138

138

Natural Gas Transmission -Introduction Worldwide and regional systems of natural gas pipeline Types of pipelines

Gathering systems Transmission lines Process facility lines

Pigging Slug Catching

The growth of natural gas transport by pipeline has led to the establishment of a large network of pipelines throughout the world. The total length of worlds pipeline is amounted to millions of kilometers. TransCanadas Alberta System is a natural gas transmission system that gathers natural gas for use within the province and delivers gas to provincial boundary points for connection with the Canadian Mainline, BC System and other pipelines. The 22,700 kilometer Alberta System is one of the largest carriers of natural gas in North America. The Alberta System delivered 4,146 billion cubic feet (Bcf) of natural gas in 2002. The volumes transported by the Alberta System in 2002 represented approximately 17 per cent of total North American natural gas production and about 68 per cent of the natural gas produced in the Western Canada Sedimentary Basin (WCSB). TransCanada's also owns the Mainline System which extends 14,900 kilometers from the Alberta/Saskatchewan border east to Quebec/Vermont and connects with other natural gas pipelines in Canada and the U.S. Annual deliveries of natural gas on the Canadian Mainline totaled 2,630 billion cubic feet (Bcf) in 2002. The Maritimes & Northeast Pipeline (Maritimes) is the transportation facility delivering natural gas from the Sable Offshore Energy Project to markets in Atlantic Canada and the Northeast United States. Maritimes & Northeast Pipeline main pipeline was built in 1999 to bring natural gas to markets in the Maritimes and Northeastern United States from six developed natural gas fields 160 kilometres off the East Coast of Nova Scotia. The Maritimes pipeline system consists of an approximately 670-mile underground mainline pipeline running from Goldboro, Nova Scotia through Nova Scotia and New Brunswick to the Canadian - U.S. border near Baileyville, Maine. The pipeline continues through Maine and New Hampshire into Massachusetts where it connects with the existing North American pipeline grid at Dracut, Massachusetts. The Blue Atlantic Transmission System proposes to construct and operate a 1,000+-mile pipeline system to deliver 1 billion-standard-cubic-foot-per-day (1 Bscfd) offshore natural gas including gathering and transportation systems to collect natural gas from proposed production facilities along the Scotian Shelf for subsequent processing (treatment and compression) in Nova Scotia. Processed natural gas and natural gas liquids would be available for use in Nova Scotia and for transport to markets in the northeastern United States.

A pipeline transport system contains the following main steps: (a) Collection of streams from the wells (gathering systems); (b)Processing of the produced gas to meet transport specifications; (c) Compression of the gas if the pressure is lower than required for transmission; (d) Pipeline transport; (e) Recompression during transport, if the distance is long to counteract theeffect of pressure drop; (f) Further treatment, if necessary, to adjust the gas to the distribution specifications; (g) Storage and transport to distribution grid; and (h) Gas distribution.

Generally, flow in transmission lines is gas phase only, although some offshore pipelines are two-phase flow. Field gathering lines are generally shorter than transmission lines and often the flowing gas contains liquid hydrocarbon. And/or liquid water and even minor amounts of solids.

Therefore there are two basic types of gas pipelines: gathering systems and transmission lines. Piping on platforms and in gas processing facilities continues a third type of gas flow line from a design standpoint.

In a pipeline systems two common terms are used very frequently: pigging and slug catching. Flow line pigs or scrapers are devices to remove condensate and solids from transmission lines, as well as to inspect such lines. Slug catchers are special piping arrangements used to catch large slugs of liquid in multiphase flow, to hold these slugs temporarily, and then to allow them to flow into down stream equipment and facilities at a rate at which the liquid can be properly handled. Two flow situation cause liquid slugging. The first is high gas flow rate with an intermediate liquid rate. Instead of simply running along the bottom of the pipe, the liquid is caught up as slugs, propelled by the fast-moving gas. The second slugging situation occurs when pigs are used to increase the efficiency of wet gas lines.

