ppl300 pipe and coatings

8/12/2019 PPL300 Pipe and Coatings

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Chevron Corporation 300-1 November 1994

300 Pipe and Coatings

Abstract

This section provides the engineer with guidance on selection of line pipe mate-

rials, requirements for bending in the field and in the shop, and selection and appli-

cation of coatings and linings for corrosion protection. Guidelines and

specifications are included. Specifications for line pipe materials, methods of

bending, and internal and external coatings are also included.

Contents Page

310 Line Pipe Selection 300-3

311 Line Pipe Manufacturing

312 Selection of Grade and Wall Thickness

313 Fracture Toughness Requirements (Impact Testing)

314 Corrosion

315 Specifications and Selection for Specific Services

316 Pipe Purchasing320 Field Bending 300-22

321 Code Requirements

322 Chevron Requirements

330 Shop Bending 300-24

331 Induction Bending

332 Hot Bending

340 External Pipeline Coatings 300-28

350 Internal Coatings and Linings 300-30

351 Epoxy Coatings

352 Plastic Linings

353 Cement Linings

360 Piping Components for Pipelines 300-38

361 General


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300 Pipe and Coatings Pipeline Manual

November 1994 300-2 Chevron Corporation

362 Through-Conduit Valves

363 Closures and Appurtenances for Scraper Traps

364 Casing Insulators and Seals

365 Special Repair Fittings

366 Branch Connections

367 Wall Thickness Transition Pieces

370 Special Installations 300-43

371 Insulation on Buried Lines

372 Heat Tracing for Buried and Aboveground Lines

373 Nonmetallic and Corrosion Resistant Pipe

380 References 300-45


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Pipeline Manual 300 Pipe and Coatings


310 Line Pipe Selection

Line Pipe Specifications

The commonly used industry specifications for line pipe are API 5L and Canadian

Standard CAN3-Z245.1. In 1994, ISO (International Standards Organization)

adopted line pipe standards. These are ISO 3183-1, Technical Delivery Conditions

for Steel Line Pipes for Combustible Fluids Part 1: Pipes of quality level A; and

ISO 3183-2, Technical Delivery Conditions for Steel Line Pipes for Combustible

Fluids Part 2: Enhanced quality level B. ISO 3183-1 is essentially based on the

Fortieth edition of API 5L, November 1992. ISO 3183-2 has tighter chemical

composition requirements, specific heat treatments and mandatory toughness

requirements. It is similar to the Chevron specifications.

For both onshore and offshore pipelines the Company generally uses line pipe

purchased with Model Specification PPL-MS-1050, Line Pipe for General Service.

For sour service, PPL-MS-4041, Sour Service Line Pipe is recommended. Specifi-

cations PPL-MS-1050 and PPL-MS-4041 (for sour service) are actually a list of

requirements that supplement API specification 5L. These additional requirements

are necessary to enable the user or project engineer to obtain state of the technology

line pipe with assured weldability, NDE requirements and sour service performance.

311 Line Pipe Manufacturing

Pipe Making Processes

Line pipe is manufactured by several different processes. Chevron commonly uses

seamless (SMLS), electric weld (ERW or HFI), and submerged arc welded (SAW)

pipe. There is also helical or spiral welded submerged arc welded pipe, however its

use has not been common in Chevrons operations. Each process has its inherentadvantages, disadvantages and suitability for different sizes of pipe. Refer to

Figure 300-1.

Seamless Pipe

Manufacturing of seamless (SMLS) pipe begins with a solid round billet that is

heated to about 2200F and pierced to make a hollow cylinder. The cylinder passes

through several hot (1800-2200F) rolling steps to make a pipe with the desired size

and wall thickness. Seamless pipe may be supplied as-rolled, or it may be heat

treated after rolling to improve its properties. Either normalizing or quenching and

tempering heat treatments may be used. Straightening if required is done either hot

or cold depending upon the mill practice.

Seamless pipe has greater variation in wall thickness that welded pipe. Also the

length variation in a particular lot or mill run is greater than welded pipe. The engi-

neer is advised to clearly specify the acceptable length variations on the purchase

order.


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(1) The range represents the capacity variations for different manufacturers.

(2) Above 1.25 in. refer to ANSI/ASME B31.4 and B31.8 for stress relief requirements.

Electric Welded Pipe (ERW or HFI)

Electric welded pipe is manufactured from a long, flat coiled strip called skelp that

has been rolled to the desired wall thickness of the finished pipe. The strip has a

width equal to the circumference of the pipe. In the pipe mill the skelp is fed

through a series of rolls which form it into a cylinder. The edges are welded

together using electric resistance (ERW) or induction (HFI) heating and pressure

from the rolls to make a longitudinal seam. No filler metal is added to the weld, and

after the flash from the weld is trimmed off it is difficult to visually locate the

weld on the OD. At the ID the flash trimming operation creates a small depression

which makes the weld line distinguishable in many cases. The narrow heat affected

zone along the seam is heat treated (seam normalized) after welding using localized

induction heating coils. EW pipe is usually not given an additional heat treatment

Fig. 300-1 Typical Availability and Usage for Types of Pipe

Seamless EW (ERW or HFI) SAW Spiral Weld

Minimum

Diameter(1)2-3/8 in. or less 2-3/8 in. or less 16 in. to 20 in. 10 in.

MaximumDiameter(1)

16 in. (typical) to 26in.

24 in. to 26 in. 64 in. to 84 in. 80 in. to 100+ in.

Maximum

Wall Thick-ness (1) (2)

0.750 in. to 2.000 in. 0.312 in. to 0.750 in. 0.625 in. to 1.500 in. 0.500 in. to 1.500 in.

Grades B thru X-80 B thru X-70 B thru X-80 B thru X-70

Highly weldable Xgrades may be heat

treated byquenching and

tempering

X-52 and highergrades are made

from controlledrolled skelp orquenched and

tempered


from controlledrolled plate


from controlledrolled skelp

AcceptableServices

All services onshoreand offshore

All services onshore;some offshore

services. SeeFigure 300-2

All services onshoreand offshore

USA experiencelimited to less crit-

ical services. Usedas equivalent to

SAW in Europe,Canada, etc.

Relative Cost More expensive thanEW. Cost premium

may be significantfor larger sizes (>10inch)

Usually less expen-sive than seamless

in sizes 10 inches. Large

overlap in size rangewith seamless

In the small range ofsize overlap, usually

less expensive thanseamless but more

than ERW

May be less expen-sive than long seam

SAW


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and its mechanical properties are determined by the original properties of the skelp.

Forming, final sizing, and straightening are all done cold.

ERW pipe has a better surface finish and can be more uniform in length than seam-

less. The advantage of better surface quality is that for FBE coated pipe there are

fewer problems with holidays in the coating.

Note The term ERW is used in this manual to refer to two processes for manufac-

turing electric welded (EW) pipe, and includes electric resistance welded (ERW)

and high frequency induction welded (HFI). The latter is the newer process. The

basic difference between the two processes is: the ERW process is conductive where

the heating of the vee formed by bringing the edges of the skelp together is

produced by flowing a high frequency current between the edges of the skelp prior

to pressing the edges together to form the weld; whereas in the HFI process, the

heat is generated by an induction coil placed around the formed skelp cylinder. HFI

is claimed to have the advantage of producing a higher heat flux across the weld

during the manufacturing and therefore is claimed to be more suitable for thicker

walls. Chevron has not made a quality distinction between the two processes.

ERW Weld Quality. Over 25 years ago, ERW pipe gained a reputation as poor

quality pipe. Most of the performance problems were associated with frequent field

leaks during field hydrotesting and operations caused by manufacturing defects in

the weld. Advances in skelp material quality, manufacturing processes, particularly

high frequency resistance and high frequency induction welding, and more accurate

and reliable NDE equipment especially ultrasonic testing have virtually eliminated

these problems. ERW pipe made today in a modern mill can be manufactured to be

equal in performance to seamless. Recommendations for specifying and ordering

ERW pipe are found in Section 316and Figure 300-2.

Submerged Arc Welded Pipe

Submerged Arc Welded (SAW) longitudinal seam pipeis manufactured by

forming a plate into a cylinder, then making a longitudinal seam using the

submerged arc welding process with filler metal. The most common forming

process is called UOE, which stands for the three main forming steps: bending the

plate into a U, pressing into an O, and then (after welding the seam) expanding the

pipe to final size. All of the forming is done cold, including the expansion step. In

addition to final sizing, cold expansion also improves roundness, redistributes the

residual stresses from forming, and acts as a severe proof test of the weld. Forming

processes other than UOE, such as pyramid rolling and press breaking, may also be

used to make SAW pipe.

