PPL800 Operations and Maintenance

8/12/2019 PPL800 Operations and Maintenance

1/37

Chevron Corporation 800-1 July 1999

800 Operations and Maintenance

Abstract

This section discusses several topics related to pipeline operations and mainte-

nance. It is not a comprehensive description of the organization and procedures for

operating and maintaining a pipeline system.

Contents Page

810 Safety 800-3

811 Regulations and Codes

812 Spill Contingency Plan

813 Damage to the Line

814 Hot Lines

820 Gas Hydrates 800-5

821 Hydrate Prediction

822 Hydrate Prevention

823 Hydrate Removal

824 Hydrates Bibliography

830 Risk Assessment, In-Service Inspection and Testing 800-11

831 Risk Assessment

832 Electronic Inspection Pigs

833 Corrosion Coupons

834 Hydrostatic Testing

835 Coating Quality

840 Leak Detection by Physical Methods 800-22

850 Hot Tapping 800-23

860 Pipeline Repairs 800-23

861 Special Repair Fittings

862 Clock Spring Fiberglass Coils


2/37

800 Operations and Maintenance Pipeline Manual

July 1999 800-2 Chevron Corporation

863 Full Encirclement Sleeves

870 Maintenance Program in Areas of Unstable Soils or Earthquakes 800-35

880 In-Service Line Lowering 800-35

890 References 800-37


3/37

Pipeline Manual 800 Operations and Maintenance


810 Safety

811 Regulations and Codes

Title 49, Code of Federal Regulations (CFR) Parts 191, 192, and 195 and

ANSI/ASME Codes B31.4 and B31.8 have subparts or chapters devoted to pipeline

operating and maintenance procedures and records. Broadly, these require: written

plans for normal and emergency procedures, periodic updating of procedures, oper-

ation in compliance with procedures, records, training of personnel, and education

of authorities and the public regarding hazards and emergency action programs.

State regulations may have further requirements. These are generally described and

are minimum standards.

Examples of written plans for normal and emergency pipeline procedures can be

obtained from the Operations Section of Chevron Pipe Line Company.Appendix D

includes:

Pipeline Operating ProceduresAbnormal and Emergency Situations, Stan-dard No. 4.2 of Chevron Pipe Line Company, New Orleans Division; 7-24-87.

Table of Contents and general section of Operation and Maintenance Plan

Guidelines for DOT-regulated Gas Pipelines, CUSA Eastern Region; 11-85.

812 Spill Contingency Plan

Governmental regulations and permit conditions require preparation of written plans

and procedures for dealing with accidental spills from liquid pipelines. A compre-

hensive spill contingency plan must be included with the pipeline operating and

maintenance procedures. The contingency plan and procedures should comply with

33 CFR 153,Navigable Waters, and 40 CFR 112, Protection of the Environment.

A spill contingency plan needs to consider a wide variety of factors:

Geographical elementstopography, surface conditions, soil type, drainage

pattern, accessibility, etc.

Environmental conditionsweather, hydrology, rare and endangered species,

developed areas

Pipeline system elementspumping rates and controls, line draindown

volumes, block valve locations, and closing response times

The response procedures for each major surface drainage pattern area incorporated

in the plan need to cover:

Organization of the spill response teamCompany personnel plus local offi-

cials and contractors as appropriate

Procedure to locate and assess the spill and initiate control and cleanup proce-

dures
http://pplappd_.pdf/http://pplappd_.pdf/


4/37



Notification of government and local authorities and public relations informa-

tion

Procedure to control or limit the amount spilled, evaluating threats to public

safety and sensitive areas

Procedure to clean up and restore contaminated ground, shorelines, and watersurfaces

Availability and location of equipment, materials, and labor crews needed for

all response actions

Documentation of the spill incident, response, cleanup, and restoration

Training plan and safety coordination

Procedure for handling damage claims

For consultation on preparation of spill contingency plans, contact Chevron Pipe

Line Company or a Company Health, Environment, and Loss Prevention represen-

tative.