139

139

Piping systems

Introduction Fluid transport lines gas vs. liquid lines Manifolds and fluid distributors Process lines within-fence pipelines Fluid pressure drop calculations

Single phase gas vs. liquid Two phase systems Short cut methods

Application of energy and continuity equations

Piping design in a thermal-fluid, energy system or fluid productions facility involves the selection of a pipe diameter and a wall thickness that is capable of transporting fluid from one piece of equipment to another, within the allowable pressure drop and pressure rating restraints imposed by the process. The first step in being able to make these changes is to understand how pressure drops in these lines are calculated. The basic principles of fluid flow governs all fluid pressure drop calculations and are discussed in basic fluid flow text books.

Reynolds number criteria determines whether a laminar or turbulent flow exists in the pipeline. Using energy equation (in the simplified form called the Bernoulli equation is used to find the total fluid head at the point of interest and the head required to drive the fluid from one point to another. The Darcy-Weisbach equation states that the friction head loss between two points in a completely filled, circular cross section is proportional to the velocity head and length of pipe and inversely proportional to the pipe diameter. This can be written:

Where f is the Moody friction factor which can be determined using standard Moody or Fanning charts and is a function of the Reynolds number (Re = rVD/m) and relative roughness of pipes (e/D). The colebrook-White equations can also be used to determine friction factor. To distinguish a Moody chart from a Fanning chart, the laminar friction factor should be checked. For the laminar flow rate the friction factor from a Moody chart equals 64/Re while it is 16/Re when it is determined via a Fanning chart. The Fanning friction head loss obviously should be calculate using hf=2CfLV2/gD where Cf is the Fanning friction coefficient.For pipe sizing purposes, since D is unknown the Reynolds number cannot be calculated to determine friction factor for pressure drop calculations. Therefore a trial and error approach is taken for pipe sizing. However there are correlations such as Swamee-Jain and various forms of the Hazen-Williams which could be used for Pipe sizing. Both equations can be used in metric system and Hazen-William coefficient for various pipe materials are given in standard data books.

gV

DL

fh f 2

2

=

140

140

Continuity equation (conservation of mass)

Energy equation (conservation of energy)

Fluid Flow Principles

uAmandmmdtdm

outin r=== &&&0

dLDguf

dFordLDguf

dFwhere

dLugDf

dHdPduug

MMoody

FFanning

M

22

2222

2:

02

1

==

=+++ rrrr

Consider a pipeline that transports a fluid between point 1 and 2 at steady-state condition, where ? is fluid density, P gas pressure, A pipeline cross sectional area and u gas average velocity. At steady state conditions mass flow rate of gas at point 1 and 2 will be equal according to the continuity equation (conservation of mass):

If the Newtons law of motion is applied to an element of fluid in a non-horizontal pipeline, the summation of all forces acting on the elements results in the general form of energy equation as shown in this slide. The general form of equation comprises of four main energy terms as indicated in the slide:

uAmandmmdtdm

outin r=== &&&0

dLDguf

dFordLDguf

dFwhere

dLuDg

fdHdPduu

g

c

MMoody

c

FFanning

c

M

c

22

2222

2:

02

1

==

=+++ rrrr

141

141

Gas flow Energy equation

Kinetic energy:

Pressure term:

Potential Energy:

Friction losses:

=+++ 021 2222 dLu

gDf

dHdPduug

M rrrr

1

22

2

lnuu

gAm

c

&

avgavg RTZPPMW

2)( 21

22 -

HTRZ

MWP

avgavg

avg D2222 )(

LgD

fu M2

22r

Piping systems- Pressure drop calculations

The general form of equation for compressible gas flow comprises of four main energy terms as indicated in the slide. The average pressure may be obtained by integrating the pressure energy term as follows:

The adiabatic frictional flow assumption is more appropriate to high speed flow in short pipes. For flow in long pipes, such as natural gas pipelines, The gas state more closely approximates an isothermal flow. For isothermal gas flow the integrals may be calculated using and average Z and average pressure and temperatures. The simplified equations in SI and Imperial units are shown in the next slide.

