressure to which the piping system can be subjected. This could be significantly higher than the flowing pressure of the fluid in the pipe.

Wall Thickness Calculations-Using B31.3 Code

ANSI/ASME Standard B31.3 is a very stringent code with a high safety margin. The B31.3 wall-thickness calculation formula is stated as

....................(9.27)

where

t	=	minimum design wall thickness, in.,
te	=	corrosion allowance, in.,
tth	=	thread or groove depth, in. (Table 9.8),
P	=	allowable internal pressure in pipe, psi,
do	=	outside diameter of pipe, in.,
S	=	allowable stress for pipe, psi (Tables 9.9 and 9.10),
E	=	longitudinal weld-joint factor [1.0 seamless, 0.95 electric fusion weld, double butt, straight or spiral seam APL 5L, 0.85 electric resistance weld (ERW), 0.60 furnace butt weld],
Y	=	derating factor (0.4 for ferrous materials operating below 900°F),
and
Tol	=	manufacturers allowable tolerance, % (12.5 pipe up to 20 in.-OD, 10 pipe > 20 in. OD, API 5L).

• 

  Table 9.8

• 

  Table 9.9

• 

  Table 9.10

Under ANSI/ASME Standard B31.3, the allowable pressure can be increased for certain instances. The conditions for the permissible increases in allowable pressure, according to Standard B31.3, are given next.

• When the variation lasts no more than 10 hours at any one time and not more than 100 hours per year, it is permissible to exceed the pressure rating or the allowable stress for pressure design at the temperature of the increased condition by no more than 33%.
• When the variation lasts no more than 50 hours at any one time and not more than 500 hours per year, it is permissible to exceed the pressure rating or the allowable stress for pressure design at the temperature of the increased condition by not more than 20%.

Wall-Thickness Calculations-Using B31.4 Code

The ANSI/ASME Standard B31.4 code is somewhat less stringent than that of Standard B31.3 because of the lower levels of hazard associated with liquid pipelines. The code for Standard B31.4 is used often as the standard of design for crude-oil piping systems in facilities, such as pump stations, pigging facilities, measurement and regulation stations, and tank farms. The wall-thickness formula for Standard B31.4 is stated as

....................(9.28)

where

t	=	minimum design wall thickness, in.,
P	=	internal pressure in pipe, psi,
do	=	OD of pipe, in.,
SY	=	minimum yield stress for pipe, psi (Table 9.11),
F	=	derating factor, 0.72 for all locations,
and
E	=	longitudinal weld-joint factor [1.0 seamless, ERW, double submerged arc weld and flash weld; 0.80 electric fusion (arc) weld and electric fusion weld, 0.60 furnace butt weld].

• 

  Table 9.11

• 

  Table 9.11 (continued)

Wall-Thickness Calculations-Using B31.8 Code

The ANSI/ASME Standard B31.8 code is less stringent than that of Standard B31.3, but more stringent than that of Standard B13.4. The B31.8 code is often used as the standard of design for natural-gas piping systems in facilities, such as compressor stations, gas-treatment facilities, measurement and regulation stations, and tank farms. The B31.8 wall-thickness formula is stated as

....................(9.29)

where

t	=	minimum design wall thickness, in.,
P	=	internal pressure in pipe, psi,
do	=	OD of pipe, in.,
SY	=	minimum yield stress for pipe, psi (Table 9.12),
F	=	design factor (see Table 9.13 and discussion that follows),
E	=	longitudinal weld-joint factor (Table 9.14),
and
T	=	temperature derating factor (Table 9.15).

• 

  Table 9.12

• 

  Table 9.12 (continued)

• 

  Table 9.13

• 

  Table 9.14

• 

  Table 9.15

The design factor, F, for steel pipe is a construction derating factor dependent upon the location class unit, which is an area that extends 220 yards on either side of the centerline of any continuous 1-mile length of pipeline. Each separate dwelling unit in a multiple-dwelling-unit building is counted as a separate building intended for human occupancy.

To determine the number of buildings intended for human occupancy for an onshore pipeline, lay out a zone 1/4-mile wide along the route of the pipeline with the pipeline on the centerline of this zone, and divide the pipeline into random sections 1 mile in length such that the individual lengths will include the maximum number of buildings intended for human occupancy. Count the number of buildings intended for human occupancy within each 1-mile zone. For this purpose, each separate dwelling unit in a multiple-dwelling-unit building is to be counted as a separate building intended for human occupancy.

It is not intended here that a full mile of lower-stress pipeline shall be installed if there are physical barriers or other factors that will limit the further expansion of the more densely populated area to a total distance of less than 1 mile. It is intended, however, that where no such barriers exist, ample allowance shall be made in determining the limits of the lower stress design to provide for probable further development in the area.

When a cluster of buildings intended for human occupancy indicates that a basic mile of pipeline should be identified as a Location Class 2 or Location Class 3, the Location Class 2 or Location Class 3 may be terminated 660 ft from the nearest building in the cluster. For pipelines shorter than 1 mile in length, a location class shall be assigned that is typical of the location class that would be required for 1 mile of pipeline traversing the area.

Location Classes for Design and Construction. Class 1 Location. A Class 1 location is any 1-mile section of pipeline that has 10 or fewer buildings intended for human occupancy. This includes areas such as wastelands, deserts, rugged mountains, grazing land, farmland, and sparsely populated areas.

Class 1, Division 1 Location. This is a Class 1 location where the design factor, F, of the pipe is greater than 0.72 but equal to or less than 0.80 and which has been hydrostatically tested to 1.25 times the maximum operating pressure. (See Table 9.13 for exceptions to design factor.)

Class 1, Division 2 Location. This is a Class 1 location where the design factor, F, of the pipe is equal to or less than 0.72, and which has been tested to 1.1 times the maximum operating pressure.

Class 2 Location. This is any 1-mile section of pipeline that has more than 10 but fewer than 46 buildings intended for human occupancy. This includes fringe areas around cities and towns, industrial areas, and ranch or country estates.

Class 3 Location. This is any 1-mile section of pipeline that has 46 or more buildings intended for human occupancy except when a Class 4 Location prevails. This includes suburban housing developments, shopping centers, residential areas, industrial areas, and other populated areas not meeting Class 4 Location requirements.

Class 4 Location. This is any 1-mile section of pipeline where multistory buildings are prevalent, traffic is heavy or dense, and where there may be numerous other utilities underground. Multistory means four or more floors above ground including the first, or ground, floor. The depth of basements or number of basement floors is immaterial.

In addition to the criteria previously presented, additional consideration must be given to the possible consequences of a failure near a concentration of people, such as that found in a church, school, multiple-dwelling unit, hospital, or recreational area of an organized character in a Class 1 or 2 location. If the facility is used infrequently, the requirements of the following paragraph need not be applied.

Pipelines near places of public assembly or concentrations of people such as churches, schools, multiple-dwelling-unit buildings, hospitals, or recreational areas of an organized nature in Class 1 and 2 locations shall meet requirements for the Class 3 location.

The concentration of people previously referred to is not intended to include groups fewer than 20 people per instance or location but is intended to cover people in an outside area as well as in a building.

It should be emphasized that location class (1, 2, 3, or 4), as previously described, is the general description of a geographic area having certain characteristics as a basis for prescribing the types of design, construction, and methods of testing to be used in those locations or in areas that are respectively comparable. A numbered location class, such as Location Class 1, refers only to the geography of that location or a similar area and does not necessarily indicate that a design factor of 0.72 will suffice for all construction in that particular location or area (e.g., in Location Class 1, all crossings without casings require a design factor, F, of 0.60).

When classifying locations for the purpose of determining the design factor, F, for the pipeline construction and testing that should be prescribed, due consideration shall be given to the possibility of future development of the area. If at the time of planning a new pipeline this future development appears likely to be sufficient to change the class location, this should be taken into consideration in the design and testing of the proposed pipeline.

Wall-Thickness Calculations-Comparisons

Additional comparison of Standard B31.3 to both B31.4 and B31.8 indicates the following:

• ANSI/ASME Standard B31.3 is more conservative than either Standard B31.4 or B31.8, especially relative to API 5L, X-grade pipe and electric-resistance-welded (ERW) seam pipe.
• ANSI/ASME Standard B31.8 does not allow increases for transient conditions.
• The ANSI/ASME Standard B31.3 specification break occurs at the fence, whereas B31.8‘s occurs at the "first flange" upstream/downstream of the pipeline.

Using ANSI/ASME Standard B31.3 criteria for oil- and gas-facility piping will assure a very conservative design. However, the cost associated with the Standard B31.3 piping design may be substantial compared to the other codes and may not be necessary, especially for onshore facilities.

Velocity Considerations

In choosing a line diameter, consideration also has to be given to maximum and minimum velocities. The line should be sized such that the maximum velocity of the fluid does not cause erosion, excess noise, or water hammer. The line should be sized such that the minimum velocity of the fluid prevents surging and keeps the line swept clear of entrained solids and liquids.

API RP14E provides typical surge factors that should be considered in designing production piping systems. These are reproduced in Table 9.16.

• 

  Table 9.16

Liquid-Line Sizing

The liquid velocity can be expressed as

....................(9.30)

where

QL	=	fluid-flow rate, B/D
and
d	=	pipe ID, in.

In piping systems where solids might be present or where water could settle out and create corrosion zones in low spots, a minimum velocity of 3 ft/sec is normally used. A maximum velocity of 15 ft/sec is often used to minimize the possibility of erosion by solids and water hammer caused by quickly closing a valve.

Gas-Line Sizing

The pressure drop in gas lines is typically low in gas-producing facilities because the piping segment lengths are short. The pressure drop has a more significant impact upon longer segments such as gas-gathering pipelines, transmission pipelines, or relief or vent piping.

The velocity in gas lines should be less than 60 to 80 ft/sec to minimize noise and allow for corrosion inhibition. A lower velocity of 50 ft/sec should be used in the presence of known corrosives such as CO₂. The minimum gas velocity should be between 10 and 15 ft/sec, which minimizes liquid fallout.