813 Damage to the Line

Risk of damage to a pipeline by activities of others can be minimized by:

Surface markers, identifying the location of the line and giving information

regarding the proper Company contact to notify before proceeding with work

Frequent surveillance of the route, on the ground and by air, to observe activi-

ties by others and changes in ground conditionsnew construction, mainte-

nance work, agricultural cultivation and grading, canal maintenance, erosion,

land slips and slides, etc.over or near the pipeline or progressing toward theline from another area

Participation with Underground Service Alert Center or equivalent agency

established to coordinate notifications regarding work on underground facilities

Regular contacts with owners, authorities and contractors regularly working in

the vicinity of the line to learn about planned and forthcoming construction that

might jeopardize the pipeline

814 Hot Lines

Lines that carry hot fluids and are designed as restrained lines to limit expansion

movements should be closely monitored at bends along the route to detect unex-

pected expansion problems. This is particularly critical at the initial warm-up of a

new pipeline in hot service, whether from a wellhead, compressor station, or heated-

oil heating station, because pipe-soil friction values may not have developed to

values used in design calculations. Also, warm-up and cool-down cycles over a

period of time may result in progressive movement of the buried line toward the

surface of the ground, reducing the effect of cover over the pipe. All overbends,


5/37



tight sidebends, sidebends with large angles of deflections, and buried-to-above-

ground transitions should be inspected.

Temperatures of fluids entering the pipeline should not exceed the design

maximum, in order to avoid risk of severe consequences of coating damage, pipe

buckling in compression, and popping out of the ground due to insufficient

restraint by the soil.

820 Gas Hydrates

Gas hydrates are very complex, solid crystalline compounds formed when hydro-

carbon gases containing water are cooled. Hydrates can form at temperatures well

above the freezing point of water. Hydrate formation is a function of gas composi-

tion, water content, temperature, and pressure. In general, higher water content,

higher pressure, and lower temperature promote hydrate formation.

Gas hydrates appear like ice or closely packed snow. The crystals will accumulate

on the walls of pipe, especially at elbows and orifices and other restrictions. Hydrate

plugs are as strong as ice plugs and more difficult to remove since they require

higher temperatures to melt.

821 Hydrate Prediction

The engineer must be able to predict hydrate formation. Hydrates must be consid-

ered whenever one is handling hydrocarbon gases containing water. Hydrates may

be a problem in the following situations:

High-pressure gas lines where the gas is cooled in transit

Valves or other throttling devices that cool gas by expansion

High-pressure process lines

In these and many other instances, it is important that the engineer be able to predict

the hydrate formation temperature in order to:

Determine whether special precautions are necessary to prevent hydrates

Determine whether installation of a gas dehydrator or gas heater, insulation of

lines and equipment, or other plant modifications represent the economical way

of preventing hydrates

Prepare specifications for heaters, dehydrators, and other special equipment

required

Charts are available that allow the prediction of hydrate formation based on gascomposition, pressure, temperature and water content. The reader should refer to the

references at the end of this section or to theEngineering Data Book, Volume 2, Gas

Processors Suppliers Association (GPSA), for more complete information and

charts.

The solubility of water in various hydrocarbon liquids varies substantially, and the

effects of composition increase with pressure. High gravity gases are less linear in


6/37



their solubility behavior. When the gas contains more than about 5% CO2and/or

H2S, one should correct for the acid gas components, especially above 700 psia.

Figure 800-1shows one correlation for lean, sweet natural gases containing more

than 70% methane and small amounts of heavy ends. This figure has been widely

used for gas dehydrator design and is adequate for most first approximations. In the

figure, hydrates will probably form in conditions below and to the left of the hydrate

formation line.

For systems that are more complicated, a more rigorous treatment should be

performed. The methods in the GPSA Data Book offer correction factors for most

deviations from normal. However, for best results, a gas compositional modeling

computer program, such as PPROP (available on the VM System), should be used.

Hydrates most commonly form when wet gas is expanded. Figures800-2to800-7

correlate gas gravity with permissible gas expansion without forming hydrates. As

in Figure 800-1, they are first approximations only.

822 Hydrate Prevention

Because water is necessary to form hydrates, prevention of hydrates is most effec-

tively accomplished by removing the free water. This may be done in two ways:

dehydration

inhibition

Dehydration is generally preferable because it removes the water from the gas

stream. The higher capital cost must be weighed against the continuous cost of inhi-

bition chemicals.

Inhibition is usually accomplished by injection of methanol or a glycol into the gas

stream to preferentially absorb the water. Methanol is expensive but effective andpreferred at cryogenic conditions. Ethylene glycol is less expensive and more easily

recoverable, except at low temperatures where its viscosity is very high. It is also

less soluble in the liquid hydrocarbons that tend to occur in producing field gas

systems. Diethylene and triethylene glycol can also be used. The glycols can be

recovered and regenerated for reuse.

Inhibitors are injected into gas lines easily with low cost equipment. However, to be

effective the inhibitor must be present at every point where the gas is cooled to its

hydrate temperature.