Spiral Weld (Helical Weld) Submerged Arc Welded Pipeis manufactured from

skelp which is twisted in a helix. The spiral seam is made with the submerged arcwelding process. Mechanical properties are determined by the original plate proper-

ties. The finished pipe and weld seams are not heat treated. Spiral weld pipe is not

usually cold expanded.

Spiral welded pipe is not included in PPL-MS-1050 or PPL-MS-4041 because

Chevron has very limited experience with the process. API 5L spiral welded pipe is

not manufactured in the U.S. There is, however, extensive use in Canada and


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Fig. 300-2 Specification Decision Tree for Mill Runs of ERW (1 of 2)


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Fig. 300-2 Specification Decision Tree for Mill Runs of ERW (2 of 2)


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Lap welded pipeis no longer made. However, there are still significant quantities

of this pipe in the ground.

312 Selection of Grade and Wall Thickness

Pipe Grades (Strength)

Line pipe grades are differentiated by the specified minimum yield strength

(SMYS) of the steel. API 5L line pipe is available in strength grades, ranging from

Grade B (35 ksi SMYS) to X80 (80 ksi SMYS). The primary advantage of higher

strength grades of pipe is reduced wall thickness for comparable design pressure

levels. Thinner walls mean fewer tons of steel over the length of the line. Since pipe

cost is directly related to tonnage, significant cost savings occur even when the

higher strength steel costs more per ton (usually about 20% extra). Cost savings

also result from the reduced time required for field welding of the thinner wall pipe.

However, before selecting the high strength pipe the designer should investigate the

fitting (bends, flanges, etc.) strength requirements and availability. Induction

bending of the pipe is a method for producing fittings of the required strength andwall thickness. However if these fittings are being considered, front end planning is

required.

Note As indicated in Section 310,ISO 3183 is comparable to API 5L. However,

the strength levels are metric and therefore the names of the grades are different.

The table below contains the English/ Metric conversion for the API grades.

Grade Limitations

Sweet Service. The Company has used line pipe up to grade X-65, but X-70 is used

by other operators. Grade X-80 should be considered where appropriate although

manufacturing experience with X-80 is currently very limited. The higher strength

grades become attractive in offshore laying operations where laying stresses and

not the operating pressure or hoop stresses may be governing the design. Experi-

mental higher strength grades up to grade X-100 are available on special order, but

they have not yet been widely used.

Sour Service. Chevron has used seamless pipe in grades X-52 and lower in sour

service without special requirements beyond API. However, the grade B seamless

being supplied today may contain additions of vanadium or columbium for strength-

ening if the carbon content is being kept low for weldability. These elements should

be controlled in the range shown in the Chevron specifications and the welding

API ISP

GR.B l245

X-42 l290

X-46 L320

X-52 L360

X-56 L390

X-60 L415

X-65 L450

X-70 L485


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procedures should be tested to assure that heat affected zones are not above 22

HRC. For seamless grades higher than X-52 the requirements of PPL-MS-4041

should apply. For welded SAW or ERW pipe the requirements of PPL-MS-4041

should apply to all grades. For ERW see the decision tree in Figure 300-2. One

difference driving different requirements between seamless and welded pipe in H2S

service is related to the manufacturing process. H2S environments result in chargingthe pipeline steel with hydrogen which collects at inclusions within the steel. In

seamless pipe the inclusions are cigar shaped and are not deleterious, however in

welded pipe which is made from plate or strip the inclusions are pancake like. In

this case hydrogen blistering or stepwise (HIC) cracking can occur. The require-

ments of PPL-MS-4041 minimize the presence of the inclusions and require testing

of the steel for cracking sensitivity in H2S environments.

Weldability

The weldability of modern pipeline steel is typically determined by the chemical

composition of the pipe and not by the yield strength. API chemistry limits are

broad and if the steel is at the maximum limits of the API specified compositions,

weldability will be compromised. However, this is usually not the case for modernsteels. Manufacturers are controlling chemistry limits more tightly than required by

API and much of the line pipe being produced today has very good weldability.

Many of the X-grades of pipe (with carbon equivalents {CE}of 0.25-0.35%) are as

weldable as Grade B. The chemical composition and carbon equivalent require-

ments of PPL-MS-1050 and PPL-MS-4041 will ensure adequate weldability.

Note Carbon equivalent,CE, is determined by an equation of specific elements

(expressed as weight percent). If the value is less than 0.42% for general service or

0.38% for sour service the material is considered weldable. This equation only

applies to carbon and low alloy steels.

CE= C+ Mn/6 +(Cr+Mo+V)/5 +(Ni+Cu)/15

Multiple Stenciling of Grade B. In order to hold down inventories manufacturers

are stenciling pipe with multiple grade designations. It is commonplace to obtain

pipe marked with all of the following designations: ASTM A-53 Gr B, ASTM A-

106 B, API 5L Gr B and API 5L-X42. This pipe will meet the minimum require-

ments of each of the specifications. The chemical composition of this material may

not be plain carbon steel but may have alloying elements of vanadium (V), titanium

(Ti) or niobium (Nb). These elements may have an effect on hardening the heat

affected zone of the pipe when they are present at levels of about 0.02%. The

designer is cautioned about the acceptance of Grade B pipe for sour service applica-

tions without a review of the mill test reports for the carbon equivalent and these

elements. See the previous section on sour service.

Pipe exhibiting multiple stencils with X-42 in the stencil will also have higher yield

and tensile strength than grade B steels produced in the past. The mill test reports

may actually show properties for this grade B that conform to grade X-52 or higher.

These steels are acceptable for use as grade B, but the user should be aware that

field bending may be more difficult than the traditional grade B steel which has a


11/45



lower yield strength. Also the user should be cautious on accepting these grades for

H2S service.

Wall Thickness

Pipe diameter and wall thickness requirements are dictated by the fluid flow and

design pressure calculations. The calculation for required wall thickness is coveredin Section 440.For offshore pipelines, laying stresses and buckling considerations

can affect the selected wall thickness and the pipe strength. Refer to Section 930.

Wall Thickness Limitations

Several factors limit the use of the higher strength grades of pipe to reduce the wall

thickness. Very thin wall pipe can be difficult to handle without denting and diffi-

cult to align properly for welding. Section 440contains the minimum recom-

mended wall thickness for pipelines of various diameters.

The maximum wall thickness is restricted by pipe availability (mill capability) as

the strength increases.

Stress relief of welds is required when the pipe wall thickness is over 1-1/2 inches

for ANSI/ASME Code B31.4 and 1-1/4 inches for ANSI/ASME Code B31.8.

Stress relieving the field girth welds is costly so higher strength steels should be

considered to reduce the wall thickness and avoid heat treatment. Since stress

relieving of the low carbon thermo-mechanically rolled steels (those containing

vanadium, niobium or titanium) may result in lowering the tensile properties below

the minimum allowable, the welding procedure qualification test specimens should

be post weld heat treated as well.

Length Variations

Length variation must also be addressed when specifying pipe. Length variation is

especially a critical factor when laying pipe off of a barge. Welding, inspection andweld coating stations are all set at specific locations along the length of the barge. If

pipe has large variation in lengths it will take longer to lay the pipe because the

ends will not coincide with the work stations. Short lengths also give problems in

loading and unloading pipe onto trucks and barges.

The data sheet guide to the pipeline specifications in section 5.2 g gives guidance

on length tolerances.

313 Fracture Toughness Requirements (Impact Testing)

Pipeline code requirements for fracture toughness of line pipe steels are addressed

in ANSI B31.4 for liquid lines and ANSI B31.8 for gas lines. Pipeline Safety Regu-lations 49 CFR Part 195 (Liquids) and 49 CFR Part 192 (gas) incorporate the ANSI

Codes by reference. The intent of both codes is to prevent any type of crack or leak

in the pipeline (such as a fatigue crack, or mechanical damage from a backhoe)

from initiating a major fracture in the line. This section provides some additional

background on fracture toughness, and explains the reasoning behind the recom-

mended fracture toughness testing requirements summarized in Figure 300-3. For
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additional help in specifying adequate fracture toughness, consult CRTC Materials

and Equipment Engineering.

(1) Critical service should include the following:

All offshore lines, and onshore lines in populated areas

Large diameter, high pressure gas lines (particularly lines greater than 14 inch or 1480 psi)

Gas or liquid lines where the lowest expected operating temperature is below 32F

LPG lines where the lowest auto-refrigeration temperature is below 32F

(2) Test temperature should be 32F or the lowest expected operating temperature, whichever is lower.

For buried lines, the lowest expected operating temperature is seldom below 20F.