2

32

21

21

2121

TTT

PPPP

PPP

avg

avg

+=

+

-+=

142

142

Steady State Compressible Flow Equation: Isothermal Gas Flow

avgavg

avg

avgavgb

bb

ZT

PHSE

DSLTZ

EPPfP

TQ

2

5.221

22

21

0375.0

155.77

D=

--=

avgavg

avg

avgavgb

bb

ZT

PHSE

DSLTZ

EPPfP

TQ

2

5.221

22

21

0375.0

155.77

D=

--=

Where:Qb = gas flow rate at base condition, Standardft3/dayTb = temperature at base condition, 520oRPb = pressure at base condition, 14.7 psia

= transmission factor dimensionless and

f is Moody friction factor

P1 and P2 = gas inlet and outlet pressures, psiaS = gas gravity, MW/29DH = elevation change, ft.Pavg and Tavg = average pressure and temperature, psia and oRZavg= average compressibility factor dimensionlessL = pipe length, milesD = pipe inside diameter, in.E = Potential energy term

f1

avgavgm

avgavg

avgm

b

bb

ZT

HSE

DSLTZ

PEPP

fPTQ

D=

--=

0684.0

165.13 5.221

222

21

Where:Qb = gas flow rate at base condition, Standard m3/s Tb = temperature at base condition, 288.7 KPb = pressure at base condition, 101.3 kPa

= transmission factor dimensionless and f

is Moody friction factor

P1 and P2 = gas inlet and outlet pressures, kPaS = gas gravity, MW/29DH = elevation change, mPavg and Tavg = average pressure and temperature, kPa, abs. and KZavg= average compressibility factor dimensionlessL = pipe length, mD = pipe inside diameter, mE = Potential energy term

f1

143

143

Panhandle B Weymouth AGA fully turbulent Colebrook-White Fritzche Mueller Pole Spitzglass

High pressure Low pressure

Simplified Fully Turbulent Flow Equations

Some of the most common and widely used flow equations that are suitable for the design of large diameter, high pressure gas transmission lines are listed in this slide. Panhandle B equation is more suitable for large transmission pipelines (>24) while Weymouth is more suitable for high pressure within-fence process pipelines (2-8). The Spitzglass low pressure equation is a good correlation for low pressure flare headers and process vacuum lines. The above mentioned equations may result in quite erroneous results if not used properly. The equations therefore are not recommended although they are still in use. The general energy equation is the most accurate and will result the best result for any pipe size and pressure temperature, flow conditions.

144

144

Ideal gas flow

Speed of sound and Ma number: Ma = V/a Ma

145

145

Ideal gas friction factor:

Isothermal friction factor:

Isothermal ideal gas equation

Piping systems- Pressure drop calculations: ideal gas flow (cont.)

2

2

2

2*

)1(2)1(

ln2

11Mak

Makk

kkMa

MaDfL

-++++-=

)ln(1 2

2

2max kMa

kMakMa

DLf

+-

=

2

2/1

2

1

22

21

2/1

2/1

ln24

D

PP

DLfT

PPMWP

TRQ

avg

avgb

+

-=

p

The friction factor for compressible flow of an ideal gas can be theoretically related to Ma number and k values. The following equation can be derived (see Fluid Mechanics by Frank White, 5th edition, 2003, McGraw Hill) for adiabatic gas flow:

It is recommended that the friction factor be estimated from the Moody chart for the average Re number and wall roughness ratio of the pipe. Available data on pipe friction for compressible flow show good agreement with the Moody chart for subsonic flow, but measured data in supersonic pipe flow can be up to 50% less than the equivalent Moody friction factor.