7/37



Fig. 800-1 Water Content of Hydrocarbon Gas


8/37



Fig. 800-2 Pressure-Temperature Curves forPredicting Hydrate Formation

Fig. 800-3 Permissible Expansion of a 0.6 GravityNatural Gas without Hydrate Formation




9/37



The minimum inhibitor concentration necessary to prevent freezing in the free

water phaseis given by the Hammerschmidt equation:

(Eq. 800-1)

where:

d = difference between gas hydrate temperature and system tempera-

ture, F

KH = 4000 for glycols

= 2335 for methanol

I = inhibitor ratio, lbm/MMSCF

MW = molecular weight of inhibitor

The total quantity of inhibitor injected must also be sufficient to inhibit the vapor

phase and provide for the solubility of the inhibitor in any liquid hydrocarbons.

Significant quantities of methanol will vaporize, while glycol will not. The total

quantity of inhibitor needed in the vapor phase may be three times that needed for

the water phase.



dK

HI

100MW MWI--------------------------------------=


10/37



823 Hydrate Removal

Once formed, hydrates are often very difficult to remove. Hydrates that form in

pipelines must be treated carefully. The method of removal depends on the specific

situation.

Aboveground pipingcan usually be heated easily. Different methods ofapplying heat include:

Torches which are quick and effective but cannot be used in hazardous

areas.

Steam, glycol, or electric tracing, if available, heat more slowly than

torches but are safer.

Directly applied steam may be available.

An induction heating coil may be desirable.

Lines that can be taken out of servicemay be depressurised; since pressure

contributes to hydrate formation, depressuring the pipeline will often let the

hydrate sublime. This is the simplest method for lines that can be taken out of

service.

When service must be maintained, large amounts of inhibitor (methanol is

preferred) may be injected. Sometimes the application of increased pressure

will loosen and blow out the hydrates. One must be careful not to exceed the

maximum allowable operating pressure (MAOP) of the pipeline.

For problem blockages in short gathering lines, try depressuring and then

circulating hot oil to heat the hydrate and the pipe. Pressure is often applied in

conjunction with the hot oil. Again, be careful not to exceed the MAOP or

maximum temperature of the pipeline or its coating.

In extreme cases, the only solution is to sectionalize the pipeline by

hot-tapping to locate and remove the hydrate plug.

824 Hydrates Bibliography

The following published reports are available on the subject of hydrates:

1. Gas Hydrates and Their Relation to the Operation of Natural-Gas Pipe Lines

United States Department of Interior, Bureau of Mines, Monograph 8.

2. Natural Gas HydratesTechnical Data Book, Hydrocarbon Research, Inc.,

Curves E-16.300 to E-16.304, inclusive.

3. Donald L. Katz, Prediction of Conditions for Hydrate Formation in Natural

Gases, (Technical Publication No. 1748 of the American Institute of Mining

and Metallurgical Engineers). Petroleum Technology. June 1944.

4. Pryor, Arthur W. Memorandum on the subject Study of Possible Hydrate

Formation at McDonald Island Pipe Line No. 2 Control Station. November 8,

1949.

5. Ingersoll, W. L. Memorandum on the subject Use of Alcohol to Prevent

Hydrate Formation. March 9, 1950.


11/37



830 Risk Assessment, In-Service Inspection and Testing

Pipelines, by their nature, are difficult to inspect, hard to protect and can run

through sensitive areas. Like other facilities, pipelines can be crucial to local

production. They may contain hazardous materials. Long and/or large diameter

pipelines are a large capital investment. Consequences resulting from an incident

can be quite severe. The risk associated with pipelines, therefore, is among the

highest in the Company.

Risk assessment (see Section 831) helps Operators quantify and manage the risks

associated with pipelines.

In-service inspection and testing are prudent measures that should be taken for veri-

fying the integrity of an operating pipeline system over the years. The following

topics are discussed further in sections 832through 835:

Wall thickness inspection by electronic inspection pigs

Corrosion coupons inspections

Hydrostatic testing Coating quality inspection

Cathodic protection surveys

The Department of Transportation requires that the operator of a pipeline system

prepare an operations and maintenance plan (see 49 CFR 195.402 and 192.605), but

specific inspection and testing measures and frequency are not defined. Each pipe-

line operating organization should therefore develop a program suitable for its

particular facility. Other than where federal or state regulations mandate specific

inspection and testing intervals, the program should be tailored to the individual

pipeline system.