For LPG lines, use 32F or lower. Test temperature should be based on the lowest auto-refrigeration

temperature, but may be higher in some cases. Consult CRTC Materials and Equipment Engineering

for specific recommendations.(3) Shear Area: 50% minimum average of all heats, 35% minimum average for each individual heat

(4) Absorbed energy: calculate requirements according to the equations given in ANSI B31.8 Section 841.

The specified minimum average energy should the the highest value calculated or 20 ft-lbs, whichever is

greater. If all calculated values are below 10 ft-lbs, see discussion in Section 313. Also note that the

equations are based on methane; see discussion regarding the effect of gas mixtures.

Fig. 300-3 Fracture Toughness Requirements for Pipelines

Fluid

Line Size (OD)and Strength

Grade

Maximum

AllowableOperating

Pressure General Service Critical Service(1)

Liquid other

than LPG

All sizes and grades All pres-

sures

No tests recommended Absorbed Energy

average:20 ft-lbs

minimum:15 ft-lbs

Test Temperature:

20 ft-lbs

15 ft-lbs(2)

LPG All sizes and grades All pres-

sures

No tests recommended if lowest

auto-refrigeration temperature is

above 32F

Abosrbed Energy

average:

minimum:

Test Temperature:

15 ft-lbs

10ft-lbs(2)

Gas or Multi-

Phase

4-inch maximum Grade B or

X-42 and maximum hoopstress does not exceed 72%

of SMYS

3705 psi

maximum(ANSI Class

1500)

No tests recommended Absorbed Energy

average:minimum:

Test Temperature:

20 ft-lbs15ft-lbs(2)

14-inch maximum Grade X-52

or lower and maximum hoop

stress does not exceed 72%

of SMYS

1480 psi

maximum

(ANSI Class

600)

Absorbed Energy

average:

minimum:

Test Temperature:32F

20 ft-lbs

15 ft-lbs

32F

Abosrbed Energy

average:

minimum:

Test Temperature:

20 ft-lbs

15ft-lbs(2)

14-inch maximum Higher

strength grade or maximum

hoop stress greater than 72%

of SMYS

All pres-

sures

Shear Area:

Absorbed Energy:

Test Temperature:

(3)

(4)

32F

Shear Area:

Absorbed Energy:

Test Temperature:

(4)

(4)

(2)

16-inch and larger All Grades All pres-

sures

Shear Area:

Absorbed Area:Test Temperature:

(3)

(4)

32F

Shear Area:

Absorbed Energy:Test Temperature:

(3)

(4)

(2)

CO2 Any size Super-crit-

ical pres-

sures

Consult CRTC Materials and

Equipment Engineering Unit

Consult CRTC Materials and

Equipment Engineering Unit


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Ductile to Brittle Transition

At low temperature, steel can fracture in a brittle manner like glass or ceramic. The

fracture surface has a crystalline appearance, and the amount of energy absorbed is

low. As the temperature increases, the steel undergoes a transition from brittle frac-

ture behavior to ductile tearing (also called shear), with a significant increase in the

amount of energy required for fracture. This ductile to brittle transition can be char-acterized using the Charpy impact test, as illustrated in Figure 300-4. The transition

temperature can be defined as the temperature where either the absorbed energy for

a full-size Charpy specimen exceeds 15 ft-lbs, or the appearance of the fracture

surface of the specimen is at least 50% shear. Brittle fracture can be prevented by

insuring that the minimum operating temperature of the pipeline is well above this

transition temperature.

Liquid Lines (ANSI B31.4)

For liquid lines, we are primarily concerned about preventing brittle fracture. Since

most pipeline steels have adequate toughness to prevent brittle fracture at tempera-

tures above freezing, fracture toughness testing for liquid lines operating above

32F is generally not required. For liquid lines in critical service, such as a large

diameter offshore crude oil line, fracture toughness testing is recommended as an

extra guarantee that the steel will be operating above its transition temperature. For

these lines, Charpy impact testing should be required according to API 5L SR5, and

a minimum average energy of 20 ft-lbs should be specified. The standard test

temperature is 32F, which is acceptable for all lines which operate above this

temperature.

For liquid lines which operate at temperatures below 32F, Charpy impact testing

should always be required. Specify a minimum average energy of at least 20 ft-lbs

at the lowest expected operating temperature of the line. This will insure that the

Fig. 300-4 Schematic Drawing Showing Ductile to Brittle Transition Behavior in the CharpyImpact Test


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transition temperature of the steel is below the minimum operating temperature,

and the steel will have adequate resistance to brittle fracture. Note that for buried

lines, the lowest expected operating temperature is seldom below 20F due to

warming from the earth.

LPG LinesLPG lines are a special case, because auto-refrigeration can cause very cold temper-

atures in the area of a leak as the line depressurizes. Brittle fracture of the line

could occur if the temperature falls below the transition temperature of the steel

while the line is still under substantial pressure. Although the ANSI B31.4 Code

does not require special treatment of LPG lines, we recommend fracture toughness

testing if the lowest auto-refrigeration temperature which could occur is below

32F. This temperature must be calculated based on the specific composition of the

LPG. Mixtures containing large amounts of propane or butane will have lower auto-

refrigeration temperatures than those with mostly C5+ hydrocarbons. If the auto-

refrigeration temperature is above 32F it is not necessary to specify Charpy impact

tests. If it is below 32F, specify a minimum average energy of 15 ft-lbs at 32F or

lower. Since it would be unlikely that the line would ever actually reach the lowestauto-refrigeration temperature while under substantial pressure, it is not always

necessary to specify fracture toughness testing at that temperature. Consult CRTC

Materials and Equipment Engineering for recommended testing temperatures for

specific lines.

Gas and Multi-Phase Lines (ANSI B31.8)

For gas lines, the Code requirements for fracture toughness are more stringent than

for liquid lines. The reason for the increased requirements is that in addition to

brittle fracture concerns, the stored energy of the compressed gas in a large diam-

eter or high pressure gas line can be great enough to propagate a ductile fracture. If

a crack is initiated by an external force (backhoe, earthquake, etc.) the gas in thepipeline will start to decompress and release this stored energy. Whether or not the

crack will propagate depends on the speed of the decompression wave inside the

pipe relative to the fracture velocity in the steel, as shown in Figures 300-5and

300-6. If the crack velocity exceeds the speed of the decompression wave, the pipe

will unzip over a long distance. One way to prevent ductile fracture propagation

is to slow down the crack. Since the crack velocity in the steel is related to the

steels fracture toughness, specifying a high enough minimum Charpy impact

energy will accomplish this. Another method is to install crack arrestors, which are

discussed in Section 448.

The fracture toughness requirements in the Code are mandatory for all lines 16 inch

NPS and larger which are designed to operate with a hoop stress over 40% of thespecified minimum yield strength (SMYS) of the pipe, and for lines smaller than 16

inch NPS which are designed to operate with a hoop stress over 72% of SMYS (the

Code permits maximum design stresses up to 80% of SMYS for some lines). Two

acceptance criteria must be met:

The average shear area for the Charpy impact specimens must be at least 35%

for each individual heat, and the average of all heats must be at least 50%, at
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the lowest expected operating temperature of the line or 32F, whichever islower.

The average absorbed energy for the Charpy impact specimens from all heats

must meet or exceed the energy value calculated using one of several equations

developed from pipeline research programs to predict the energy required for

ductile fracture arrest. These equations and an example calculation are given in

Figure 300-7.

Fig. 300-5 Ductile Fracture in Gas Pipelines

Fig. 300-6 Example of Ductile Fracture Analysis for Export Gas Line


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Company practice has generally been to specify Charpy impact testing for all gaspipelines, with a minimum energy requirement of 20 ft-lbs at 32F or the lowest

expected operating temperature of the line, whichever is lower. This level of frac-

ture toughness is adequate to prevent brittle fracture, and will also exceed the

ductile fracture arrest energy required for many small to medium diameter lines

with typical operating pressures. This practice is included in the requirements in

Figure 300-3, in addition to the Code requirements.

For lines up to 4 inch OD(3.5 inch NPS) which operate above 32F and are

designed using API 5L Grade B or Grade X-42 pipe, fracture toughness testing is

not required unless the hoop stress exceeds 72% of SMYS, or the maximum allow-

able operating pressure exceeds ANSI Class 1500 limits (3705 psi at up to 100 F).