Gas velocity is expressed in Eq. 9.31 as

....................(9.31)

where

Vg	=	gas velocity, ft/sec,
Qg	=	gas-flow rate, MMscf/D,
T	=	gas flowing temperature, °R,
P	=	flowing pressure, psia,
Z	=	compressibility factor, dimensionless,
and
d	=	pipe ID in.

Multiphase-Line Sizing

The minimum fluid velocity in multiphase systems must be relatively high to keep the liquids moving and prevent or minimize slugging. The recommended minimum velocity is 10 to 15 ft/sec. The maximum recommended velocity is 60 ft/sec to inhibit noise and 50 ft/sec for CO₂ corrosion inhibition.

In two-phase flow, it is possible that liquid droplets in the flow stream will impact on the wall of the pipe causing erosion of the products of corrosion. This is called erosion/corrosion. Erosion of the pipe wall itself could occur if solid particles, particularly sand, are entrained in the flow stream. The following guidelines from API RP14E should be used to protect against erosion/corrosion.

Calculate the erosional velocity of the mixture with Eq. 9.32.

....................(9.32)

where C = empirical constant. ρ_M is the average density of the mixture at flowing conditions. It can be calculated from

....................(9.33)

where

SG	=	specific gravity of the liquid (relative to water),
and
S	=	specific gravity of the gas relative to air.

Industry experience to date indicates that for solids-free fluids, values of C = 100 for continuous service and C = 125 for intermittent service are conservative. For solids-free fluids where corrosion is not anticipated or when corrosion is controlled by inhibition or by employing corrosion-resistant alloys, values of C = 150 to 200 may be used for continuous service; values up to 250 have been used successfully for intermittent service. If solids production is anticipated, fluid velocities should be significantly reduced. Different values of C may be used where specific application studies have shown them to be appropriate.

Where solids and/or corrosive contaminants are present or where c values higher than 100 for continuous service are used, periodic surveys to assess pipe wall thickness should be considered. The design of any piping system where solids are anticipated should consider the installation of sand probes, cushion flow tees, and a minimum of 3 ft of straight piping downstream of choke outlets.

Once a design velocity is chosen, to determine the pipe size, Eq. 9.34 can be used.

....................(9.34)

where

d	=	pipe ID, in.,
Z	=	compressibility factor, dimensionless,
R	=	gas/liquid ratio, ft3/bbl,
P	=	flowing pressure, psia,
T	=	gas/liquid flowing temperature, °R,
V	=	maximum allowable velocity, ft/sec,
and
QL	=	liquid-flow rate, B/D.

Valve, Fitting, and Flange Pressure Ratings

Pipe fittings, valves, and flanges are designed and manufactured in accordance several industry standards including API, ASTM, ANSI/ASME and Manufacturer’s Standardization Soc. (MSS) (large-diameter pipeline fittings/flanges). The piping components are designed and manufactured to the industry standards to ensure the consistency of the material properties and specifications; set uniform dimensional standards and tolerances; specify methods of production and quality control; specify service ratings and allowable pressure and temperature ratings for fittings manufactured to the standards; and provide interchangeability between fittings and valves manufactured to the standards.

Piping materials manufactured to these standards can be traced to the source foundry and the material composition verified. Material traceability is another important feature of standardization. Each fitting, valve, and flange can be certified as to the material, specification, and grade.

Pressure Ratings

ANSI Standard B16.5, Steel Pipe Flanges and Flanged Fittings, has seven pressure classes: ANSI 150, 300, 400, 600, 900, 1500, and 2500. Table 9.17 illustrates the maximum, nonshock working pressures for Material Group 1.1, which is the working group for most oil and gas piping and pipeline applications.

• 

  Table 9.17

API Spec. 6A prescribes seven pressure classes: 2,000, 3,000, 5,000, 10,000, 15,000, 20,000, and 30,000. API 2,000, 3,000, and 5,000 lbf have the same dimensions as ANSI 600, ANSI 900, and ANSI 1,500, respectively. When the API flange is bolted to an ANSI flange, the connection must be rated for the ANSI pressure rating. Table 9.18 shows the temperature and pressure ratings for API-specification fittings.

• 

  Table 9.18

API flanges are required for extreme high pressures and are typically used for wellheads. ANSI flanges are less costly and more available than the API flanges and are used in the production facility. Typically, API flanges are used in the flowline near the wellhead, but ANSI flanges are used downstream. Manifolds and production headers may be API or ANSI, depending upon the operating pressures.

Flange Types

Flanges come in a variety of neck connection configurations and face designs. Flange connections may be slip-on, threaded, socket weld, or weld neck. Slip-on, socket-weld, and threaded-neck flanges should not be used in most high-pressure applications, especially for pipe larger than 3- to 4-in. nominal pipe size. ANSI Standard B31.3 specifically recommends that slip-on flanges not be used where mechanical vibration or large temperature cycles are encountered. Weld-neck flanges are typically better in the higher-pressure oil and gas and pipeline applications.

The flange face, or the part of the flange that makes the physical connection, comes in several classifications: flat face, raised face (RF), and ring-type joint (RTJ), as shown in Fig. 9.13. Flat-face flanges are typically available only in low-pressure ANSI 150 flanges and are not used in high-pressure applications. RF and RTJ flanges are commonly used in the oil and gas and pipeline applications.

• 

  Fig. 9.13—Typical ASME/ANSI B16.5 and MSS SP 44 flange faces (courtesy of AMEC Paragon).

RF flanges are less expensive and easier to make up where tight clearances make it difficult to spread the flanges apart so that the ring may be inserted. RTJ flanges tend to seal better at higher pressures. API RP14E recommends RTJ faced flanges in ANSI class 900 and higher. Onshore applications often use RF flanges in pressure class ratings as high as ANSI 2500. ANSI Standard B16.5 places no limitations on the application of RF flanges in pressure service.

Gasket Materials

Gasket materials for flat-face gaskets normally are 1/16 in. thick and made of composite materials. Asbestos was formerly used for gasket materials for both flat-faced and RF gaskets, but asbestos has been replaced because it is a hazardous material.

Spiral-wound gaskets, composed of a metal ring with wound internal composite rings, are typically used. The composite materials may include stainless steel and Teflon or other polytetrafluoroethylene (PTFE) type materials. A wide selection of winding materials is commercially available for a number of different fluids and applications. RTJ "ring" gaskets are typically made of cadmium-plated soft iron or low-carbon steel for ANSI 600 and ANSI 900 class flanges. 304 and 316 stainless-steel rings are frequently used in the higher-class ratings as well as for corrosive-service applications (such as H₂S and CO₂ service).

Bolting Materials

The typical carbon-steel bolt materials used in most flange bolting applications is ASTM A-193, Grade B-7. The companion nuts are typically ASTM A-194, Grade 2H. ASTM has specifications and grades for carbon-steel and alloy bolts and nuts for high-temperature, low-temperature, and extreme-service applications.

Pipe Fittings

Pipe fittings generally are categorized as threaded, socket weld, or butt weld. The threaded and socket-weld fittings are typically forged steel and are ASTM A-105 material and manufactured as per ANSI B16.11, Forged Steel Fittings, Socket Welding, and Threaded. Socket-weld fittings have a groove where the pipe is inserted and weld material is used to fill the void and seal the connection. The pressure class ratings of forged-steel threaded and socket-weld fittings are 2,000 lbf (also known as standard); 3,000 lbf [also known as extra strong (XS)]; and 6,000 lbf [also known as double extra strong (XXS)], which refers to their allowable operating pressure at 100°F. The fittings are rated up to 700°F, where the rating effectively reduces the fitting operating pressures by 1/3. Generally, threaded fittings should not be used in piping systems for pipe larger in size than 2-in. nominal.

API RP14E recommends that 1 1/2-in. size fittings should be socket welded for hydrocarbon service above ANSI 600, hydrocarbon service above 200°F, hydrocarbon service subject to vibration, and glycol service. It also recommends that 2-in. and larger piping should be flanged with butt-weld fittings when in hydrocarbon or glycol service. Threaded fittings should be avoided in all applications where mechanical vibration (pumps and compressors) or cyclic thermal variations occur.

For most hydrocarbon service, ASTM A-106 Grade B seamless pipe or API 5L Grade B pipe is used with ASTM A105 flanges and threaded/socket-weld fittings; ASTM A-234 Grade WPB seamless, butt-weld fittings; ASTM A-193 Grade B-7 and A-354 Grade BC flange stud bolts; and ASTM A-194 Grade 2H nuts. In higher pressure where the pipe and fitting wall-thickness requirements become a cost factor (because of the extra weight of the steel), pipe and fittings manufactured to higher-strength steel specification and grade may be used. For example, if a design would require that 0.500-in. wall, A-106 Grade B pipe be used with A-234 Grade WPB seamless fittings, an API 5L Grade X65 pipe (say with a design wall thickness of 0.250 in. and companion grade butt-weld fittings) could be used to save wall thickness and weight, which would save cost for the materials. (Note: the higher-grade steel butt-weld fittings may cost slightly more than the more commonly available A-234 Grade WPB, but any cost differential is usually offset by the difference in physical weight saved—the price for carbon-steel pipe and fittings is essentially based on the weight of the steel.)

Most of the common Grade B steels are safe to operate down to –20°F. For colder-service conditions, A-106 and API 5L Grade B can operate to –50°F, if the maximum operating pressure is less than 25% of the maximum allowable design pressure, and if the combined longitudinal stress because of pressure, dead weight, and displacement strain is less than 6,000 psi. The common Grade B steels can be used in service to –50°F if the pipe and fittings are heat treated and Charpy impact tested. However, a number of other commonly available steel specifications and grades for pipe, flanges, valves, and fittings are available for low-temperature service without special testing. Some common steels available include ASTM A-333 Grade 1 (–50°F), A-334 Grade 1(–50° F), A-312 TP 304L (stainless steel, –425°F), and A-312 TP 316L (stainless steel, –325°F).