831 Risk Assessment

The purpose of this section is to help Operators quantify and manage the risks asso-

ciated with pipelines.

What is Risk?

An incident is an occurrence that negatively impacts business. Pipeline incidents

include, but are not limited to, oil spills, gas leaks, injury, lost revenue, and nega-

tive press coverage. Operators must determine the likelihood of an incident occur-

ring and understand the potential consequences. These two elements combined,

consequence and likelihood, represent the risk. Once the risks are clear, the Oper-

ator chooses whether to:

take action to prevent the incident from occurring;

attempt to mitigate the consequences; or

monitor for impending failure.

Preventing an incident is preferred unless the cost to do so is excessive compared

to the consequences.


12/37



It is our strategic goal to be a safe, socially responsible and profitable operator. Risk

assessment helps us achieve these goals.

What is Risk Assessment?

An incident is rated as high risk if it is extremely likely to occur and would result

in severe consequences. An incident is rated as low risk if it is unlikely to occurand would result in only minor consequences. SeeFigure 800-8.

Once risk is determined and rated, the Operator can choose to:

Prevent the incident from occurring or reduce the probability of occur-

rence. This is a good way to reduce risk and should be considered first.

Monitor for impending failure.

Sometimes this is more practical. Inspection for corrosion is an example of

monitoring a risk. Because all pipelines eventually corrode, we monitor corro-

sion in order to predict a leak and take action before it occurs. It is more prac-

tical to monitor for corrosion than to replace the line every ten years.

Mitigate consequences.Mitigation starts with the assumption that the incident will occur. Projected

consequences are then reduced through pre-planning. Oil spill drills and initial

route selection are examples of mitigating consequences.

Fig. 800-8 Typical Risk Matrix


13/37



Methods Used for Assessing Risk

Commercial and internal models for risk assessment exist:

1. Kent Muhlbauers Pipeline Risk Management Manual: A Systematic

Approach to Loss Prevention and Risk Assessment

This is the only commercial model widely recognized and used. The Operatoranswers a list of standard questions provided. A numerical weighting system is

applied to the answers and the resulting numerical score indicates the degree of

risk calculated. Mr. Muhlbauer has recently published Win95 software to assist

users in performing risk assessments using his method.

While many Operators use this system, little documented confirmation of

results exists. Perhaps the benefit comes mainly from the questions provided,

which stimulate thought and help in prioritizing pipelines. However, his

approach has not been widely adopted within the Company.

2. The CPL Risk Assessment Process

This standardized method, practiced by Chevron Pipe Line Company (CPL), is

used to determine yearly expense allocations to obtain the highest overall risk

reduction. It relies on local experts and experience to judge both the likelihood

and consequence of an incident. Refer to the following section for details.

CPL Risk Assessment Process

A key factor in the success of this program is the use of dedicated facilitators who

help all sites implement risk assessment the same way. This results in conclusions

that are consistent and comparable among sites.

The process starts with a visual inspection of the lines from beginning to end. After

the visual inspection, a group consisting of the best local expertise gathers to begin

risk assessment. Membership of the group is important. Accurate analysis depends

on experienced judgment on relative probabilities. Inexperienced opinion results in

inaccurate assessments.

The risk assessment process consists of the following:

Phase 1 - generating scenario, estimating likelihood of occurrence and severity

of consequences

Phase 2 - reviewing current risk reduction activities and new project nomina-

tions

Phase 3 - determining cost of proposed prevention/mitigation projects

CPL Risk Assessment Process - Phase 1

Generating the Scenario. An experienced site person describes the pipeline using a

drawing or map highlighting all major impact areas (schools, streams, freeways,

etc.). Physical properties, repair history and process limits are reviewed. The group

brainstorms failure scenarios. The facilitators use a master list of pipeline failure

causes to prompt the group and to make sure all known scenarios are considered.


14/37



Estimating the Likelihood of Occurrence. The group then creates risk maps based

on the generated scenarios. More than one risk map may be needed.Figure 800-9

shows an example of the risk associated with a pipe located near a high school.

Should it leak due to internal corrosion, what would be the risk? The group

concluded that no one would suffer injury and that the negative consequence would

be limited to a precautionary evacuation and bad press coverage. Experienced teammembers judged a once in ten-year probability of a leak as being appropriately

conservative. Then the group estimates the probability of a small vs. a large leak,

and the probability of a precautionary evacuation.