These lines do not have a significant risk of brittle fracture, and the calculatedenergy requirement for ductile fracture arrest is low (less than 10 ft-lbs). For critical

service, which includes all lines with operating temperatures below 32F, fracture

toughness testing should be specified with a minimum energy requirement of 20 ft-

lbs at 32F or the lowest expected operating temperature (whichever is lower)

according to past Company practice. Note that API 5L SR5 does not cover testing

of pipe 4 inch OD and smaller because it specifies transverse specimens which

cannot be taken from small pipe without flattening. All of the requirements of API

Fig. 300-7 Example of Ductile Fracture Arrest Calculations

1. Gas Pipeline: 24" outside diameter1480 psi maximum allowable working pressure

2. Select Pipe Grade and Wall Thickness:

API 5L X-60wall thickness:

hoop stress =

(SMYS = 60,000 psi)0.438" required for hoop stress 72% of SMYS

= 40,548 psi (68% of SMYS)

3. Calculate Ductile Fracture Arrest Energy using equations from ANSI B31.8 Section841.11

a. Battelle Columbus Laboratories (BCL) (AGA)CVN = 0.01082R1/3t1/3= 31 ft-lbs

b. American Iron and Steel Institute (AISI)CVN = 0.03453/2R1/2 = 31 ft-lbs

c. British Gas Council (BGC)CVN = 0.0315R/t1/2 = 23 ft-lbs

d. British Steel Corporation (BSC)CVN = 0.001192R = 23 ft-lbs

where:

CVN = full-size Charpy V-notch absorbed energy, ft-lb

= hoop stress, ksi

R = pipe radius, in.

t = wall thickness, in.

PD

2t-------


17/45


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Use of drop-weight tear testing (DWTT) in accordance with API 5L Supplementary

Requirement SR6 should also be considered for high pressure gas lines 20 inches in

diameter or larger and Grade X-52 or higher. The Code permits this test as an alter-

native to specifying a minimum shear area for the Charpy impact specimens.

However, Charpy impact testing is still required to verify that the ductile fracture

arrest criteria are met.

CO2Lines

CO2lines which operate at super-critical pressures (where the CO2is a dense phase

more like a liquid than a gas) are also a special case. Extremely high pressures

combined with auto-refrigeration concerns can result in fracture toughness require-

ments which are significantly greater than for typical natural gas pipelines. Crack

arrestors have been used for CO2pipelines, as discussed in Section 448. Consult

CRTC and CPTC specialists for advice on design of high pressure CO2pipelines.

314 Corrosion

Internal Corrosion

Carbon steel pipelines are typically designed with a zero corrosion allowance.

Adding a corrosion allowance should be an economic decision. Corrosion in pipe-

lines usually takes the form of pitting for which a corrosion allowance offers little

benefit. Corrosion can usually be controlled more economically with either inhibi-

tors or corrosion resistant linings.

In the special instances where corrosion allowances are desired the following rules

of thumb may be used:

The corrosion allowance depends on the product or medium in the line.

As small as possible corrosion allowance is usually selected because it will add

to the weight and cost of the line.

For refined products the rule is zero to 1/32 inch (0.8mm).

For crude lines with significant water the typical allowance is 1/16 to 1/8 inch

(1.60 to 3.20 mm).

In gas lines that contain water, and CO2or H2S an allowance of 1/8 inch is

reasonable.

In special cases a higher allowance may be warranted.

Pipelines carrying gas meeting transmission pipeline specifications should notrequire a corrosion allowance.

In systems where corrosion cannot be controlled or carbon steel is inadequate,

several options can be considered:

Internally lined pipe (e.g., cement-lined, plastic lined, or epoxy coated) is used

in water services. See Section 350for more information.


19/45



Nonmetallic pipe (e.g., fiber reinforced plastic (FRP) or plastic) is sometimes

used for water or chemicals. See Section 370of this manual and Section 1100

of the Piping Manualfor more information.

Corrosion-resistant alloys (chromium and duplex stainless steels, and nickel

alloys) are available as line pipe as indicated in Section 311. There are also

weldable low chromium alloy steel grades (0.5% to 2% Cr) with enhanced

CO2corrosion resistance available from some of the Japanese manufacturers.

Clad or bi-metallic pipe with a conventional steel backing and an alloy liner is

available. API specification 5LD applies to these materials. These materials are

very costly but very effective in mitigating corrosion. Long lead times are

necessary for procurement. See Section 311.

External Corrosion

Codes B31.4 and B31.8 require external corrosion control of buried and underwater

pipelines by a combination of external coating (see Section 250 of the Coatings

Manualand Sections 340and 444of this manual) and cathodic protection (see

Section 460 of this manual and Section 500 of the Corrosion Prevention Manual).

It is not necessary to provide a corrosion allowance for pitting.

315 Specifications and Selection for Specific Services

General Services (PPl-MS-1050)

For most services with temperatures above 32F, including crude oil and products

lines, small diameter and low pressure gas lines, and water injection systems, the

basic requirements of PPL-MS-1050 are adequate. PPL-MS-1050 also contains

supplemental requirements which can be specified for critical services (e.g.,

offshore pipelines and lines in populated areas). The supplemental requirements canbe specified in Data Sheet PPL-DS-1050, which should be part of the bid request

and the purchase order. Hard copies of both the data sheet and specification and a

PC disk copy of the latter are contained in this manual.

Sour Service (PPL-MS-4041)

Specification PPL-MS-4041 covers all services which contain H2S, including sour

gas, sour crude oil, and water injection systems which are contaminated with H 2S.

All of the basic requirements of PPL-MS-1050 are included in PPL-MS-4041, as

well as some additions. PPL-MS-4041 also has supplemental requirements, which

can be specified on the Data Sheet PPL-DS-4041. Hard copies of PPL-DG-4041

and PPL-MS-4041, and a PC disk copy of the latter are contained in this manual.

ERW Pipe Selection Decision Tree

Figure 300-2presents an ERW pipe selection decision tree which is intended to

assist the engineer in the selection of the specification level, supplementary require-

ments and the mill class / source for ERW pipe. While ERW has been widely used

in Chevron for onshore sweet lines its use offshore and for sour lines has been

almost nil (except for Canada) . Cost savings can be realized with ERW especially
http://ppl400__.pdf/http://ppl400__.pdf/http://ppl400__.pdf/http://ppl400__.pdf/


20/45



in sizes greater than about 10 NPS. All of the requirements and notes shown in the

tree must be adhered to since performance is dependent upon all of the require-

ments being met.

The first decision to be made in using the tree is to determine if the environment

will be corrosive. Commodity grade ERW pipe can undergo grooving corrosion of

the weld seam in low pH waters, salt water, and wet gas containing CO2. Grooving

corrosion is controlled by using a pipe chemistry with low sulfur (


21/45



assigned. Mills capable of manufacturing the highest quality of pipe are assigned a

class A. The classes are tied to specific applications based on severity of service.

Mill order quantities. For pipeline projects and major producing field projects

(such as gathering systems), the quantity of pipe required is usually large enough to

justify mill order purchase. PPL-MS-1050 and PPL-MS-4041 should be used to

supplement the requirements of API 5L and to assure that chemical composition,

mechanical properties and NDE are adequate. This will minimize weldability and

field bending problems during laying of the lines. For recommendations on inspec-

tions to be performed see Section 700.

Based on experience, ERW pipe will be generally less in cost compared to seamless

in sizes above about 10 to 12 NPS. However the engineer, when going out for pipe

cost quotations should consider the total cost of ownership including shipping,

coating, delivery time, etc. all of which could easily effect the economics of which

product is more cost effective.

ERW mill order purchases. In order to properly specify and purchase ERW,

consult the decision tree in Figure 300-2. This tree is intended to assist the facilitiesengineer with selection of the proper Chevron specifications, supplementary

requirements that will provide the appropriate quality level of pipe and to give guid-

ance on the selection of the mill class. It is recommended that this chart be used

whenever ERW pipe is being purchased. If the pipe is coming out of stock, request

the mill test reports.

Pipe orders from distributor stock. For small projects, pipe is purchased off- the-

shelf from distributor stock. Purchasing pipe manufactured to API 5L, or other

similar industry standards typically has been the only option for small jobs. API 5L

pipe not meeting the additional requirements of PPL-MS-1050 General Service, or

PPL-MS-4041, Sour Service, is adequate for some services, but has had several

serious shortcomings. Some of these are:

Broad chemical composition limits which can decrease weldability

Mill hydrotest pressures as low as 60% of the specified minimum yield

strength (SMYS) which is usually lower than the field hydrotest

Minimum NDE inspection requirements that may not be adequate for critical

services

In recent years, many manufacturers are gradually upgrading their standard product

to where it will meet many of the Chevron specification requirements. If the engi-

neer requires out of distributor stock (for ERW see next paragraph) it is recom-

mended that they request the mill test reports, and check these against the chemical

composition, NDE, and hydrotest requirements of the Chevron PPL-EG specifica-

tions. This pipe may be acceptable if it meets these requirements. If assistance is

required consult a quality assurance or metallurgy specialist in the Materials and

Equipment Engineering Unit at CRTC.