Pipe and butt-weld fittings in ASTM A-53 Grade B, A-106 Grade B, A-333 Grade1, and API 5L Grade B and the "X" grades (X42 through X65) are acceptable for H₂S service. Natl. Assn. of Corrosion Engineers (NACE) Standard MR-01-75, Sulfide Stress Cracking Resistant Metallic Material for Oil Field Equipment, Secs. 3 and 5, prescribes the requirements for steel pipe, valves, and fittings in such service.

Minimum Wall Thickness-Pipe and Fittings

The pressure and temperature requirements, and the chosen wall-thickness calculation formula, dictate the resulting pipe wall thickness required for the piping or pipeline design. The specification and grade of pipe and fitting materials selected for the design must be compatible with each other chemically (e.g., carbon content) so that the fittings can be welded to the pipe. In Sec. IX of the ASME Codes for Welding, base metals (pipe and fittings) have been assigned P-numbers and group numbers. Within the P-number groupings, ferrous base metals, which have specified impact test requirements, are classified in groups. The assigned P-numbers and group numbers are based essentially on comparable base-metal characteristics, such as composition, weldability, brazeability, and mechanical properties. The ASME/ANSI and ASTM material specifications for pipe and fittings will list the P-numbers and group numbers within the data. The group number and P-numbers for the materials to be welded should be compatible (see ASME Sec. IX, QW-420 to verify material compatibility). Typically, for most oil and gas production-facility and pipeline applications (Group 1), P-1 materials will be required. The various codes and standards may prescribe allowable tolerances for pipe-to-fitting thickness variances. The allowable operating pressure and temperature and wall thickness of the fitting must be compatible with the pipe design. The maximum allowable operating pressure and temperature of the weakest piping-system component will determine the maximum allowable operating pressure for the system.

In small diameter threaded piping systems, for mechanical strength, impact resistance, and corrosion resistance, the pipe should have at least a 0.25-in. wall thickness. For smaller pipe, it is recommended that 3/4-in. and smaller pipe be Schedule 160, 2 to 3 in. Schedule 80, and 4 to 6 in. Schedule 40. ANSI/ASME B31.3 recommends that 1 1/2-in. and smaller threaded pipe use a minimum Schedule 80 and 2 in. and larger use Schedule 40.

Branch Connections

Branch connections in piping systems must be designed for both pressure/temperature requirements and mechanical strength. Typically, a tee fitting should be used for branch connections unless the nominal branch pipe diameter is less than 1/2 of the nominal, main "run" pipe diameter. If a connection, other than a tee, is used for the branch, ANSI/ASME B31.3 requires that the branch connection be reinforced; a pipe coupling is used if the branch size is 2 in. or less and the branch is less than 1/4 of the diameter of the pipe run, or an integrally reinforced, pressure-tested branch fitting (such as a weld-o-let, thread-o-let, or socket-o-let) is used. Table 9.19 is an example branch-connection schedule that could be used to specify the proper choice of branch connection.

• 

  Table 9.19

Valves

There are several types of isolation valves that are used in hydrocarbon service applications, including ball valves, gate valves, plug valves, globe valves, butterfly valves, diaphragm valves, and needle valves. Table 9.20 describes some of the characteristics of the various isolation valves. Valves are designed and manufactured under many industry standards. For most hydrocarbon service, valves manufactured under API Spec. 6F standards are used. Valves are designed and manufactured with a variety of end connections, body and trim materials, seat and seal materials, and operators. Valves are rated in accordance with the ANSI and API pressure class systems: ANSI 150, 300, 400, 600, 900, 1,500, and 2,500 and API 6A 2,000, 3,000, 5,000, 10,000, 15,000, 20,000, and 30,000. Valves used on the wellhead are typically API valves built to the same pressure ratings as the API flanges, whereas valves used in the production facility and pipelines are most commonly ANSI flange rated.

• 

  Table 9.20

The options specified for isolation valves include:

• End connections: weld end, threaded (or screw) end, and flanged end (RF or RTJ).
• Body and trim: cast iron, ductile iron, carbon steel, stainless steel, and NACE.
• Seat and seal materials: PTFE, Fluroelastomer, Buna-N, Viton, Nylon, and others.
• Operator: lever, hand-wheel, gear, and automatic (extensions if needed).
• Fire safe rating: per API Spec. 6FA.
• Pressure rating: ANSI/ASME or API.
• Mounting: floating or trunion (ball and plug valves).
• Port configuration: full, reduced, or regular port (ball, gate, and plug valve).
• Seating: double or single seat (ball and gate valve).
• Double block and bleed: ball and gate.
• Sealant fittings: ball and plug valves.
• Rising or nonrising stem and inside or outside yoke: gate valves.

Refer to manufacturer’s literature for the various options available for specific valve types and their intended use.

The other type of valve commonly used is the check valve, which allows flow in one direction only. There are four types of check valves: swing, split disk, lift plug/piston, and ball. The swing check valve is suitable for nonpulsating flow and is not good for vertical-flow applications. The split-disk check valves are mounted between flanges (wafer configuration), but the operating springs are easily subject to failure. The lift-plug and piston check valves are good for pulsating-flow conditions—an orifice controls the plug or piston movement, and they are excellent in vertical flow conditions; however, the lift-plug/piston check valve can easily be cut out in sandy service and is subject to fouling with paraffin and debris. The ball check valve is typically used in 2-in. and smaller lines and can be used in vertical-flow applications, but it does have a characteristic of slamming shut upon flow reversal. Check valves are designed and manufactured under the same codes and standards as isolation valves. The pressure ratings, end connections, body materials, seals, etc. are the same as for isolation valves. Note: Check valves should never be substituted for a positive-shutoff isolation valve in any piping-system application. Under ideal service conditions, the best check valve in the perfect application will not guarantee a positive shutoff.

Control Valves and Pressure-Relief/Safety Devices

Automatic control valves and pressure-relief devices are an integral part of oil and gas facility and pipeline-system piping. Control valves typically are used to regulate pressure, temperature, and flow rate. Pressure-relief valves and devices prevent the piping system from exceeding the maximum allowable pressure. As piping-system components, control valves and pressure-relief valves come in a variety of configurations and materials and are rated in accordance with the ANSI and API pressure classes, flange ratings, and end connections. As with isolation and check valves, control valves and pressure-relief valves must be rated for the maximum allowable pressure of the interconnecting piping system.

Specification Pressure Breaks

Fluid flowing through a piping system can undergo pressure decreases by flowing through chokes and/or control valves. However, if flow were to stop, the pressure in the line would increase to the upstream pressure.

When fluid flows from a high-pressure source into a lower-pressure system, there is a distinct point where the system could be subjected to the higher pressure by activation of an isolation valve. This distinct point is called a specification "pressure break" point. Pipe valves and fittings upstream of this point must be designed to withstand the higher pressure.

The piping and equipment must be designed for the maximum possible source pressure that the system might experience. This means that any segment that can be isolated either intentionally or accidentally from a downstream relief device must be designed for the maximum upstream pressure to which it can be subjected. Typically, this "design" pressure will be set by the set pressure of an upstream relief device, or the maximum pressure that can be developed by the upstream source (pump, compressor, or wellhead). Because pressure breaks occur at isolation valves, careful placement of isolation valves must be considered in multipressure piping-system designs.

API RP14J, Design and Hazards Analysis for Offshore Production Facilities provides the following guidance for determining the proper maximum allowable pressure to use in designing a segment of a piping system and the location of specification breaks.

• Check valves may leak or fail open and allow communication of pressure from the high side to the low side. (Check valves should still be used to minimize backflow in case of a leak, but cannot be relied upon to prevent overpressure.)
• Control valves, including self-contained regulators, can be in either the open or closed position, whichever allows the piping segment to be exposed to the maximum pressure.
• Block valves can be positioned in either the open or closed position, whichever position creates the highest pressure.
• Locked open (or closed) valves can be considered always open (or closed), if the lock and key are maintained in accordance with a proper lockout and tagout procedure. A hazards analysis should be performed to determine if the risk associated with relying on the lockout/tagout procedure is justified.

High-pressure sensors alone do not provide sufficient protection from overpressure. The one exception is that API RP 14C allows the use of two independent isolation valves on production flowline segments (see the chapter on Safety Systems in this volume of the Handbook). This should be approached with caution after thorough consideration of other alternatives.

Pressure-relief valves and rupture discs will always work because of the high reliability of their design. (In critical service, some operators require a backup relief valve or rupture disc to the primary relief device to increase reliability or to provide a spare).

In checking for spec-break locations, it is easiest to start at a primary pressure-relief valve (one designed for blocked discharge) and trace the upstream piping (including all branches) to the first block valve or control valve. It is then assumed the valve is closed, and the line is followed further upstream (including all branches) to the next pressure-relief valve or the source of pressure. The piping from the first block valve to the upstream pressure relief valve or source of pressure should be rated for the setting of the pressure-relief valve or maximum pressure of the source if no pressure-relief valves are present. Each branch upstream of the first block valve should be pressure rated at this highest pressure at every location, where it can be isolated from any downstream pressure-relief valve.

Fig. 9.14 shows an example of spec-break locations determined in this manner. Fig. 9.15 shows how the spec breaks change if Valve 5 is added on the inlet to the low-pressure (LP) separator. Note: this changes the ratings of Valves B, D, and F in the manifold, as well as that of Valves 1 through 4 on the liquid outlet of the high pressure (HP) separator. Fig. 9.16 shows that the pressure rating of Valves 1 through 4 do not need to be changed if the location of Valve 5 is changed. Fig. 9.17 shows an alternative pressure rating scheme brought about by adding a relief valve upstream of Valve 5.

• 

  Fig. 9.14—Determination of pressure breaks. Example of spec break in accordance with API RP14J (courtesy of API).