Estimating the Severity of Consequences. The group then estimates the severity

of consequences for each risk map. Using the Consequence Criteria in

Figure 800-10, the group considers each category as it relates to the risk map and

rates it as high, medium or low.

Fig. 800-9 Risk Map for a Leak Near a High School

Fig. 800-10 CPL Consequence Criteria Categories

1. Public and Worker Health and Safety

2. Environmental Resources

3. Public Concerns

4. Regulatory Compliance

5. Financial Performance


15/37



For each category, several questions are asked with respect to current status of risk

mitigation practices. It is typical that several risk prevention and mitigation strate-

gies are already in place. Review of these helps the group estimate realistic conse-

quences and probabilities.

After doing a few risk maps and consequence evaluations, typical patterns begin to

emerge and the process speeds up considerably. Once all the scenarios are evalu-

ated, the probability and consequence data is mapped onto a single chart

(Figure 800-11).


Reviewing Current Risk Reduction Activities / New Project Nominations. At

the second meeting, the group focuses on selecting scenarios that merit further

discussion and developing projects that help prevent or mitigate potential incidents.

Usually, the scenarios with the worst consequences and highest likeligood of occur-

6. Customer Satisfaction

7. Employee Commitment

8. Strategic Alignment

NOTE: This list is specific to CPL. Other operating Companies can and do choose different criteria. What is key,

however, is that there is only one set of criteria within an Operating Company.

Fig. 800-11 Sample Risk Map

Fig. 800-10 CPL Consequence Criteria Categories


16/37



ring are considered first. In many cases, preventing one cause can reduce the risk for

several scenarios.

The group estimates the costs of implementing risk reduction strategies and then

estimates the level of risk reduction achieved if a strategy is implemented.


Determining Cost of Proposed Prevention/Mitigation Projects. The final phase

of the process consists of outlining the cost of implementation and benefit achieved.

The group completes a standardized form for each project which allows it to be

easily compared to other risk reduction efforts currently in place. The result is a

final Benefit-to-Cost ratio used for project ranking.

The CPL process standardizes risk evaluations and ensures that the most serious

risks receive priority funding. It is an efficient process that provides a large return

for a small investment.

CPL Risk Assessment Process - Resources for More Information Steve Walston, CPL the Woodlands, CTN, 281 363-7204, (stww)

Chris Baumbauer. CPL San Ramon, CTN 510 842-6807, (ccba)

CPL Risk Management Home Page

http://www-cpl.chevron.com/cplrm1/

832 Electronic Inspection Pigs

Electronic intelligent pigs (smart pigs) are the most effective way to assess pipeline

integrity for corrosion defects. Although smart pig runs can be quite expensive, they

provide a detailed survey of almost 100% of the pipe wall while searching for areas

of metal loss or cracking.

Smart pigs can be used while a pipeline is either in or out of service:

When a pipe is in service, force to push the pig down the line comes from pres-

sure drop across the pig.

When a line is out of service, tethered smart pigs are pulled through the pipe

using a wire line (or tether).

After the run, data is retrieved from the pig and analyzed.

Inspection Methods

Smart pigs primarily use one of two methods for inspection Magnetic Flux

Leakage (MFL) or Ultrasonic (UT):

MFL can be used in either oil or gas lines. When using MFL tools in gas lines it

can be difficult to control the speed of the tool. Gas bypass is available on some

tools to control the speed and minimize impact on production.

Ultrasonics are easiest to use in liquid systems (UT needs a liquid couplant to

work). However, UT tools can be adapted for gas lines by sequencing the tool

in a liquid pill between two cleaning pigs.


17/37



Recent developments in UT have seen tools developed for detecting external stress

corrosion cracking and tools with a gas bypass to minimize production impact on

high volume lines.

Specialized MFL and UT tools are designed to:

use in sour service maximize travel distance

negotiate tight bends.

optimized to allow pigging through multiple line sizes

in hot systems

optimized for very thick wall pipe, or very thin wall pipe

map out the line using inertial referencing (often called geopigs)

size the ID or look for dents (often called caliper pigs)

Line Design May Preclude Pigging

Original line design may preclude smart pigging. Some lines, however, may be

modified to make them piggable without spending a great deal of money.

Lines may be poor candidates for intelligent pigging under the following circum-

stances:

The line contains bends with a radius of 1.5D or less. Note some of the newer

tools have been configured to allow pigging down to and including 1.5D bends.

The line contains miter joints over 10 degrees. Miter joints are unusual except

on very old lines.

The line contains unbarred branch connections. Depending on branch size,

orientation, flow direction and control over pig speed, smart pigging may be

possible.