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ERW Pipe Orders from Stock

For smaller quantities of pipe ordered directly from distributor stock, the use of the

Chevron specifications to place the order is not feasible. The engineer and

purchasing units are encouraged to refer to the decision tree in Figure 300-2to

select the appropriate class mill. Knowing the mill who produced the pipe,

consulting the new mill approved list, and the experience information in AQUA IIavailable from QA will aid in assessing the suitability of the stock pipe. The engi-

neer should request the mill test reports which will give the chemical composition

and the mechanical properties. The type of final NDE can be determined from the

mill source. While the pipe will not be made to the Chevron specifications, the engi-

neers will be able to assess whether it is from a high enough class of mill and meets

the important specification requirements for the service. Engineers in the Materials

Unit will be able to help with this selection.

320 Field Bending

Field bending involves cold bending the pipe to the required radius or bend angle.Field bending is needed so the pipe will conform to the curvature of the ditch. For

up to approximately NPS 12 the bending can be done with a suitable bending shoe

attached to the frame of the side boom. For sizes larger than NPS 12, a field

bending machine is recommended. Most domestic field bending machines are

manufactured by CRC-Evans, Houston, Tx (713) 460-2900. Their many sizes range

from 4- to 60-inch diameter. For large-diameter high-strength pipe, a bending quali-

fication test is recommended to confirm that the proposed bending machine size has

adequate capacity to bend the pipe. Bend quality depends on the skill of the

machine operator.

321 Code RequirementsBoth Code B31.4 Section 406.2 and B31.8 Section 841.231 limit the prequalified

minimum bending radius to a multiple of the pipe diameter. The minimum prequali-

fied bending radius varies with the pipe diameter. For example, pipe sizes up to and

including NPS 12 have a prequalified minimum bend radius of 18D (18 times the

pipe diameter). NPS 20 and larger have a prequalified minimum bend radius of

30D. Both Code B31.4 and Code B31.8 will allow a smaller bending radius,

providing prototype testing is done. For cold bends, Code B31.4 (liquids) limits the

absolute minimum pipe bend radius to 18D.

Both Codes B31.4 and B31.8 allow bends with a smaller radius providing a proto-

type bend conforms to the following: (1) wall thickness is within tolerance for the

original pipe, (2) pipe diameter is not reduced by more than 2.5%, (3) the pipe willpass a specified gauging pig, and (4) the bend is free from buckling, cracks, and

mechanical damage. ANSI/ASME Code B31.3 Section 332contains different

requirements, but generally allows smaller radius bends.


23/45



322 Chevron Requirements

Corrosion Coating Damage

Company pipeline fabrication specifications often limit the bending radius to larger

than would be allowed by the Code. The intent is to limit pipe coating damage.

Excessive bending angles can cause the coating to crack or to spall. The bending

limits are different for the various common pipeline coatings.

Pritec(extruded polyethylene with a butyl rubber mastic) and Mapec(extruded

polyethylene with a thermal setting mastic) are bendable without special precau-

tions. However, these coatings wrinkle very easily, i.e., disbond, and they can hide

buckles and mechanical damage in the bend.

Fusion-bonded epoxy(FBE) (up to 20 mils DFT) can typically be bent to 1.5

degrees per diameter bend length (38D bend radius) without difficulty. For

example, a 40-foot length of 24-inch pipe with two 6-foot tangents has 28 feet of

bendable length. This represents 14 pipe diameters, so this joint could be bent up to

21 degrees. Tighter bends are possible, and the limit will depend on the tempera-ture, FBE supplier, and coating thickness.

The bendablity of coal tar enameldepends on the ambient temperature and the

coating grade. High-temperature grades have poor bending properties at ambient

temperature and may require heating to avoid cracking.

Field-applied over-the-ditch (OTD) tapes require special attention for bends of

more than 0.5 degrees per diameter foot (115D). The OTD machine operator must

increase the tape overlap before entering a bend. Otherwise the tape will gap on the

outside radius of the bend.

Field bending specifications require that the bending apparatus be adequately

padded to minimize damage to the pipe coating. Misalignment of the bending shoescan also cause coating damage. Field bends should be holiday-tested (jeeped) to

confirm that the coating has not been damaged by bending.

Wall Thickness

Seamless pipe can have significant variations in wall thickness. The thickness can

be determined by ultrasonic measurements (see Section 710). Field bending specifi-

cations for seamless pipe require that the thinnest wall be positioned on the inside

radius during bending, because the wall on the outside of the bend will be thinned

during the bending process. This minimizes the chance that the outside of the bend

will have wall thicknesses below the minimum tolerance for the original pipe.

Welded pipe does not have significant wall thickness variations.

Welded Pipe Seam

For welded pipe, the weld seam should be located on the neutral axis of the bend.

This is considered good practice, and is required by CFR Part 192 and Part 195

unless certain precautions are taken. When the bend is in the bending machine, the

neutral axis would be located in the 3 or 9 oclock position for a bend made in the


24/45



vertical plane. This is a workmanship requirement and, providing all of the other

Code and specification requirements are met, should not be the sole reason for

rejection of a bend.

Sizing Plate

Each field bend must be able to pass a sizing plate of a size specified in the bendingspecification. This can be used to confirm the Code requirement that pipe diameter

should not be reduced by more than 2.5% of the nominal pipe diameter.

Sizing plates that confirm that an inspection pig will be able to pass through the

line are typically not necessary for field bends. Field bends are typically 18D and

above, and the problem with inspection pig passage usually does not begin until

bends are 12D and below.

Mechanical property degradation

Significant degradation of the pipe material impact toughness is not expected unless

the cold forming strain exceeds 5% (equivalent to less than a 10D bend radius).

This degradation is caused by strain aging, which leads to increased yield strengthand decreased toughness.

Bending Formulas

(1)

where:

(2)

330 Shop Bending

331 Induction Bending

Induction bending for pipe is widely used.

Capabilities and Advantages

Large induction bending machines can bend pipe from 3 to 66 inches in diameter

with wall thicknesses up to 4 inches and bend angles up to 180 degrees (90 degrees

Bend radius and bend length are measured in pipe diameters

Bend angle is in degreesD = nominal pipe diameter, ft

Bend radius57.3 bend length

bend angle-----------------------------------------------=

Cold forming strainD 100%

2 bend radius-------------------------------------=


25/45



for pipe diameters greater than 34 inches). Small bending machines (e.g., Cojaflex

PB Special) can bend 2- to 12-inch diameter pipe. The bend radius can be as low as

1.5 times the pipe diameter (3D bends are routine) for small diameter pipe.

Figure 300-8gives some basic induction bending terminology.

Induction bending overcomes most of the deficiencies of furnace hot bending and

has several additional advantages:

High dimensional accuracy.

Various bend angles and multiple plane bends.

Off-the-shelf seamless and ERW pipe may be induction bent to avoid small

quantities of special order pipe. The weld metal in SAW pipe can be a problem.

Description of the Induction Bending Process

The induction bending process uses a medium frequency induction coil to heat the

pipe (to 1500-2000F for carbon and low alloy steels, and 1900-2100F for stain-

less steel), while a hydraulic ram pushes the pipe around a radius (see

Figure 300-9). A water or air quench ring is placed closely behind the induction

coil, so that the width of the heated zone is typically only twice the pipe wall thick-ness. Restricting the heating and bending to this small zone helps maintain dimen-

sions and avoid wrinkling. As a result, most of the residual stresses are

compressive. A water quench provides the best dimensional properties and is

preferred, except for ASME P4 and P5 materials. ASME P4 and P5 materials are

easily hardened, and they can crack as a result of water quenching.

Fig. 300-8 Basic Induction Bending Terminology


26/45



Note The induction bending temperature cycle can significantly affect the mechan-

ical properties (strength and/or impact toughness) of the pipe as detailed below.

Metallurgical Effects of Induction Bending

The thermal cycle associated with induction bending can significantly affect the

yield and tensile strength (of all steels), impact properties (of carbon and low alloy

steels), and corrosion resistance of austenitic stainless steels. The effects of induc-tion bending vary with the chemical composition and the prior heat treatment of the

pipe to be bent.

Carbon steel pipe(e.g., ASTM A106 & A53, API 5L Gr B, X-42, etc.) is

strengthened primarily by carbon and manganese. It will often strengthen

significantly during the induction bending thermal cycle. For example, API 5L

Gr B pipe has met X-70 strength requirements following induction bending. To

reduce the excessive strength and hardness in the as-bent condition, these

grades require tempering following induction bending.