For isothermal flow the friction factor equation will be simplified as:

The general isothermal flow equation for an ideal gas, therefore could be derived as follows:

For adiabatic flow:

2

2

2

2*

)1(2)1(

ln2

11Mak

Makk

kkMa

MaDfL

-+++

+-

=

)ln(1 22

2max kMa

kMakMa

DfL +-=

2

2/1

2

1

22

21

2/1

2/1

ln24

D

PP

DLfT

PPMWP

TRQ

avg

avgb

+

-=p

( )speedsoundstagnationadiabatickRTaand

VV

kDL

fk

VV

a

V 00

1

2

2

2

120

21

)ln(1

1

=++

-

=

146

146

Gas compressibility estimation General compressibility charts Thermodynamic equations

Average thermodynamic properties estimation Critical temperature and pressure Reduced temperature and pressure Molecular weight of a gas mixture

Steady State Compressible Flow Equation -Reminder

Average molecular weight for a mixture of natural gas is calculated using the following formula:

yN = mole fraction of component N = moles of component N in gas phase divided by total moles in gas phase. Moles = Weight of a gas component divided by its molecular weightFor instance moles for 32 lbs of methane is 32/16=2 lbmole. Molecular weight of individual compounds can be found in Figure 23-2 of Ref. 4. Since molecular weight is the weight of one mole of a compound, it can have various weight units depending on the unit system used. Number of moles is also represented in different forms depending on the unit systems used; therefore for instance we may have 2.2 lbmoles of methane which equal to 1 kgmole of methane in SI system of units. Therefore, the number of moles is not the number of molecules rather an indication of weight of the compounds in molar basis. One grmole of each compound, of course, contains 6.23 x 1023 molecules, therefore one lbmole contains 6.23 x 1023/453.5 = 1.37 x 1021 molecules of the same compound.For pure components, critical pressure and temperature data can be found from Figure 23-2 of the Ref. 4data book. For mixture, the Kays mixing rule can be used to find the effective critical properties:PPC = S yNPCN and TPC = S yNTCNWhere PPC and TPC are the pseudocritical pressures and temperatures, respectively, for the mixture and yN is the mole fraction of component N in the gas mixture. These are called pseudo because they are used as a correlation basis rather than as a very precise representation of mixture critical properties.

]).([ NN MWyMW =

147

147

Example 18 Pipeline pressure drop calculations

Find downstream pressure for a horizontal line with the following given information:

Gas flow rate: 23 MMSCFD Gas viscosity: 0.013 cp Gas gravity: 0.85 Length: 7,000 ft Inlet pressure: 900 psia Gas temperature: 80 oF Pipe diameter (ID): assume 4 Pipe roughness (e): 0.004 (old steel)

Compare the result of calculations with various methods.

148

148

Example 19 Process lines pressure drop calculations

A gathering line delivers gas with the following spec to a processing plant, find the required inlet pressure:

Gas flow rate: 2.3 MMSCFD Gas viscosity: 0.011 cp Elevation drop: 500 ft Gas gravity: 0.7 Length: 8.5 miles Exit pressure (Pout): 100 psia Gas temperature: 80 oF Pipe diameter: 4 Sch. 40 Pipe roughness (e): 0.001

149

149

Design velocity Erosional flow velocity:

Gas lines 40 to 50 percent of erosional velocity (10-13 m/s)

Liquid lines 1 to 5 m/s (2 to 3 m/s) Process gas lines API RP 14E pressure drop

recommendations:

2-phase systems density of two phase= total mass flow rate (liquid + gas) divided by total volumetric flow rate

Pipe Sizing Pipe diameter

mixe

CV

r=

522

121

100 336000,013.0, df

CmCCC

P ===D &r

API Recommended Practice 14E (API RP 14E) recommends the following equation for maximum fluid velocity in a pipe line:

Where: Ve is erosional velocity (ft/sec), r is fluid density (lb/ft3), and C is an empirical constant. Earlier version of API (before 1990) recommended values between 100 for continuous and up to 125 for non-continuous services. The more recent versions allow C values 150 up to 200 for continuous non corrosive (corrosion controlled) services. The recommended value for the gas velocity in gas transmission mainlines is 40 to 50 percent of the erosional velocity (i.e., a value of 10-13 m/s or 33-43 ft/sec is an acceptable value for preliminary design purposes). A minimum velocity should be kept in the pipeline to minimize accumulation of liquids and solid particles in the pipeline. For liquid lines a minimum velocity of 1 m/s and a maximum value of 5 m/s are used for design purposes. Below the minimum velocity solid deposition is very possible and above the maximum erosive conditions prevail. For design purposes values between 2 to 3 m/s are normally used.For process lines (within fences gas piping), API RP 14E recommends the pressure drop criteria for pipe sizing purposes. The following equation is used:

Where: DP100 is pressure drop per 100 ft of pipe (psi/100), m is fluid mass flow rate (lb/sec), f is Darcy-Weisbach or Moody friction factor, d is pipe i.d. (in.), and r is fluid density (lb/ft3).For two phase system the erosional velocity is calculated using the API equation, only the mix density should be calculated using the following equation:

Where: R is gas/oil ratio (ft3/bbl), P is operating pressure (psia)T operating temperature (oR), S gas specific gravity (MW/29), Z is gas compressibility factor, and rm is fluid mix density (lb/ft3)

5.0mix

eCV

r=

522

121

100 000,336,013.0, df

CmCCC

P ===D &r

TZPPSPGS

mix ++=

7.198)7.2(.).(409,12r

0.50-1.2500-2000

0.20-0.50100-500

0.05-0.200-100

Acceptable pressure drop, psi/100 ftOperating pressure (psig)

Acceptable pressure drop for single-phase gas process lines (API RP 14E, 1984)

150

150

Example 20 Pipeline sizing

Size a manifold for 100 psia in a gas plant for a gas with the following specification:

Patm: 14.0 psi Gas flow rate: 2.3 MMSCFD Gas viscosity: 0.011 cp Elevation drop: 500 ft Gas gravity: 0.7 Length: 8.5 miles Exit pressure (Pout): 100 psia Gas temperature: 80 oF Pipe roughness (e): 0.001

151

151

Example 21 Two phase flow HYSYS exercise

Calculate pressure drop per unit length through a straight pipe for the following conditions

Pin: 2800 kPa Gas flow rate: 427.5 Sm3/h Gas viscosity: 0.012 cp Liquid flow rate: 16.8 m3/h Liquid viscosity: 7.98 cp roughness (e): 0.001 Gas composition (C1: 98.38, C2:1.38; C3: 0.07, iC4: 0.02; nC4: 0.02; H2O: 0.13) Liquid composition: (C1: 10.95, C2: 0.65; C3: 0.14; iC4: 0.08; nC4: 0.15; iC5: 0.24; nC5:

0.36; C6: 1.20; C7: 2.50; C8: 2.40; C9: 3.30; C10: 4.50; C12: 2.71; C14: 6.61; C16: 3.61; C18: 5.63; C20: 7.23; C22: 14.85, C24: 14.97; C30: 17.92)

152

152

ANSI B 36.10 and CSA Z245.1-02 (steel pipe standards) API 5L Allowable stress/pipe thickness codes: ANSI/ASME CODE FOR PRESSURE PIPING, B31v ANSI/ASME B 31.1 - Power Pipingv ANSI/ASME B31.3 - Chemical Plant and Petroleum Refinery Piping:

v ANSI/ASME B31.4 - Liquid Petroleum Transportation Piping Systems

v ANSI/ASME B 31.8 Gas Transmission and Distribution

Canadian Standards Association B51-M1991, Boiler, Pressure Vessel, and Pressure Piping Code.

Pipe Sizing Pipe Dimensional Standards

1002( ) 100 .

i om

i

Pdt CA

SE PY Tol

= + + -

FTESdPt oim

=2

ANSI (American National Standard Institute) B 36.10 and in United States and CSA Z245.1-02 (steel pipe standards) provide standards for pipe and pipeline systems. Ten different pipe schedules are defined (10, 20, 30, 40, 60, 80, 100, and 160), the wall thickness increasing as the schedule number increases. Schedule 40 is referred to as standard pipe, abbreviated S for 1/8 through 10 pipes. Schedule 80 is referred to as extra strong indicated often as XS for 1/8 through 8 pipes. Also used double extra strong or XXS for through 8 pipes. API 5L is another standard for dimensional requirements. Standard 5L agrees with ANSI 36.10 for the most part, with a few more wall thicknesses for several diameters. Stainless steel pipes are designated by ANSI 36.19 and are much the same as for carbon steel pipe.The ANSI codes governing allowable stress for various types and grades of steel are presented by ASME B31 Code for Pressure Piping. ANSI B31.1 and B31.3 use the same equation to calculate the required wall thickness. ANSI B31.4 is actually a subset of ANSI B31.8 when it comes to calculation of wall thickness. Therefore from a wall thickness standpoint, only ANSI B31.3 and ANSI B31.8 are in common use. In general but not always, ANSI B31.3 is the more severe in calculating required wall thickness. The more stringent requirements of ANSI B31.3 apply to piping in processing plants and on offshore platforms so called within fences standard. ANSI B31.8 applies to cross-country gas transportation piping.ANSI B31.3