• 

  Fig. 9.15—Determination of pressure breaks. Same example of spec break in accordance with API RP14J as Fig 9.14 except Valve 5 has been added on the inlet to the low-pressure separator and down-stream of the high-pressure dump line, which changes the ratings of Valves B, D, and F on the inlet manifold as well as Valves 1 through 4 on the liquid outlet of the high-pressure separator (courtesy of API).

• 

  Fig. 9.16—Determination of pressure breaks. Same example of spec break in accordance with API RP14J as Fig. 9.14 except this shows that the pressure ratings of Valves 1 through 4 do not need to be changed if Valve 5 is located upstream of the dump line from the high-pressure separator (courtesy of API).

• 

  Fig. 9.17—Determination of pressure breaks. Same example of spec break in accordance with API RP14J as Fig. 9.14 except this shows an alternative spec-break scheme by adding a relief valve upstream of Valve 5 (courtesy of API).

Pipe Expansion and Supports

Pipe Expansion

Steel piping systems are subject to movement because of thermal expansion/contraction and mechanical forces. Piping systems subjected to temperature changes greater than 50°F or temperature changes greater than 75°F, where the distance between piping turns is greater than 12 times the pipe diameter, may require expansion loops. ANSI/ASME B31.3 addresses the design requirements related to displacement strain because of thermal expansion, longitudinal sustained stresses, and computed displacement stress range.

Screening for expansion loops is not required by ANSI/ASME B31.3 if the piping system duplicates an existing system and can be readily judged as adequate by comparison to other piping systems and DY/(L–U) 2 ≤ 0.03, where D is the nominal pipe size in inches, Y is the expansion to be absorbed by the piping in inches, L is the length of the pipe segment in feet, and U is the straight-line distance between anchors).

In the majority of oil and gas facility and pipeline applications, pipe expansion is not critical, as normal piping arrangements contain the numerous elbows and changes of direction. These make the piping system relatively flexible and allow the pipe to absorb the expansion; however, if the flowing temperatures are high or there is a significant variation in temperature, the normal piping configuration may not be adequate to handle the expansion and contraction of the piping systems. The design must be checked to verify that the piping configuration will absorb the expansion and, if not, that expansion loop will be incorporated as needed.

The calculation of both actual and allowable stresses in piping systems subject to movement and large temperature changes is complex and requires special expertise. There are a number of good computer programs that calculate stresses in piping systems and compare them to the stresses allowed by the specific piping code.

Pipe-Support Spacing

The proper location and spacing of above-ground-pipe supports can be determined as follows:

1. Assume that the hoop stress in the pipe is equal to the allowable stress, S_h, for the material at the design temperature.
2. According to Poisson’s law, the axial stress can be no more than 0.3 S_h. The stress available for the bending moment is then 0.7 S_h.
3. As an approximation, assume 0.25 S_h is used for the moment caused by the pipe to allow for stress concentrations and occasional loads.
4. Assuming the pipe can be modeled as a fixed beam,

....................(9.35)

where

L	=	length between supports, ft,
Sh	=	allowable stress, psi,
Z	=	pipe-section modulus, in.3,
and
W	=	weight of pipe filled with water, lbm/ft.

Eq. 9.35 is merely a conservative approximation. A more liberal spacing can be determined by using one of the many pipe stress calculation programs.

Pipelines

Gathering Systems

The pipeline system that conveys the individual-well production or that of a group of wells from a central facility to a central system or terminal location is a gathering pipeline. Generally, the gathering pipeline system is a series of pipelines that flow from the well production facilities in a producing field to a gathering "trunk" pipeline.

Gathering systems typically fall into one of four categories:

1. Single-trunk systems with "lateral" lines from each well production facility.
2. Loop systems, in which the main line is in the shape of a loop around the field.
3. The multiple-trunk system, in which there are several main lines extending from a central point.
4. Combinations of Categories 1 through 3.

Selection of the most desirable layout requires an economic study, which considers many variables, such as the type of reservoir, the shape of the reservoir, the way in which the land over the reservoir is being used, the available and permissible flow rate, the flowing and shut-in pressure and temperature, the climate and topography of the location, and the primary destination of the oil or gas.

Gathering systems typically require small-diameter pipe that runs over relatively short distances. The branch lateral lines commonly are 2 to 8 in. Gathering systems should be designed to minimize pressure drop without having to use large-diameter pipe or require mechanical pressure-elevation equipment (pumps for liquid and compressors for gas) to move the fluid volume. For natural-gas gathering lines, the Weymouth equation can be used to size the pipe.

Transmission Pipelines

"Cross-country" transmission pipelines will collect the product from many "supply" sources and "deliver" to one or more end users. There are three general categories of transmission pipelines: natural gas, "product," and crude oil. Natural-gas transmission pipelines carry only natural gas. Product pipelines may carry a number of processed or refined petroleum products such as processed natural-gas liquids (e.g., butane and propane), gasoline, diesel, and refined fuel oils. Crude-oil pipelines convey unrefined crude oil from producing areas to large storage areas or directly to refineries. Transmission pipelines will generally require much larger pipe than gathering systems. Transmission systems normally are designed for long distances and will require pressure-boosting equipment along the route.

Onshore Pipelines

Many factors must be considered when designing, building, and operating a pipeline system. Once the basic pipe ID is determined using the applicable flow formula, the other significant design parameters must be addressed.

For U.S. applications, gathering, transmission and distribution pipelines are governed by regulations and laws that are nationally administered by the U.S. Dept. of Transportation (DOT). The regulations are contained in the Code of Federal Regulations (CFR) Title 49, Part 190 Enforcement Procedures, Parts 191 and 192 Natural Gas Pipelines, Part 193 Liquefied Natural Gas Pipelines, Part 194 Oil Pipelines Response Plans, Part 195 Hazardous Liquid Pipelines (e.g., crude oil and products), Part 198 State Grants, and Part 199 Drug Testing. The regulations incorporate the industry codes, guidelines, and standards including ANSI/ASME B31.4, B31.8, and others.

Internationally, many countries have adopted the U.S. regulations and the industry codes, guidelines, and standards. Some countries have different requirements, laws, and regulations, and each should be consulted prior to designing and building a pipeline. For the most part, these regulations are similar to those in the U.S., and, thus, the comments that follow, based on U.S. standards, are generally true in other countries as well. Even pipelines not specially covered by the regulations should be designed, constructed, and operated according to industry codes, guidelines, and standards, as these are based on sound engineering and operating experience.

Pipe Selection and Wall Thickness. The type of pipe and wall thickness must be determined for each application. Following the design requirements of Part 192 for natural gas, Part 193 for liquefied natural gas (LNG), and Part 195 for crude-oil and products pipelines, the pipe materials and wall thickness can be determined using the applicable formula. As discussed in Sec. 9.2, the operating pressure (maximum and normal), operating temperature, other design factors (depending upon the type of pipeline and applicable regulation), and the pipe material will determine the wall thickness.

PVC, fiberglass, polypropylene, and other materials may be used in low-pressure and utility applications. ANSI/ASME B31.4, B31.8, and the DOT regulations allow the use of alternative materials in very restricted applications. However, steel pipe will be required in the majority of the oil and gas production and pipeline applications. ANSE/ASME A53 and A106 and API 5L seamless, ERW, and submerged arc-welded (SAW) steel pipe are commercially available and most commonly used in pipeline systems. Seamless pipe is seldom used in pipeline applications because of the higher unit cost and limited availability. From a design and regulatory perspective, pipe made with ERWs and SAW seams is equivalent to seamless pipe and is less costly. Note: this is not true for piping systems designed in accordance with the ANSI/ASME Standard B31.3.

Typically, for high-pressure pipelines, higher-grade pipe (such as API 5L, Grades X42, X52, X60, and X65) is selected because much-thinner-wall pipe can be used, which significantly reduces pipe costs. Construction-costs savings also are realized, as the welding time is reduced and material shipping/handling costs are reduced.

Material Selection. Pipe fittings, flanges, and valves must meet the specification and pressure class of the pipe selected for pipeline applications. The materials for pipelines commonly conform to industry codes and standards including ANSI/ASME Standard B16.5, ANSI/ASME Standard B16.9, ANSI/ASME Standard B31.4, ANSI/ASME Standard A105, ANSI/ASME Standard A106, ANSI/ASTM Standard A234, ANSI/ASTM Standard A420, ANSI/ASTM Standard A694, API Standard 6D, API Standard 6H, MSS Spec. 44, and MSS Spec. 75. Pipe fittings can be matched to the higher grade API 5L, X Grade pipe. Detailed material information is discussed in Sec. 9.6.

Route Selection and Survey. Route selection is very important to successful pipeline design. Careful study of the terrain, natural obstacles (such as mountains, swamps, marshes, and rivers), manmade obstacles (such as highways, roads, railroads, and buildings), and population density is required. Topographic maps, aerial photography, satellite imagery, and property ownership maps, as well as physical inspection, are helpful aids in the routing process.

Constructability is an essential consideration when choosing the route. Typically, the minimum pipeline construction working right-of-way (ROW) for a 2-in. pipeline is 35 to 40 ft in width, and the working area should be reasonably level. Larger-diameter pipe requires wider ROW because the larger pipe requires bigger pipe-handling equipment (sidebooms), wider ditches and wider spoil piles. Eighty- to 100-ft wide construction working ROWs are typical for 4- to 12-in. pipe, and 200-ft plus construction ROW widths are common for pipe up to 30 to 36 in. The proposed route must be surveyed to determine the exact length of the proposed pipeline, determine the physical terrain, locate natural and manmade obstacles, and verify property boundaries. Once a workable route is confirmed, the acquisition of the ROW and regulatory permits begins.