High strength steel pipe (e.g., X-56 and above)is strengthened by chemistry

(carbon and manganese), thermal mechanical working, and microalloying.

Grades of pipe that gain a significant amount of their strength by microalloyingand thermal mechanical working often do not retain their original strength after

induction bending. Hence, these steels may have problems meeting specified

minimum strength requirements following induction bending. Bends should

also be tempered following induction bending, which may further reduce their

strength. They mustbe tempered for sour service.

Fig. 300-9 Induction Bending Machine


27/45



Low alloy steel pipe (e.g., ASME P4 & P5) will be strengthened significantly

by induction bending and is normally cooled by air quenching rather than

water quenching during induction bending. The air quench will minimize the

hardness and the risk of cracking. These grades require tempering following

induction bending.

Austenitic stainless steel pipe (e.g., Type 316), which receives some of its

strength from cold work, will have its strength reduced by the induction

bending thermal cycle. In addition, the beginning and end of the bend will have

reduced corrosion resistance similar to that experienced in weld heat affected

zones. If corrosion resistance or resistance to stress corrosion cracking is

required, only low carbon or stabilized grades (e.g., 304L, 316L, 317L, 321, or

347) of stainless steel should be induction bent.

In summary, allinduction bent pipe (except austenitic stainless steelsType 3XX)

should be tempered following bending to reduce the strength and hardness and to

improve the impact toughness of the pipe. Tempering should be waived only on

certain nonsour-service, high-strength grades when tempering would be detrimental

to the final strength and/or impact toughnessand then only after prototype bendsare made and shown to meet the service requirements.

Selection of Materials for Induction Bending

Successful induction bends have been made in Carbon, Low Alloy, And Line

Pipe Steelswith carbon equivalents (CE) from the high 0.20%s through the

0.50%s. However, carbon equivalents in the mid- to high-0.30%s represent the

optimum chemistry for both bendablity and weldability. Carbon equivalents are

defined by the equation:

CE = C + Mn/6 + (Cr + Mo + V)/5 + (Cu + Ni)/15

(Eq. 300-1)

A potential weld toughness problem exists when SAW pipe, particularly pipe for

low temperature service, is induction bent. SAW wire and flux combinations devel-

oped to give good impact toughness in the as-welded condition may undergo a

dramatic decrease in toughness after being exposed to a stress-relieving (tempering)

or quenching and tempering cycle similar to that encountered during induction

bending. Welding consumables are available which will respond more favorably to

heat treatment, but they will typically not be the pipe mills standard consumable.

Model Specification PPL-MS-4737 requires testing of the weld for SAW pipe and

weld impact testing when the original pipe is impact tested.

If corrosion resistance or resistance to stress corrosion cracking is required, only

low carbon or stabilized grades (e.g., 304L, 316L, 317L, 321, or 347) of Austeniticstainless steelshould be used as bent. The corrosion resistance would not normally

be a factor for service temperatures above 850F or below 32F.

Model Specification PPL-MS-4737

Model Specification PPL-MS-4737, Induction Bending, presents requirements for

induction bending carbon and low allow steel pipe (ASME P1, and P3 through P5


28/45



pipe, CAN3-Z245.1 line pipe, and API SPEC 5L line pipe). Submerged arc welded,

seamless, or electric resistance welded (ERW) pipe may all be bent according to

this specification.

Austenitic stainless steels (e.g., Type 3XX) may also be bent by induction bending.

They have been excluded from the model specification for simplicity. A hard copy

and PC disk copy of PPL-MS-4737 are contained in this volume.

332 Hot Bending

Prior to the widespread use of induction bending for pipe (approximately 1980),

pipe bends were made by hot bending. Two methods were used:

Hot slab bending. Pack with sand, furnace-heat, and bend while hot

Hamburger or clam shellmethod. Hot-form half-shells in dies and then weld

the long seams

These methods were labor intensive, had limited dimensional accuracy, requiredexpensive dies for each size and bend radius, and presented the problem of how to

maintain the bending temperature on large pieces. Bending could not continue after

the pipe temperature cooled below 1600F, necessitating repeated return trips to the

furnace. Hot bends also require limited quantities of special high-strength line pipe

with specific chemical and physical properties, creating a procurement problem.

Hot bends are no longer recommended for use in any service.

340 External Pipeline Coatings

This section provides a brief overview of the recommended types of corrosion

protection coatings for buried pipelines. More complete information on external

pipeline coatings can be found in the Coatings Manualand in Section 950of thismanual.

The Coatings Manuals Quick Reference Guide provides a selection guide for

external pipeline coatings. It lists the types of coatings (fusion bonded epoxy,

extruded plastic, coal tar enamel, tape wraps, etc.) and their recommended services.

The guide also includes temperature limits, hydrocarbon resistance, weld joint

protection and repair. Figure 300-10gives the advantages and disadvantages of

using these coatings.

Fusion bonded epoxy (FBE) is, in general, the best coating for buried lines.

Extruded plastics (Pritec and Mapec are preferred because of their high quality

adhesive and plastic) are recommended when supply or economics rule out FBE.Tape wraps and coal tar enamel, while needed for certain applications, are not

recommended for new pipeline construction.

When selecting a coating, installation costs must be balanced with the reliability

expected. Using a tape wrap instead of FBE may save money in the short-term, but

will increase the chances of long-term losses due to increased maintenance and

possible early corrosion failure of the line. Other concerns are shipping costs, appli-


29/45



Fig. 300-10 External Coating Alternatives (1 of 2)

Coating Advantages Disadvantages

Line Coatings

Fusion Bonded Epoxy 20+ years experience

Low current required for C. protectionGood resistance to C. disbondment-40to 200F temperature range

Available in all pipe sizesExcellent hydrocarbon resistance

Not susceptible to cathodic shieldingExcellent adhesion to steel

Continuous coating

Near white metal surface prep required

High application temperaturesThinnest coatingDifficult to apply holiday free

Difficult to apply consistentlyDifficult to apply to bends

Liquid Epoxies

(Thermosets)

200F+ temperature resistance

Can be spray or hand applied in fieldGood chemical resistance

Can be applied to odd shapesCan be incorporated with a tapeCan be applied while pipe in service

Long cure time (minutes to 24 hours)

May need near white blast surfaceLimited service history

Expensive

Extruded Plastic,

Butyl adhesive -(Pritec brand)

Low current required for C. protection

Minimum holidays on application-40to 180F temperature rangeSelf-healing adhesive

Wide range of sizesExcellent adhesion to steel

Continuous coating

High initial cost for small dia. pipe

Susceptible to C. shieldingDo not use on spiral welded pipe

Hard to handle when warmSusceptible to damage from thermalexpansion and contraction

Cannot be used on bendsLimited hydrocarbon resistance

Extruded Plastic,Liquid adhesive-

(X-Tru-Coat-type)

24+ years experienceMinimum holidays on application

Low current required for C. protection-40to 100F temperature range

Minimum adhesion to steelDo not use above ground

Limited storage lifeTears in jacket can go length of pipe

Adhesive flows at low temperaturesPoor hydrocarbon resistance

Susceptible to C. shieldingHard to handle when hot

Tape Wraps(services < 140F)

25+ years experienceEasy to apply

Can be used for bendsCan be used to coat all sizes of pipes

Can be applied to pipe while in service

Susceptible to cathodic shieldingPoor coating-to-coating bond at overlap

Susceptible to soil stressesTemperature limited

Non-continuous coatingPoor service history

Coal Tar Enamel 60+ years experienceMinimum holidays on application

Low current required for C. protectionGood resistance to C. disbondmentGood subsea experience with weight coating

Available for all sizes of pipe

Carcinogenic fumes when applied PoorUV resistance

Cracking problem below 32FSoft when hot (100F)

Poor hydrocarbon resistance


30/45



cation site, chemical resistance, maximum service temperature, soil conditions,

accessibility to the line, and storage and handling.

Tape wraps are no longer recommended for new pipelines because their low cost

and the ease of over-the-ditch application are offset by a poor service history and

high failure rate. However, tapes are useful for repairing mechanically damaged

coatings, protecting large radius bends and tie-ins, and performing over-the-ditch

coating refurbishment when other coatings are not flexible enough or cannot be

field-applied.

Increasingly, liquid epoxies are being used to refurbish old coatings and for odd

geometries. These two-part liquids have chemical and temperature resistance prop-erties that are similar to FBE, and can be applied in the field. However, they do

require a sand-blast cleaned pipe surface and are relatively expensive.

No matter which coating is selected, surface preparation is critical. Poor or

improper surface preparation will cause any coating to fail prematurely.