Where tm minimum required thickness (in.); CA mechanical corrosion, and/or erosion allowance (in.), typically 0.064; Pi internal design pressure (psig); do outside diameter of pipe (in.), S is allowable stress (psi); E is longitudinal joint factor, 1.0 for seamless pipe and 0.85 for ERW pipes; Y temperature factor, 0.4 for up to 900oF, 0.5 for 950oF, and 0.7 for 1,000oF and above. Allowable stress values are given in standard tables with ANSI B31.3 designation. Tol. Is manufacturers allowed tolerance (12.5% for API 5L pipes up to 20-in and 10% for API 5L pipe greater than 20-in)ANSI B31.8

Where: S is specified minimum yield strength (psi); E is longitudinal joint factor, 1.0 for seamless and welded pipes except, 0.89 for Fusion Welded A 134 and A 139, 0.80 for Spiral Welded A 211, and 0.6 for furnace Butt-Welded ASTM-A 53, API 5L, F is construction design factor, 0.72 for cross country locations, etc., 0.6 for fringe areas near cities and towns, etc., 0.5 for commercial and residential areas, etc., 0.4 for areas with multistory buildings, etc., T temperature factor, 1.000 for 250oF or less, 0.967 for 300 oF, 0.933 for 350 oF, 0.900 for 400oF, and 0.867 for 450oF. Allowable pressures for ASTM A-106, API 5L and API 5LX seamless transmission pipe of various minimum yield strength are given in standard tables with ANSI 31.8 designation. The canadian equivalent code is the Canadian Standards Association B51-M1991, Boiler, Pressure Vessel, and Pressure Piping Code.

FTESdP

t oim =

2

1002( ) 100 .

i om

i

Pdt CA

SE PY Tol

= + + -

153

153

Design Pressure:

Maximum Allowable Working Pressures - B31.3 and B31.8 Pressure Rating Classes

ANSI B16.5: 150, 300, 400, 600, 900, 1500, and 2500

API 6A: 2000, 3000, 10000, 15000, 20000, and 30000

Pipe Sizing Pipe Dimensional Standards: Design Pressure and Pressure Rating Classes

5% of max Op. P>100050 500

154

154

Example 22 Pipe Sizing: ANSI B31.3 and B31.8

Chose a line size and wall thickness using B31.3 and B31.8 for the following conditions:

Gas flow rate to a dehydrator tower @ 800 psia: 23 MMSCFD Line rated for 1,480 psi Gas viscosity: 0.013 cp Gas compressibility (Z): 0.67 Gas gravity:0.85 roughness (e): 0.001 Pipe length: 7,000 ft T= 80 oF Criteria: Vmax= 60 ft/sec; Vmin= 10-15 ft/sec; D P= 100 psi Use API 5L X60 pipe or ASTM A106 GB Joint efficiency = 1.0 CA= 0.05

155

155

Piping Systems - Fabrication Methods and Materials of construction

Pipe Fabrication techniques Seamless Longitudinally welded

Electric Resistance Welding (ERW) Submerged and Double Submerged Arc Welding (SAW/DSAW) Continuous Welding (CW) Furnace lap-weld, furnace butt weld, fusion welding, spiral weld Etc.

Pipe materials Carbon steel (ASTM A-106, API 5L, etc.) Alloy steels Plastic and fiber glass reinforced plastics (PE, PP, PVC, etc.) Titanium Etc.