ROW. The acquisition of private and public ROW and associated governmental permits is a major component of the pipeline process. Oil and gas leases often have provisions that allow the producer to install wells, flowlines, production facilities, and processing and storage facilities without having to acquire additional ROW or facility properties. However, producers do not have the right to cross public roads, highways, railroads, rivers, jurisdictional creeks/streams, wetlands, or pre-existing easements or ROWs. Gathering and transmission pipelines have to purchase the ROW, or easement, that is required for the pipeline system. Typically, easements, which grant the pipeline owner the right to operate and maintain the pipeline and appurtenant facilities, are purchased. In some instances, the ROW may be purchased "in fee" where the easement is acquired as a property.

Permits and Special Considerations. Permits are required to install pipelines across public highways, roads, streets, and any other public conveyance. The permits must be acquired from the federal, state, or local authority that has jurisdictional authority. Special easements or permits must be acquired from railroads and other pipelines as well.

There are special design requirements for pipe installed across the highways, roads, streets, and railroads, which are stipulated in ANSI B31.4, B31.8, and the DOT regulations. Heavier-wall pipe (required because of lower design derating factors), casing, hydrostatic and nondestructive testing and other special requirements are stipulated in the applicable regulations, codes, and industry standards.

Special installation requirements are common, as few highways, public roads, or streets, if any, can be open-cut and ditched. Railroads will not allow conventional, open-cut ditch installation. The pipeline must be installed by wet or dry boring methods, tunneling, or horizontal-directional-drilling (HDD) methods. These methods are described later.

Environmental requirements have a major impact upon the pipeline industry. Pipelines can not be constructed in certain defined wetlands, marshes, swamps, rivers, creeks, or streams where the pipeline installation and operation could affect sensitive ecologies and environments. In the U.S., the U.S. Army Corps of Engineers (COE) has the primary jurisdictional authority over these areas, and other federal agencies, such as the U.S. Fish and Wildlife Service, have secondary jurisdiction. All states now have environmental or similar agencies that also have jurisdiction in many of these areas. Internationally, many countries now have laws and regulations that protect the natural resources. Historically significant sites, archeological sites, endangered species, and many other related issues require investigation before finalizing the route selection. Special permits must be acquired to work in and around sensitive areas. In the U.S., permits from COE are required for crossing of rivers, navigable streams/creeks, wetlands, and other regulated waters.

The environmental and natural resource regulations and requirements not only apply to regulated gathering, transmission, and distribution pipelines but also apply to flowlines and production facilities constructed within oil and gas leases. The potential cost impacts of these issues must be given serious consideration in the pipeline design process.

Corrosion Prevention. Steel pipe and pipeline facilities must be protected from the effects of external and internal corrosion. Nonferrous piping materials, such as fiberglass, PVC, and polypropylene, do not undergo the same corrosive effects and require little attention. Industry codes and standards and the DOT regulations require that pipelines, appurtenances, and facilities be protected from the effects of corrosion. NACE has standards prescribing the corrosion protection required for pipelines—NACE Standard MR01-76, RP200, and RP572.

Internal Corrosion. Internal corrosion may be caused by the presence of CO₂, water, H₂S, chlorides (salt water), bacteria, completion fluids, or other substances in the produced hydrocarbon. When CO₂ or H₂S is mixed with oxygen and/or water, acids are formed that attack and destroy the steel. When CO₂ or H₂S is mixed with oxygen and/or saltwater, extreme corrosion occurs. Certain types of bacteria often found in producing formations can also attack and destroy the steel. Any of the internal corrosives, separately or in combination, can cause leaks and severe blowouts.

The potential corrosives usually can be identified from a chemical analysis of the produced hydrocarbons. In instances where high concentrations of CO₂, H₂S, or other highly corrosive chemicals are present, additional pipe wall thickness may be added in the pipe design to allow for the potential corrosive effects. This is not normally recommended, as corrosion could be localized and the rate difficult to predict. In most cases, the removal of oxygen and water from the fluid is sufficient to combat potential corrosion. Where this is not practical, corrosion-inhibition chemicals, internal coatings, and corrosion-resistant materials are used.

Internal corrosion also can be caused by erosion or wear. Excessively high velocities in liquid and multiphase fluid systems can erode or wear the internal pipe wall as well as fittings and valves. The conditions that cause mechanical erosion can be mitigated through proper pipe sizing and design.

The corrosive effects of the hydrocarbon fluid may change over time as the chemistry of the produced fluid changes or as bacteria develop that were not present earlier. Where unknown corrosives develop after operations have commenced, chemical treatment may be the best solution.

External Corrosion-Underground Piping. External corrosion affects buried pipe and above-ground pipe. Buried pipe is subjected to cathodic actions and galvanic actions. Above-ground pipe is subjected to atmospheric corrosion and galvanic actions.

Cathodic actions occur when steel pipe is buried below ground. Ferric and other materials, such as soils, have small electrical potentials. In the natural process of converting metals back to their elemental or native state, electrolytic conduction takes place. Unprotected, the steel pipe becomes an anode (positively charged) and transfers material, by means of electrons, to the cathode (negatively charged) material, which is the soil or surrounding medium. The pipe metal literally flows away by means of the electric current between the anode and cathode. Water contained in the soils and other media serves as the electrolyte to help promote the electron transfer.

To counteract cathodic actions, pipe is coated with anticorrosive materials and cathodic protection systems are placed on the pipeline. The coating must provide an effective "insulation" against the environment but must be tough enough to withstand the operating temperatures, be resistant to the soil, and withstand physical handling.

There are a number of coating systems that are economical and commercially available, which include extruded systems (polyethylene or polypropylene over asphalt mastic or butyl adhesives), tape coats (polyethylene, polyvinyl, or coal tar over butylmastic adhesive), fusion bonded epoxy (thin film), and coal-tar epoxy. Fusion bonded epoxy (FBE) coatings are the most popular coating systems because they are excellent insulators; are hydrocarbon, acid, and alkali resistant; are unaffected by temperature; do not require a primer; and can be applied over finished welds (field joint). Tape-coating systems and coal-tar enamel systems are becoming less and less popular. Tape coating is difficult to apply and is especially difficult to use on large-diameter pipe. A number of tape-coated systems have experienced failures over relatively short spans of time because of improper application. Coal-tar epoxy is becoming less desirable because of some health and environmental concerns caused during application.

In addition to the anticorrosion pipe-coating systems, cathodic protection systems are added to the pipeline to protect the pipe where breaks in the coating system occur. The cathodic protection system employs either an impressed current or sacrificial anode to protect the underground pipe. The cathodic protection system reverses the electrolytic conduction process and uses an impressed electrical current or another metal object (sacrificial anode) to make the pipe a cathode. In simplified terms, the impressed current reverses the natural flow of electrons from the pipe to the surrounding medium to prevent the loss of metal ions. The sacrificial anode made of a higher potential metal, such as magnesium, is in contact with the pipe and the surrounding medium. The anode gives up its electrons (metal) in place of the steel pipe.

Sacrificial-anode systems are simpler and less expensive than impressed current systems. Onshore pipelines generally use magnesium, and offshore pipelines use zinc or aluminum anodes. Impressed current systems are much more complex and require external power sources and AC/DC power inverters or rectifiers to provide the current to the pipe.

The design of cathodic protection systems requires specialized training and can be very complicated. Detailed soil surveys must be conducted to determine the electrical potential and resistivity of the soils or surrounding medium, pipe-to-soil potentials, and a number of other criteria. System design should be done by a cathodic protection expert.

Galvanic Corrosion. Another important facet of the anticorrosion system is prevention of galvanic corrosion. Galvanic corrosion is caused by the interface of dissimilar metals with different electrolytic potentials. The dissimilar metals will gain or lose electrons from or to each other resulting in one of the metals effectively flowing away and losing material. Steel pipe that undergoes abrupt changes in the medium will behave somewhat as dissimilar metals and cause galvanic actions. Pipe transitioning from below ground to above ground may experience galvanic-like corrosion. Mating materials such as carbon steel with stainless steel will cause the carbon steel to corrode.

Insulating flanges or joints can be used to counteract the effects of galvanic actions. Efforts should be made to avoid the interface of the dissimilar materials in the system design.

Atmospheric Corrosion. The effects of atmospheric corrosion are readily apparent. Bare steel exposed to moisture, salt, chemicals (pollution), heat, cold, or air (oxygen) will corrode rapidly. Piping and equipment exposed daily to the elements must be protected with anticorrosion coatings. Good paint coating systems, such as epoxies, and regular maintenance will normally provide adequate protection to the above-ground facilities.

Facilities exposed to severe service, such as offshore, may require more-extensive protection systems. There are a number of alternative coating systems that are discussed in the offshore pipeline section.

Welding and Pipe Joining. The methods used to connect the joints or pipe segments are very important and are critical to the pipeline design. ANSI/ASME Standards B31.3, B31.4, and B31.8, as well as the DOT regulations, specify welding and joining methods for pipe. Each type of pipe material has joining or coupling methods designed to ensure that the joint is as strong as, or stronger than, pipe joint. Fiberglass, PVC, and other types of plastic pipe may have bell- and spigot-type joints that are mechanical, threaded, or glued. Polypropylene and polyethylene pipe, which is used frequently in very-low-pressure hydrocarbon applications, use a fusion-welded joint. However, the majority of the hydrocarbon pipeline applications require steel pipe.

For the majority of steel pipeline applications, welding is the preferred method of joining the pipe. API Standard 1104 and ASME Sec. IX of the boiler and pressure vessel codes specify the requirements for the welding of steel pipe. Manual and automatic welding processes are used on pipelines both onshore and offshore. Shielded metal-arc welding (SMAW), or "stick" welding, is the most common manual process used on carbon-steel pipelines, but the development and use of higher-grade carbon-steel pipe (e.g., API 5L X65 and X70) have required the development of welding processes and metallurgy compatible with the high-carbon alloys. Stainless steels and other alloys may require special welding processes.

The development of reliable and economical automatic welding machines has had a significant impact on the pipeline industry as well. The automatic welders may be external or internal for large-diameter pipe.