350 Internal Coatings and Linings

This section briefly summarizes information from the Coatings Manual.For further

information refer to the Coatings Manual.

Pipe is internally coated or lined to prevent corrosion, to increase flow rates byreducing friction losses, to preserve product purity, or to prolong the life of an

existing line. In this section the term coatings refers to the relatively thin paint-

type coatings, while linings refers to the thicker cement or plastic, field applied

means application of a coating or lining to an existing pipeline. Figure 300-11gives

alternatives for internal coatings and linings.

Field Joint Coatings

Fusion Bonded Epoxy Best protection

Cost near to that of shrink sleevesSame material as on the lineSee above, Line Coatings

Near white metal surface prep required

Requires special equipment to applyUse on FBE lines onlySee above

Liquid Epoxies See above, Line Coatings See above

Shrink Sleeves Easy to apply by inexperiencedpersonnel

-30to 230F temperature rangeExtensive service historyMinimum surface prep required

(SSPC SP-3)Readily available

High temperature sleeves need heatapplication

Poor hydrocarbon resistance

Tape Wraps Not recommended, see above Not recommended, see above

Fig. 300-10 External Coating Alternatives (2 of 2)

Coating Advantages Disadvantages


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351 Epoxy Coatings

(1) Except as noted, costs are for lining an 8-inch pipe at the shop location. Pipe costs extra. Costs are for rough comparative purposes

only.

Shop applied, internal epoxy coating is generally available as a heat cured powder

or as a baked-on liquid. The powder is a thermosetting resin for application by the

fusion-bonded process, with or without primer. The baked-on liquid can be epoxy,epoxy-phenolic, or possibly a modified urethane with primer.

Field-applied coatings are limited to the liquid epoxies since a furnace cure is not

possible. The application method makes an experienced foreman crucial to

achieving a good result.

Fig. 300-11 Internal Coating/Lining Alternatives for Pipelines

MaterialRecommended

Services Advantages LimitationsApproximate

Cost(1)

Cement Lining Produced waterSalt water

Almost always fornew lines

Thick, usually veryreliable against

water corrosion

Joints are potentially aweak link, not good in many

chemicalsMin. Pipe diameter: 2-3

inchesTemp. approx. 250FPressure approx. 5000 psig.

Velocity approx. 10 fps

Shop = $1.60/ft.

Plastic Liner(shop applied)

Process chemicals Excellent corrosionresistance to avariety of services

Typically comes in 20-footflanged lengthsFlange joints can leak

Pipe diameter 1-16 inchesTemp. approx. 200F (PPL)

to approx. 500F (Teflon)

Including pipe andflanges = $80/ft

(PPL) to $300/ft(Teflon).

Plastic Liner

(Field applied)(HDPE)

Produced water

Salt waterNew existing lines

Very reliable Very

few joints Cansalvage

existing lines

Pipe diameter 3-16 inches(but larger sizes can bedone)

Temp.200F

$9.20/ft.

Coatings(Shop applied)

Produced waterSalt waterFlow friction reduc-

tion

Fair to good corro-sion resistance

Joints are potentially aweak link

Relatively thin film (maygive shorter, less reliablelife)

Coatings

(Field applied)

Produced water

Salt water

Flow friction reduc-tion

New or existinglines

Fair to good corro-

sion resistance

Good chance of field foul-

ups

Spotty history of qualitycontrol

Relatively thin film (maygive shorter, less reliable

life)


32/45



352 Plastic Linings

Linings are installed for new construction or can be installed through existing pipe-

lines to salvage a corroded line that would otherwise have to be replaced.

High density polyethylene (HDPE) liners are used to line pipelines in the 3- to 16-

inch size range. Installation is by wire-line pulling of sections up to 3000 feet longinto previously laid steel pipeline. Joints are made with buried flanges. The cost per

lineal foot is fairly high compared to cement lining (see Section 353) but may be

the only option. For instance, a HDPE liner was pulled through the expansion loops

and river crossing sag bends in an otherwise cement-lined pipeline because cement-

lined pipe could not have been bent.

A HDPE lining was used in the 4NPS flow lines for the Norphlet project to reduce

the need for inhibition. The liner failed during startup of the system. The conse-

quences of the failure are that significantly larger quantities of chemical inhibitor

are necessary to control the corrosion than would be required with a bare steel flow

line. While this is a negative experience it is believed that there is considerable

potential for cost savings with the use of these liners. It is stressed that front endengineering and testing to qualify a procedure for making the HDPE joints in long

pipelines is very definitely required for a successful application.

HDPE liners can effectively salvage existing corroded pipelines, even bridging

small leaks. For large (18 inch and above) the Companys own thin-walled HDPE

(Spirolite) can be used to line pipelines that operate below about 100 psig.

353 Cement Linings

Cement-lined pipe has been used in the United States for nearly 100 years. Cement-

lined steel pipe combines the physical qualities of steel with the protective qualities

of cement mortar. The lining creates a smooth, dense finish that protects the pipefrom tuberculation (the formation of scale or other nodules on the inner surface of

the pipe) and provides a relatively high flow coefficient. In addition to acting as a

physical barrier between the steel pipe and any potentially corrosive fluid, the

cement lining also creates an alkaline environment near the steel wall that helps

inhibit corrosion [1].

Chevron has successfully used cement-lined pipe for many years in both producing

and refining applications. Cement-lined pipe is most often used to protect carbon

steel pipe from corrosion in water/brine environments. Typical applications include

water injection systems in oil fields and fire water systems in large plants.

Applicable SpecificationsGeneral. There are several specifications you may use for cement lining steel pipe:

API RP 10E, Recommended Practice for Application of Cement Lining to

Tubular Goods, Handling, Installation and Joining.


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PPL-MS-1632, Materials and Fabrication of Cement-Lined Piping and Tubular

Goods. PPL-MS-1632 modifies API RP 10E, which is intended for oil produc-

tion related uses.

AWWA STD C602-83, Cement-Mortar Lining of Water Pipelines in Place.

AWWA STD C205-85, Cement-Mortar Protective Lining and Coating for SteelWater Pipe4 In. and Larger ShopApplied.

ANSI Standard A21.4, Cement-Mortar Lining for Cast Iron and Ductile Iron

Pipe and Fittings for Water.

API RP 10E and Company Specification PPL-MS-1632 (used in conjunction) are

the recommended specifications for cement-lining of pipe for produced water, rein-

jection water, brine, and salt water service in the oil field.

For some piping intended for fresh or brackish service the AWWA Standards are

often good enough. Many small applicators use the AWWA standards and are not

familiar with API RP 10E. Refineries and chemical plants have successfully lined

pipe to the AWWA Standards for fresh and seawater service.

How to Specify. API RP 10E is the recommended specification for cement lining

both new and used pipe. Specification PPL-MS-1632 should be used in conjunction

with API RP 10E for cement-lining new pipe. In-place (in-situ) cement lining is

sometimes done on existing pipe to extend the life of internally corroded pipe, as

well as for lining new pipe on site. PPL-MS-1632 should still be used along with

the API specification even though it does not directly address in-place lining. PPL-

MS-1632 still gives guidance on cement selection, gasket selection, etc.

API RP 10E is preferred primarily because it covers sulfate- resistant cements with

low tricalcium aluminate (C3A) and is a more stringent specification and more

appropriate for oil producing or refining services. Company specification PPL-MS-1632 is based directly on API RP 10E and modifies it by adding or deleting require-

ments from several paragraphs.

Many cement lining vendors are not familiar with the API practice and commonly

use the AWWA standards. In several instances the AWWA standards have been

used in lieu of the API standard. The Richmond Deepwater Outfall Project is one

example. Generally, if the water being piped is fresh or mildly brackish and the

piping system is not deemed critical, specifications other than the API RP 10E are

adequate. Examples of noncritical systems are potable water, domestic drainage,

and sewage systems.

The AWWA Standards have been used in the past with requirements added for steel

pipe, curing, joining, etc. Contact the CRTC Materials and Equipment EngineeringUnit for assistance with the specific requirements for your project.

Steel Pipe Requirements

Company Specification PPL-MS-1050 supplements API SPEC 5L. See Section 310.

Thickness and straightness are two very important requirements for steel pipe to be

cement-lined. Thickness is more important than the grade. If the pipe is thin-wall, it


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is more apt to be dented, formed out-of-round, or to become bent. Section 2 in API

RP 10E and PPL-MS-1632 cover pipe thickness requirements.

Pipe should be straight to within 1/8 inch per 10 feet of length. This is not covered

in API RP 10E but is used by several cement lining applicators.