Carbon steel pipe is manufactured either in seamless or longitudinally welded form. Welded pipe has lower allowable stress than seamless pipe because of the potential weakness of the weld seam. Generally, seamless pipe is made by heating bar stock, then piercing it with a mandrel, and rolling and/or drawing the hot steel over the mandrel to the desired thickness. Longitudinal seams are welded by three main commercial methods: electric-resistance welding (ERW), submerged electric arc welding (SAW), or continuous welding (CW). In electric resistance welding, sheet stack is rolled to the proper diameter, then welded by squeezing the edges together with simultaneous induction heating. SAW pipe is made by first bending the pipe to a circular form in presses, followed by conventional submerged arc welding of the longitudinal seam. In double submerged are welding (DSAW), the seam is welded twice, once on the inside and once on the outside. Continuous-welded pipe is formed by rolling the hot stock into cylindricalshape, followed by pressing the very hot edges together to accomplish the weld. API RP 14E (1984) recommends ASTM A106, grade B (available only in seamless) and API 5L, grade B (seamless, ERW, or SAW) for non-corrosive hydrocarbon service in petroleum industry. Seamless pipes are made only up to a size of 26 (2-26) up to a length of 44; while welded pipes are manufactures in following sizes: ERW 4-20 in diameter and 80 in length, SAW 20-48 in diameter and 40 in length, CW 1/8-4 in diameter and 50 in length. Fabrication techniques similar to those for carbon steel are used for other metal pipes.Pipe materials. Carbon steel (ASTM A-106, grade B or and API 5L, grade B ) is by far the most commonly used pipe material for non corrosive services above -20 oF (-29 oC). Between -20 and -50 oF, ANSI B31.3, allows this material to be used if the pressure is less than 25% of maximum allowable design and the combined longitudinal stress due to pressure, dead weight, and displacement strain is less than 6,000 psi. Below -50 oF, it is required that the pipe be heat treated and Charpy tested. Alloy steel, which contain relatively high chromium and/or nickel, may be required for fluid streams with corrosive material content. National Association of Corrosion Engineers (NACE) recommends material for corrosive services (e.g., NACE Std MR-01-75). There are different grades of carbon and alloy steels, for instance A-312 TP 304L stainless steel can handle minimum temperatures down to 425 oF (-254 oC). Chemical analysis of varying grades of steel pipes are available via manufacturers information brochures or internet websites. Plastic and fiber glass reinforced pipe (RFP) are light, easily handled, and do not corrode. Allowable pressures and temperatures are low, although RFPs with very high allowable pressures can be made, they are relatively more expensive compared to steel pipes. Available materials for plastic pipes include polyethylene (PE), polyvinyl chloride (PVC) and polypropylene (PP).

156

156

Corrosion prevention Material selection Corrosion inhibitors Cathodic protection (Sacrificial anodes and

DC current) Protective coatings

Hydrostatic testing and line cleaningHydrostatic testing and line cleaningHydrostatic testing and line cleaning Pipeline Pigging Pipeline Pigging Pipeline Pigging Leak DetectionLeak DetectionLeak Detection