Each weld joint must be designed and a welding procedure specification (WPS) developed for the pipe. Each WPS specifies the type of pipe to be welded (specification, grade, etc.), the type and specification the of the pipe joint [e.g., specify bevel(s), angle, shoulder, and spacing/alignment], the material thickness or range of thickness applicable, the type and size of welding rods, the position and direction of the weld, the voltage/amperage, pre-/post-heat, stress relieving, etc. The WPS must be physically proved by actually welding a test "nipple" and conducting destructive testing in accordance with the API and/or ASME requirements. Once the specification is proven, a procedure qualification record (PQR) is recorded verifying the WPS. Welders must be qualified to perform the welds in accordance with either API Standard 1104 or ASME Sec. IX. Each welder will perform a test weld using the WPS for the pipe and will qualify under the procedure. API Standard 1104, ASME Sec. IX, and DOT specify and define welder qualifications.

There are other acceptable methods for joining pipe. Steel pipe may be threaded and coupled or may have various mechanical joints. Threaded-steel-pipe application is generally limited to small diameters, 4 in. and less. Larger pipe is difficult to properly couple, and threaded line pipe in large diameter is not readily available. Fiberglass pipe used in the industry may be threaded or have solvent-welded joints. PVC may have solvent-welded joints or may have bell-and-spigot mechanical joints. Industry codes and standards, as well as DOT regulations, recognize the other joining methods but limit the use of pipe other than steel.

Pipeline Construction Process. Conventional, onshore pipeline construction process is described next.

ROW Clearing/Preparation. Before initiation of construction activities, any sedimentation, erosion control, construction fencing, and other preparation is completed. All vegetation is cleared and grubbed, topsoil is removed (if required), and the working ROW is graded.

Pipe Stringing. Once the ROW has been prepared, the pipe is loaded on flatbed trucks. Before unloading, pipeline skids (typically 4-in. × 6-in. × 4-ft hardwood timbers) are dropped along the ROW to be placed under the pipe. The trucks are driven down the ROW, and the pipe is unloaded, joint by joint/end to end, by sidebooms or cranes.

Ditching. The ditch is excavated along the pipeline centerline using ditching machines, excavators, backhoes, and other excavation equipment. Pipelines are normally buried with a minimum of 36 in. of cover (DOT regulatory requirement). In consolidated rock, the minimum cover varies between 18 and 24 in. The cover for Class 1 locations is 18 in.; the cover for Classes 2 to 4 (railroads, highways, and public roads) is 24 in.

Welding. The pipe strung along the ROW is welded in a progressive manner. Sidebooms will work along the ROW lifting the pipe while a crew aligns the pipe in preparation for the "stringer bead" weld. Generally, a welder or welders (depending upon the size of the pipe) will work with the alignment crew, align the pipe, and apply the initial weld "bead." A group of welders will follow immediately behind the stringer welder(s) and apply the "hot pass" bead or seal weld. Additional welders will follow to apply the final passes of weld material.

Field Joint and Anticorrosion Coating and Inspection. When the welding is completed, field joint crews clean the weld areas and the short, adjacent bare steel on either side of the weld, and apply the field joint coating. Any nondestructive testing of the welds, such as X -ray, will be completed before application of the field joint coating. Following the completion of the field joint coating, the pipe is inspected with "holiday" detection equipment (low-voltage DC equipment that shows where the pipe coating and field joints have failures or breaches), and anomalies and breaches in the coating are repaired.

Pipe Lowering. Upon completion of the field joint application and coating inspection, the pipe is lowered and placed into the ditch by sidebooms or other lowering equipment.

Backfill, Cleanup, and Restoration. Following completion of the pipe lowering, the ditch is backfilled, and the ROW is cleaned and dressed. The ROW is finely dressed, grass and vegetation replanted, and any special remediation measures or cleanup requirements are completed.

Highway, Road, Railroad, and River Crossings. Highway, road crossings are seldom installed using conventional, open trench methods. Typically, these crossings are installed using a wet bore or dry bore method. The boring is done by rigs that are similar to very small drilling rigs, laid horizontally, and placed in pre-excavated boring level "pits." The boring rig drills underneath the crossing area, and the pipe or casing is installed. The wet method uses a boring rig and circulates water or drilling fluid through a drill stem to open a small pilot hole, then pulls a pipe or casing-sized cutting head back to the rig, cutting a hole large enough to place the pipe or casing. The dry bore method is similar, but the casing or carrier pipe is fitted with a cutting head and is used to drill the hole and is left in place when the drill is completed. The hole is drilled dry and does not use any water or fluid to assist the drilling operation. Railroad crossings are never open cut and are always bored. Typically, railroads require that the borings be made with the dry bore method. Both wet and dry bore methods are limited on the distance that they are effective and practical.

River crossings are now typically installed using the HDD method. Open-cut trenching of rivers may be allowed by the U.S. Corps of Engineers, but HDD installations have become more economical. The HDD method uses a computer-controlled rig that controls a directional wet-bore pilot drill that can be accurately steered from the rig. The directional drill can bore a pilot hole up to a mile or more and ream a hole back to the rig large enough to install the carrier pipe. The "drill" string or pull section of pipe is welded together on the drill exit side, pretested, then pulled back to the rig side following the backreamer.

The HDD method may be used to install long highway and road crossings, such as interstate highways and freeways. The wet- and dry-bore methods are limited to several hundred feet in length, which requires multiple borings to cross the distances typically required to cross interstate highways and freeways.

Tie-ins. A crew, or crews, is typically deployed that makes all pipeline tie-ins along the construction corridor. The tie-in crew makes the final welds at junctures where the progressive welding cannot make the final welds. Tie-ins are made at locations such as highway, road, railroad, and river and creek crossings and at drag sections, etc. The tie-in crew typically has excavation and pipe handling equipment and dedicated welders.

Construction Details. Figs. 9.18 through 9.28 illustrate typical construction details. The Occupational Safety and Health Admin. (OSHA) is an agency under the DOT and provides additional federal rules and regulations concerning the design, construction, and testing of pipelines.

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  Fig. 9.18—Typical cased railroad-crossing ROW (courtesy of AMEC Paragon).

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  Fig. 9.19—Typical cased highway/road-crossing ROW (courtesy of AMEC Paragon).

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  Fig. 9.20—Typical details for casing seal, insulator, and vent piping for Figs. 9.18 and 9.19 (courtesy of AMEC Paragon).

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  Fig. 9.21—Typical details for pipeline burial (courtesy of AMEC Paragon).

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  Fig. 9.22—Typical details for minimum clearance between multiple pipeline crossings (courtesy of AMEC Paragon).

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  Fig. 9.23—Typical details for pipeline coating in transition area, just below and just above grade elevations (courtesy of AMEC Paragon).

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  Fig. 9.24—Typical uncased highway/road-crossing ROW (courtesy of AMEC Paragon).

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  Fig. 9.25—Typical uncased small-stream-, canal-, or ditch-crossing ROW (courtesy of AMEC Paragon).

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  Fig. 9.26—Various types of density anchors and conventional mechanical anchor (courtesy of AMEC Paragon).

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  Fig. 9.27—Typical set-on reinforced-concrete pipeline weights (courtesy of AMEC Paragon).

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  Fig. 9.28—Typical natural-gas pipeline warning sign for installation at railroad, highway/road, ditch crossings, property lines, etc. (courtesy of AMEC Paragon).

Offshore Pipelines

Offshore pipeline design differs primarily in the requirements of the environment and the installation process. Pipe used in offshore applications is subjected to high bending stresses—potential crushing forces on pipe installed in deep water and a low-density environment. Until recently, the pipeline size was severely limited, but technological developments and improved construction methods have enabled offshore pipelines to continue to increase in size and capacity. Pipelines are being constructed in deeper and deeper waters. Pipelines up to 28-in. diameter are now being installed in the deepwater applications up to 7,000 ft of water.

Design. The piping materials used in the offshore pipelines are essentially the same as those used in onshore pipelines. When a pipeline is designed according to ANSI/ASME Standard B31.8, a 0.72 design factor is used for most of the pipeline wall-thickness calculation, and a 0.50 design factor is used in the riser pipe and often the first 300 ft of pipe adjacent to the riser. Pipe greater than 10-in. nominal size installed in low-density saltwater will generally tend to float. Sometimes this can be overcome by using more wall thickness than otherwise necessary to make the pipe heavier. It is normally more economical to use a concrete weight coating or to lay the line wet to get the required on-bottom stability. Generally, pipe is designed to have a specific gravity of 1.35.

The pipe has to be designed with enough wall thickness to handle the internal operating pressure, the bending stresses, and the external crushing forces. High-strength, high-grade pipe, such as API 5L Grade X65 and greater, is often used for construction, structural, operational, and economical considerations.

The minimum bending radius calculation for concrete coated pipe is expressed in Eq. 9.36.

....................(9.36)

where

R	=	bending radius, in.,
E	=	modulus of elasticity for concrete = 3,000,000 psi,
C	=	pipe radius + enamel thickness + concrete thickness, in.,
and
SB	=	2,500 psi.

The minimum bending radius for steel is expressed as

....................(9.37)

where

SY	=	pipe specified minimum yield strength, psi,
P	=	design pressure, psi,
D	=	pipe OD, in.,
t	=	pipe wall thickness, in.,
R	=	bending radius, in.,
E	=	modulus of elasticity for steel = 30,000,000 psi,
C	=	pipe radius, in.,
and
f	=	stress factor: use 75 to 85% for offshore design.

In deep water, computer programs are available to calculate the tension that must be kept on the pipe to maintain an acceptable bending radius. This is a complex calculation and must take into account the specific capabilities of the lay barge. In deep water, laying stresses and collapse stresses may determine the wall thickness. In addition, buckle arrestors may be required to restrict the length of a buckle, should one be caused by an installation problem (e.g., loss of adequate tension).