Spiral-welded pipe is not used for cement-lined pipe that conforms to API RP 10Ebecause the cement cannot be applied by the rapid spin method. The raised weld

profile causes the pipe to vibrate severely, and bounce or wobble during applica-

tion, when spinning speeds can reach 700 rpm. This prevents the application of a

good, dense lining and may damage equipment.

However, spiral welded pipe has been successfully lined using other lining

methods. These methods utilize a heavy slurry sand cement and involve slower spin-

ning speeds and hand trowelling. This type of cement-lined pipe is covered in the

AWWA specifications and is appropriate for low corrosive and noncritical systems,

as mentioned earlier. Richmond Refinery made successful use of spiral-welded

cement-lined pipe for the deep water effluent outfall line.

Types of Cement Linings

Cements. The Company specifies Portland cement conforming to ASTM C-150

Type I, Type II, Type III, or Type V depending on the sulfate levels of the water that

the pipe will transport. Sulfate ions attack cement linings by reacting with the

cement and forming gypsum, which occupies about 18% greater volume than the

original cement. The gypsum in turn reacts with C3A to form a complex hydrate

crystal which expands to over 200% of the volume of the original constituents[2].

This causes the lining to spall and crack, and eventually to fail.

Types III and V cement are specified for high concentrations of sulfate (above 5000

ppm and 1500 ppm, respectively). Limits are placed on the content of C3A in the

cement. Cements with low amounts of C3A are resistant to sulfate attack. Type II

cement may be used for moderately sour water with sulfate levels below 1500 ppm.

Type I cement may be used for fresh water with sulfate levels below 200 ppm.

Fresh and potable water generally have less than 40 ppm of sulfates and seawater

has around 2650 ppm. These levels vary; the engineer should obtain an analysis of

the water the pipe will transport.

Experience. Two types of lining mixtures have dominated cement-lined pipe tech-

nology over the last 25 years: pozzolanic cements,containing 60% cement and

40% pozzolans; and sand cements containing 60% sand, 35% cement, and 5%

pozzolans[2]. Pozzolans are fine particles of silica and alumina that react with lime

to form calcium silicate and aluminates.

Experience has shown that pozzolan cements are more sulfate resistant, and sand

cements are more acid-resistant [2].

CUSA Producing, Northern Region has used 60% cement/40% pozzolan linings

successfully for many years in injection systems high in sulfates conditions. This

type of cement has a lower permeability than sand cements and therefore provides

more resistance to water diffusing through the pipe and corroding the steel [3].


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Cement Lining Application

Chemical Attack. As with almost any type of coating or lining, proper application

is one of the most important variables in the overall success and longevity of the

coating or lining. For cement linings, proper mix proportion is equally important.

Shop-Applied. Straight sections of pipe are lined with a machine that spins thepipe joint and centrifugally applies cement linings to the interior of steel pipe. The

entire pipe section is lined to a uniform thickness without interruption. Once the

desired thickness is obtained, the rotation speed is increased to produce a dense

cement with a smooth surface and a minimum of shrinkage.

Elbows, bends, and other shapes must be lined using mechanical placement, pneu-

matic placement, or hand application techniques. The cement is often reinforced in

these cases with a wire fabric reinforcement. The thickness may be varied to make

a smooth transition with adjoining sections of pipe but is otherwise the same as

centrifugally spun straight sections [4].

Several things can go wrong during the lining process and must be watched for:

Excessive acceleration up to spinning speed leads to poor spreading of cement

and results in lining eccentricity.

Too high a spinning speed and too long a spin duration result in particle size

segregation in the lining.

Applicators must vary rotating speed for different pipe diameters to ensure

proper centrifugal forces, which determine liner density.

Holddowns, or rollers, should be spaced about one per every 7 feet of pipe.

This helps reduce vibration and eccentricity.

Field-Applied or In-Place. Field application is done in three basic steps. First, amechanical scraper with wire brushes is run through the line enough times to

remove heavy scale and deposits. Then, a rubber pig is run through the line to

remove sand, debris and water. Finally, the cement coating is applied. Application

is by a moving head that centrifugally shoots the mortar onto the steel pipe. A

conical trowel almost immediately smoothes out the cement to a uniform thickness.

The pipe ends are then sealed to prevent moisture loss [5].

Curing. Specification PPL-MS-1632 requires all shop-applied cement linings be

steam-cured. Steam curing accelerates the chemical (cement hydrolysis) curing

process and brings the cement to full strength much quicker than an atmospheric

cure will. Steam curing does not alter the linings chemical resistance properties.

Most, if not all, field applicators of cement linings are unable to steam cure. In

these cases, the atmospheric curing requirements in API RP 10E, Section 3.4b,

should be strictly enforced.

Quality Control Procedures. The Company should inspect the contractors plant

during application to ensure proper lining procedures are being used. The Company

should also inspect the finished product and review the applicators certification

documents to ensure that the cement used for lining meets the required specifica-


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tions. Certification and testing are covered in Sections 4 and 6, respectively, in API

RP 10E.

Cement Lining Applicators. Listed below are several cement lining applicators.

The list is not complete, nor is it an approved bidders list.

Joining Cement-Lined Pipe

Gaskets. Gaskets are needed to protect the inner surface of steel pipe joints once

the pipe is put into service. Gaskets for butt-welded joints must be heat-resistant to

withstand the heat of welding. Asbestos has been used for many years and has been

largely successful [3]. We believe that asbestos gaskets may still be used in compli-

ance with environmental and health regulations because the gaskets are installed in

the outdoors and never exposed once the joint is welded. However, the engineermust check the current regulations concerning the use of asbestos gaskets. The

governing regulations are listed on page three of API RP 10E.

If the operating company or the governing regulations prohibit the use of asbestos

gaskets, API RP 10E lists an alternative to asbestos. This is a new product with

limited field experience. We believe that the flexible graphite sheet will work well,

but it costs considerably more than asbestos.

Chevron Canada Resources has successfully used an Inconel wire-mesh-impreg-

nated gasket for welded joints. These gaskets are available through Alberta Gaskets

in Alberta. The CRTC Materials and Equipment Engineering Unit can provide assis-

tance with selecting nonasbestos gasket materials.

Joints. The Company has used butt-weld, sleeve, and slip-on flange joints. Butt-

weld joints are preferred because they are stronger and stiffer than sleeve joints.

Slip-on flange joints are hardly ever used because welding heat damages the

cement lining. Screwed-on flanges are possible but not recommended. See

Figure 300-12for illustration of a butt-weld cement-lined pipe joint.

Armor Cote, TX 915/332-0558Permian Enterprises, TX 915/683-1084

Ameron, CA 213/268-4111

Spiniello Construction Co., CA 213/835-2111

Heitkamp, CT 203/274-5468

Burke Industries, CA 408/297-3500

Progressive Fabricators, MO 314/385-5477

Thompson Pipe and Steel, CO 303/289-4080

U.S. Pipe and Foundry, AL 205/254-7000

American Cast Iron Pipe Co., AL 205/325-7701Bitco, CA 415/233-7373

Shaw Pipe Protection, Alberta


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Welding procedures for cement-lined steel pipe have traditionally been standard

pipeline procedures, with incomplete penetration on the root pass to avoid damage

to the cement and gasket. Electrodes have generally been of the EXX10 type. Some

recent experience in Canada has suggested that these electrodes, which leave more

hydrogen in the weld, may combine with the stress riser of the incomplete penetra-

tion weld to produce root cracks.

A welding procedure using EXX18 low hydrogen electrodes and an inconel wire-

reinforced composition gasket has been developed by Chevron Canada Resources.

The procedure allows more weld penetration (90+%) and thus a stronger weld. The

procedure isdownhillfor NPS 2 pipe and uphillfor NPS 3 and larger. The uphill

procedure appears slower but will save on repair time. Contact the Design and

Construction Group in Calgary for further information.

Branch Connections. Branch connections are preferably made with cement-lined

tees. Branches may be made with bosses or weld-o-lets that have been fabricated

into a pipe spool and cement-lined in the shop. Good advance planning and design

will allow ordering shop lined branch components with connections and fittings

attached. If field cutting must be done use a hole saw. A hole saw is a cylindrical

saw attached to a drill. A cement-lined weld-o-let should be welded on and the

internal lining repaired with a repair compound such as X-Pando.

Field torch-cutting for branches should be avoided as this damages the cement

lining. Repatching these damaged areas is difficult, especially for small connections

and fittings. Ordering extra tees, fittings, and flanges will prevent delays in field

work and result in better lining integrity.

Typical Problems with Cement Linings

Chemical Attack. Cement linings can be corroded by many different chemicals

[2]. Examples are:

Strong acids with pH below 5.0

Carbonic acids

Fig. 300-12 Butt-weld Cement-Lined Pipe Joint

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