Pipeline Operation

Gathering and transmission lines should obviously be protected against corrosion. Pipeline corrosion is an electrochemical process and can be inhibited by several means:Material selection. Carbon steel pipe is adequate for long, trouble-free non-corrosive services. However as pointed out in API RP 14E (1984), production process streams containing water, brine, carbon dioxide, hydrogen sulfide, or oxygen or combination of these may be corrosive to metals used in system components. Corrosion is a complex process and function of numerous parameters including fluid composition, water content, flow velocity, etc. Two main type of Stress Corrosion Cracking occur due to water and hydrogen sulfide and due to chlorides. Different materials are required for these two services. Latest editions of ANSI B31.3 (Petroleum Refining Piping) and B31.8 (Gas Transmission and Distribution Piping Systems) , API RP 14E (Design and Installation of Offshore Production Platform Piping Systems) and NACE (National Association of Corrosion Engineers) MR-01-75 (Sulfide Stress Cracking Resistant Metallic Materials for Oil Field Equipment) should be consulted concerning material selection. Corrosion inhibitors. Chemicals that passivate steel surfaces and make them resistant to corrosion may be injected into fluid lines. Important parameters in corrosion inhibitors are filming, injection rate, and monitoring. Inhibitors may be introduced in batch or continuous modes. Monitoring provides evidence of the treatment efficacy. Flush mounted, electronic, corrosion-measuring devices are used, as well as hydrogen probes. Chemical testing of water samples for iron and manganese can reveal intensity of corrosion. Cathodic protection. Electrochemical protection is provided by reversing the normal current flow of corrosion, thereby safeguarding the pipe. Two methods are used. Sacrificial anodes (e.g., magnesium or zinc blocks) are attached to the line and the soil and, because of their higher activity in the galvanic series, reverse the current flow and are preferentially corroded. The anodes should be replaced when completely used and can only protect a limited length of pipe. Applied DC current is provided by rectifiers attached to the pipeline (cathod) and to a steel or carbon anode that is in electrical contact with the soil. With sufficient voltage, one rectifier can protect a long pipeline. Protective coatings. External coatings have been used to inhibit corrosion in pipelines for many years . The most widely used and still type, consists of hot-applied bituminuous material wrapped with an appropriate covering. Mineral fillers may be mixed with bitumin to impart strength. Generally two layers of coating and wrapping are applied. Glass fiber fabric is a popular wrapping material. In addition to bitumin, epoxy powder and polyethylene have been used. Rubber and PVC laminated tape are also used in desert line. Coatings may be applied internally; there are reports of using polyurethane, phenolic resin, phenolic epoxy for internal coating of pipelines. TransCanada has developed a pipe fabrication technique in which a thin shell of stainless steel or other corrosion resistant material is wrapped and reinforced by a a mixture of resin and fiber glass. The fabricated pipe is light and resistant to corrosion from both inside and outside.

157

157

Pipeline Operation (cont.)

Corrosion preventionCorrosion preventionCorrosion prevention Material selectionMaterial selectionMaterial selection Corrosion inhibitorsCorrosion inhibitorsCorrosion inhibitors Cathodic protection (Sacrificial anodes and DC Cathodic protection (Sacrificial anodes and DC Cathodic protection (Sacrificial anodes and DC

current)current)current) Protective coatingsProtective coatingsProtective coatings

Hydrostatic test pressure at least 1.5 times the design pressure and line cleaning

Pipeline Pigging Leak Detection

Hydrostatic Testing and Line Cleaning. Accidental pressure excursions may cause the operating piping system pressure to exceed the MAWP for a short time. Fortunately the code provides a safety factor and hence the pipe may not burst. However the designer cannot claim this safety factor. Pipes contain inhomogeneities that cause weak spots. Field welding is another source of inhomogeneities. Therefore, the ASME code requires that pipes should be hydrostatically tested with water at 150% of the MAWP to ensure integrity before fluid flow is allowed.The purpose of testing after construction is to test and remove from the line defects that escape inspection procedures in the pipe mill and any that are produced during shipping, handling and construction. Minimum proof tests are established by such codes mentioned before (e.g., ANSI B31.4, etc,.). In hydrostatic testing the line is filled with fresh or sea water. Dye, corrosion inhibitors and biocide are often added. Associated with hydrostatic testing is the task of cleaning the pipeline before and/or after the introduction of water. The line may contain not only water but considerable amount of debris such as mill scale, rust, welding rods, etc. In a typical pipeline, a 280-mile line was cleaned out of approximately 370 tons of debris. Pipeline pigging. As discussed before pigs are run through the pipeline to remove foreign including liquids and solid materials. Gauging or caliper pigs (also known as intelligent pigs) are used to detect dents, buckles, or excessive corrosion. For cleaning purposes a fairly good seal is required between the pig and the pipewall.Leak detection. This refers to routine inspection of pipe for small leaks. Visual inspection are not any help with small fluid leaks. For gas lines, air sampling adjacent to the line and for transmission lines, computer calculations built into SCADA system.