Construction. Offshore pipelines are constructed using lay barges or special ships. Each operation of the pipeline construction process, with the exception of pipe burial, takes place on the lay barge. Pipe is stored, prepared, welded, field joint coated, inspected, and lowered from the lay vessel. The pipe is lowered from the rear of the barge using a sophisticated system of dynamic positioners, rollers, cable tensioners, floats, and a long, adjustable boom or stinger. The pipe is strung out behind and below the lay barge and assumes an S-shape or J-shape. In an S-lay, the pipe is made up horizontally on the barge allowing for several welding stations. The pipe leaves the barge over a stinger that controls the curvature of the "overbend." Tension in the barge anchors controls the radius of curvature of the "sag bend", which returns the pipe to horizontal on the seafloor. In very deep water, it is no long possible to control the overbend with a stinger and, thus, a J-lay is used where the pipe leaves the barge vertically. A J-lay requires a tower on the barge to hold a length of pipe while all the welding is done at one location.

No matter which system is used, the pipe experiences tremendous bending forces caused by the weight of the pipe, the motion of the vessel, and the radius of the bends. The radius is controlled by tensioner systems. The pipe must be designed so that stress, caused by axial tension and bending moment, is within allowable limits.

The rate of progress of the lay, the roughness of the sea, and other factors can cause the pipe to buckle. The deeper the lay, the greater is the potential to buckle the pipe. Pipe can be laid in shallow water, 50 ft or less, with a spud barge or jack-up barge. The spud and jack-up barges operate in a fashion similar to the lay barge.

Pipe burial is performed with a plow or a jet. Plows are used in deep water and denser clays and can be used concurrently with the lay barge. Jet systems can be used in water up to depths of approximately 300 ft. Divers can hand jet a pipe in shallower waters, but more often, a jetting machine is used to bury the pipe after it is laid. In shallow waters (50 ft or less), a dredge can be used to excavate the pipe trench.

In the U.S., the minimum cover required over the pipeline, in depths up to 200 ft, is 36 in. There is no requirement for pipe burial in water deeper than 200 ft. Typically, pipe is buried with 5 ft of cover for the first 300 ft outward from the platform riser, 16 1/2 ft in anchorage areas, and 10 ft in fairways. Foreign pipelines are generally crossed over, and it may be necessary to lower the foreign line. A minimum of 18-in. separation must be maintained, and often rubber coated, articulated concrete mats are placed between the lines.

Corrosion Control. The same corrosion protection and cathodic protection principles that apply to onshore pipelines also apply to offshore pipelines. The line pipe is typically coated with an FBE or similar system, and if additional weight is needed, it will have an overcoat of concrete.

Above-water piping is typically coated with a multicoat epoxy paint system. A special section of pipe with a vulcanized rubber coating bonded to the pipe, "Splashtron," is often used in the highly corrosive splash zone at the water/air interface.

Sacrificial zinc or aluminum anodes are mounted to the pipe in a bracelet configuration. The anodes are typically designed for a minimum 20-year service life. It is very difficult to design and maintain an impressed current system on a long offshore pipeline.

Pipeline Pigging

Pipeline pigs are devices that are placed inside the pipe and traverse the pipeline. Pigs may be used in hydrostatic testing and pipeline drying, internal cleaning, internal coating, liquid management, batching, and inspection. Fig. 9.29 shows several types of pipeline pigs.

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  Fig. 9.29—Types of pigs (courtesy of AMEC Paragon).

Pigs are used during hydrostatic testing operations to allow the pipeline to be filled with water, or other test medium, without entrapping air. The pig is inserted ahead of the fill point, and water is pumped behind the pig to keep the pipe full of water and force air out ahead of the pig. Pigs are then used to remove the test waters and to dry the pipeline.

Operations may conduct pigging on a regular basis to clean solids, scale, wax buildup (paraffin), and other debris from the pipe wall to keep the pipeline flow efficiency high. In addition to general cleaning, natural-gas pipelines use pigs to manage liquid accumulation and keep the pipe free of liquids. Water and natural-gas liquids can condense out of the gas stream as it cools and contacts the pipe wall and pocket in low places, which affects flow efficiency and can lead to enhanced corrosion.

Pigs are used in product pipelines to physically separate, or "batch," the variety of hydrocarbons that are transported through the line. Product pipelines may simultaneously transport gasoline, diesel fuel, fuel oils, and other products, which are kept separated by batching pigs.

Crude-oil pipelines are sometimes pigged to keep water and solids from accumulating in low spots and creating corrosion cells. This can be especially necessary when flow velocities are less than 3 ft/sec. Multiphase pipelines may have to be pigged frequently to limit liquid holdup and minimize the slug volumes of liquid which can be generated by the system.

Pigs may be used to apply internal pipe coatings, such as epoxy coating materials, in operating pipelines. Pigs may also be used with corrosion inhibitors to distribute and coat the entire internal wetted perimeter.

Pigs are being used more frequently as inspection tools. Gauging or sizing pigs are typically run following the completion of new construction or line repair to determine if there are any internal obstructions, bends, or buckles in the pipe. Pigs can also be equipped with cameras to allow viewing of the pipe internals. Electronic intelligent, or smart, "pigs" that use magnetic and ultrasonic systems have been developed and refined that locate and measure internal and external corrosion pitting, dents, buckles, and any other anomalies in the pipe wall.

The accuracy of location and measurement of anomalies by the intelligent pigs has continued to improve. Initially, the electronics and power systems were so large that intelligent pigs could be used only in lines 30 in. and greater in size. The continued sophistication and miniaturization of the electronic systems used in the intelligent pigs has allowed the development of smaller pigs that can be used in small-diameter pipelines. Newly enacted DOT pipeline-integrity regulations and rules acknowledge the effectiveness of the intelligent pigs and incorporate their use in the pipeline-integrity testing process.

Pig Launchers and Receivers

Pigging facilities and considerations should be incorporated into the pipeline system design. Basic pigging facilities require a device to launch the pig into the pipeline and a receiver system to retrieve the pig as shown in Fig. 9.30. The launcher barrel is typically made from a short segment of pipe that is one to two sizes larger than the main pipeline and is fitted with a transition fitting (eccentric reducer) and a special closure fitting on the end. The barrel is isolated from the pipeline with full-port gate or ball valves. A "kicker" line, a minimum of 25% capacity of the main line, is tied from the main pipeline to the barrel, approximately 1 1/2 to 2 pig lengths upstream of the transition reducer, to provide the fluid flow to "launch" the pig into the pipeline. The barrel is fitted with blowdown valves, vent valves, and pressure gauges on the top and drain valves on the bottom. The length of the barrel is determined by the length and number of pigs to be launched at any one time. Receivers have many of the same features.

• 

  Fig. 9.30—Typical sphere launcher and receiver traps (courtesy of AMEC Paragon).

A typical hinge-type closure for pig launching and receiving traps consists of a forged hub, a hinged blanking head, split-yoke clamps, operating bolts, and a self-energizing O-ring gasket. Materials of construction are in accordance with ASTM specifications and manufacture complies with applicable rules of the ANSI code for pressure piping and with the ASME boiler and pressure vessel code. Most important is the pressure warning safety device with yoke positioning plate. This safety device provides visual and mechanical assurance that the yokes are in the correct position over the head for commencement of operations. Additionally, the devices serve the purpose of alerting the operator to any residual pressure in the pig launcher or receiver trap should he inadvertently attempt to open the closure before all pressure has been relieved. A pressure warning device is located at each of the yoke splits with one of the positioning lugs attached to each yoke half. Tightening the holding screw on the nipple provides a seal and locks the hinged positioning plate on the positioning lugs. Loosening the holding screw breaks the seal and provides a means by which the operator can determine whether the pig launcher or receiver trap has been completely relieved of internal pressure. Continued loosening of the hold screw will allow disengagement of the positioning plate from the positioning lugs, permitting the yoke halves to be spread and the closure to be opened. There are several manufacturers of end closures, but most often Tube Turns or Modco closures are used worldwide.

Elbows and pipe bends installed in the pipeline should have a minimum radius of three times the main-line pipe diameter—3D bends. Intelligent pigs may require greater radius to diameter elbows and bends because of the longer length of the pigs. Tees installed in the pipeline with an outlet size 75% of the main-line ID should be equipped with bars across the tee outlet to prevent the pigs from attempting to turn into the tee and lodging in the line. Hot taps greater than 6-in. diameter added to the pipeline should be barred. If possible, tees should not be installed adjacent to one another. Check valves should be full open, and the pigs or spheres should be sized such that the pig or sphere is larger than the "bowl" cavity of the check valve.

Pig Selection

Pig runs of between 50 to 100 miles are normal, but pig runs exceeding 200 miles should be avoided as the pig may wear and get stuck in the line. Cleaning pigs may be constructed of steel body with polyurethane cups or discs and foam pigs with polyurethane wrapping, solid urethane disc, and steel body with metallic brushes. Drying pigs are usually low-density foam or multicup urethane. The intelligent pigs may be magnetic flux leakage, ultrasonic, elastic/shear wave, transponder/transducer, or combinations thereof. Internal-coating pigs are generally multicup urethane type. Batching pigs are typically bidirectional, multidisk rubber, which maintain efficiency up to 50 miles. Pigs used for obstruction inspection are typically urethane, multicup type fitted with an aluminum gauge plate or a gel type.

Spheres are generally sized to be approximately 2% greater diameter than the pipe internal diameter. Cups and discs are typically sized to be 1/16 to 1/8 in. larger in diameter than the pipe ID. Foam pigs have to be significantly oversized. Foam pigs 1 to 6 in. in diameter should be oversized by 1/4 in.; foam pigs 8 to 16 in. in diameter should be oversized 3/8 to 1/2 in.; foam pigs 18 to 24 in. in diameter should be oversized 1/2 to 1 in.; and foam pigs 28 to 48 in. in diameter should be oversized 1 to 2 in.

Slug Catchers

The receiving end of the pipeline should have surge containment to accommodate the slugs of liquid carried by the pigs. For liquid lines, additional storage capacity (tankage) will provide surge containment. Gas and multiphase lines need specially designed "slug" catcher systems to handle the intermittent liquid slugs generated by the pigging activities. When a normal gas flow is pushing the pig through a gas pipeline, the velocity can be quite large and the flow rate of liquids being pushed ahead is given by

....................(9.38)

where

QL	=	liquid-flow rate in front of the pig, B/D,
Qg	=	gas-flow rate behind the pig, MMscf/D,
T	=	temperature, °R,
P	=	line pressure, psia,
and
Z	=	compressibility factor, dimensionless.

In most systems, the instantaneous liquid-flow rate and "energy" surge ahead of the pig will exceed the processing design capacity and capability of the receiving facility. The slug catcher provides excess storage capacity within the receiving facility and helps dissipate the excess energy generated by the high-velocity liquid slug. The basic slug catcher is essentially a liquid-separation system where the incoming liquid enters a larger-diameter pipe or a vessel, which provides additional volume for the liquid surge and provides for separation of the vapor from the liquid stream. The additional volume provided by the slug catcher reduces the stream velocity and dissipates the excess energy produced by the liquid slug.

Another typical slug-catcher design employs an inline liquid header system attached to a series of horizontal liquid accumulators which may be several hundred feet in length. The liquid-slug stream enters the header and disperses into the accumulators, while the gas continues through the system and exits at the vapor-outlet collection header. The slug catcher may incorporate vortex breakers or other impingement devices to slow the liquid and mist extractors at the vapor outlet to capture entrained liquids. The liquid is transferred from the accumulators to the facility processing or storage. Fig. 9.31 shows an example slug-catcher design.

• 

  Fig. 9.31—Typical slug catcher for two-phase flow-front elevation (courtesy of AMEC Paragon).

• 

  Fig. 9.31 (continued)—Typical slug catcher for two-phase flow-front elevation (courtesy of AMEC Paragon).

The volume of the slug catcher is expressed as

....................(9.39)

where

(Vol)SC	=	volume of slug catcher, bbl,
Vol	=	volume of liquid holdup, bbl,
and
Qd	=	design liquid dump rate from the slug catcher, B/D.

....................(9.40)

where T_R = time during which slug is processed, in days. The volume of the slug catcher should be designed with a minimum 25% safety factor.

Hydrostatic Testing and Nondestructive Testing and Inspection

Each pipeline system must be tested and inspected to ensure that the system can be operated safely. DOT regulations specify testing and inspection requirements as well as ANSI/ASME Standard B31.3, B31.4, and B31.8 and API Standard 1104, 571, and 574.

Hydrostatic Testing

The DOT regulations, Part 192, Subpart J, paragraph 192.501 to 192.517; Part 193, Subpart D, paragraph 193.2319 and 193.2323; and Part 195, Subpart E prescribe the pressure-testing and strength-testing requirements for natural-gas, LNG, and hazardous-liquids pipelines, respectively. The ANSI/ASME and API standards also prescribe testing requirements. Pneumatic testing is allowed for certain low-pressure pipeline systems, but the majority of pipelines are tested with water.

Before to conducting the hydrostatic testing, a profile of the test section should be developed showing the maximum and minimum elevations, the maximum allowable working pressure (MAWP) determined at the lowest elevation point, the location of the fill and pressure pump, minimum pressure required at the pressure pump determined by the maximum pressure at the lowest elevation, and water-source quality and discharge/disposal point. The profile of the test segment provides a graphical representation of the test segment, which helps the testing engineer determine the location of air bleed vents and the fill rate and pig velocity required to prevent air entrapment, and verify that the test will not overpressure or underpressure the pipe in the segment. The elevation differential can become a major consideration. When radical changes in elevation occur over short distances, it may be necessary to subdivide the original segment into shorter test segments. Each 100 ft of elevation difference represents approximately 43.3 psi of pressure differential, which can result in high points being underpressured and low points being overpressured during the test. The test profile is also used to document the location of the fill pump, the test pump, the dead-weight gauge, and the pressure/temperature recording equipment. Fig. 9.32 illustrates is a typical test profile segment.

• 

  Fig. 9.32—Pipeline integrity testing-elevation vs. station number (courtesy of AMEC Paragon).

The typical testing equipment that is needed to conduct the hydrostatic test is a temporary fill manifold complete with valves (pressure rated at a minimum of 1.5 times the maximum test pressure), dewatering manifold complete with valves (also pressure rated at a minimum of 1.5 times the maximum test pressure), foam or urethane pigs, low-pressure/high-volume fill pump with filtration equipment, high-pressure positive-displacement pump, certified dead-weight gauge(s), chart-type pressure recorder, chart-type temperature recorder for the water, chart-type temperature recorder for ambient air, pressure gauges rated at 50 to 75% of the maximum test pressure, compressed air or nitrogen source for dewatering, and discharge water filtration equipment. Temporary water-storage or holding tanks may be needed to supply reserve test water or serve as holding or settlement devices for dewatering.

Nondestructive Testing. Nondestructive testing and inspection of the welds is required by the DOT regulations Part 192, Subpart E, paragraph 192.243 for natural-gas pipelines; Part 193, Subpart D, paragraph 193.2321 for LNG lines; and Part 195, Subpart D, paragraph 195.234 for hazardous-liquid lines. ANSI/ASME Standards B31.3, B31.4, and B31.8 also prescribe nondestructive requirements.

Inspection. Each of the regulations and industry codes requires visual inspection of welds and construction process.

Instrumentation and Control

Pipeline control systems may consist of simple devices such as automatic pressure-control valves to the sophisticated total supervisory-control-and-data acquisition (SCADA) control system. The SCADA system can monitor and control, on a real-time basis, an entire pipeline system. The SCADA system can open and close valves, start and stop pumps/compressors, monitor and control flow, sample the product, monitor and regulate pressures and temperatures, and perform many other functions. SCADA systems are typically neither needed nor practical for small, gathering pipeline systems.

Compressor stations, pump stations, and related facilities may require emergency isolation equipment to protect the pipeline. Emergency-shutdown (ESD) systems consist of automatic shutoff isolation valves located at the main inlet and outlet to the stations/facilities and coordinated pressure-relief systems between the isolation valves. The ESD system protects both the pipeline and facility by stopping the flow into and out of the facility and limits the feed source in the event of fire, explosion, or other emergency.

Basic pipeline instrumentation includes strategically located pressure gauges and pressure-monitoring instruments, temperature gauges and monitoring instruments, and pressure control/limitation and relief equipment.

Nomenclature

A	=	cross-sectional area of pipe, ft2
C	=	pipe radius, in.
CV	=	flow coefficient for liquids, dimensionless
d	=	pipe inside diameter, in.
dO	=	outside diameter of pipe, in.
D	=	pipe diameter, ft
E	=	efficiency factor
f	=	Moody friction factor, dimensionless
F	=	design factor
g	=	gravitational constant, ft/sec2
HL	=	head loss, ft
HS	=	hoop stress in pipe wall, psi
Kr	=	resistance coefficient, dimensionless
L	=	length, ft
Le	=	equivalent length
Lm	=	length, miles
P	=	internal pressure of the pipe, psi
P1	=	upstream pressure, psia
P2	=	downstream pressure, psia
Qd	=	design liquid dump rate from the slug catcher, B/D
Qg	=	gas-flow rate, MMscf/D
Ql	=	liquid-flow rate, B/D
R	=	gas/liquid ratio, ft3/bbl
S	=	specific gravity of gas at standard conditions, lbm/ft3 (air = 1)
SB	=	2,500 psi
SG	=	liquid specific gravity relative to water
Sh	=	allowable stress, psi
SY	=	pipe specified minimum yield strength, psi
t	=	pipe wall thickness, in.
te	=	corrosion allowance, in.
tth	=	thread or groove depth, in.
T	=	gas flowing temperature, °R
T1	=	temperature of gas at inlet, °R
Tol	=	manufacturer’s allowable tolerance, %
TR	=	time during which slug is processed, days
U	=	straight-line distance between anchors
V	=	flow velocity, ft/sec
V	=	maximum allowable velocity, ft/sec
V1‘	=	specific volume of gas at upstream conditions, ft 3 /lbm
Vg	=	gas velocity, ft/sec
Vol	=	volume of liquid holdup, bbl
(Vol)SC	=	volume of slug catcher, bbl
w	=	rate of flow, lbm/sec
W	=	weight of pipe filled with water, lbm/ft
Y	=	derating factor
Z	=	compressibility factor for gas, dimensionless
γ	=	kinematic viscosity, centistokes
ϕ	=	absolute viscosity, cp
ΔhW	=	pressure loss, inches of water
ΔP	=	friction pressure drop, psi
ΔPZ	=	pressure drop because of elevation increase in the segment, psi
ΔZ	=	increase in elevation for segment, ft
μ	=	viscosity, cp
μc	=	viscosity of the continuous phase of the mixture, cp
μeff	=	effective viscosity, cp
ρ	=	density, lbm/ft3
ρM	=	density of the mixture, lbm/ft3

References

SI Metric Conversion Factors

°API		141.5/(131.5 + °API)		=	g/cm3
bbl	×	1.589 873	E – 01	=	m3
cp	×	1.0*	E – 03	=	Pa•s
ft	×	3.048*	E – 01	=	m
ft2	×	9.290 304*	E – 02	=	m2
ft3	×	2.831 685	E – 02	=	m3
°F		(°F – 32)/1.8		=	°C
in.	×	2.54*	E + 00	=	cm
in.3	×	1.638 706	E + 01	=	cm3
lbf	×	4.448 222	E + 00	=	N
lbm	×	4.535 924	E – 01	=	kg
mile	×	1.609 344*	E + 00	=	km
psi	×	6.894 757	E + 00	=	kPa

*

Conversion factor is exact.