The line contains reduced port valves (often done on older lines to save money

on valve costs).

Line diameter changes by one or more standard pipe sizes. Again, depending

on specifics, smart pigging may be possible.

The line does not have pig launching or receiving capability. Note there are

pipeline service companies that will rent horizontal and vertical pig traps for

smart pigging use.

High vs. Conventional Resolution Smart Pigs

Inspection sensitivity depends on the number of sensor heads in the tool:

Smart pigs that use more sensor heads (making them highly sensitive) and givequantitativewall thickness data are commonly called high resolution tools.

Tools that use fewer sensor heads are called conventional resolution tools.

These tools provide qualitativedata. Conventional resolution pigs are consider-

ably less expensive than high resolution.

Conventional resolution tools can be cost effective where the line is in relatively

good condition with few areas in need of repair and where repair cost is low.


18/37



Conventional resolution tools have been used where the accessibility for cut out is

good. For example, in CCR in some lines where conventional resolution tools were

used, all defects greater than 30% of wall loss were cut out. However, conventional

resolution tools, even when run by a reputable vendor, can miss problems. This

occurred at least once. A significant site of external corrosion was missed and a

multi-million dollar spill resulted. The cause is suspected to have been thick, tightmagnetic OD corrosion scale saturated with high conductivity water. These condi-

tions are thought to have allowed the scale to carry more magnetic flux, making the

pipe wall look thicker than it really was. This line is now inspected using a high

resolution ultrasonic pig at a cost premium of five times over the prior conventional

resolution technique.

Conventional resolution results are higher in false positives than high resolution

tools. If cost to repair is very high, like subsea lines, high resolution tools may be

justified. High failure costs may also justify use of high resolution to obtain the

maximum protection against a multi-million dollar incident. Tethered tools are typi-

cally used on shorter sections in lines where just a river crossing, for example, may

have a high failure consequence. Short, high consequence inspections like these canbe done at reasonable cost. Tethered tools have now been developed for use to

impact the riser section of offshore platform pipelines.

Key to getting the most value from a smart pig is working closely with the vendor to

ensure that all of the many details are communicated correctly and acted upon.

Overlooking or not handling correctly just one detail can potentially cause a pig to

stick in the line. Once a pig is stuck, the line must be shut down, the pig located and

cut out of the pipe, and both the line and the pig must be repaired. Usually,

unpleasant discussions with Operations follows such an event. Avoid this situation

by working with the vendor who will suggest a preparation plan of cleaning and

sizing pigs to prevent such problems. Chevron Pipelines procedure for pigging lists

many of the details Chevron must supply to the vendor (see Additional Resources).

After a successful run, review the results and verify that they are consistent with

known features and corrosion hot spots. Interpretation errors have been known to

occur.

Figures 800-12through 800-14further detail characteristics of specific types of

intelligent pigs.

Fig. 800-12 ultrasonic vs MFL Metal Loss Inspection Tools (1 of 2)

Ultrasonic MFL

Requires a fluid couplant No fluid couplant required

Direct measurement No direct measurement

Tends to be best at detection of defectsless than 60% of pipe wall

Tends to be best at detection of defectsgreater than 30% of pipe wall

Generally works best on pipelines with awall thickness greater than a half inch

Generally works best on pipelines with awall thickness less than a half inch


19/37



May not detect corrosion damage or accu-rately measure depth of corrosion pitswhere remaining pipe wall has been

reduced to less than 100 mils (2.54 mm)

May not detect corrosion pitting less than30% of the pipe wall

Requires the removal of internal scale inorder for ultrasonic sensors to work prop-erly

Not as sensitive to internal scale as anUltrasonic tool

Best tool for monitoring corrosion rate anddetecting internal corrosion activity

Ability to monitor corrosion rate is limiteddue to measurement accuracy limitations

Fig. 800-13 Conventional vs Advanced MFL Tools

Conventional MFL Advanced MFL

Fewer sensors therefore lower defect

resolution

More sensors therefore greater defect

resolutionRequires special analysis to get estimatedcorrosion pit length, depth and shape infor-mation

Requires special analysis to get estimatedcorrosion pit length, depth and shape infor-mation

Cannot tell if corrosion damage is internalor external, however corrosion signaturesometimes can be used to make aneducated guess

Has sensors to determine if the corrosion isexternal or internal but the process is not100% accurate

More economical inspection cost but morephysical inspections may be required todetermine the condition of the pipeline

Higher inspection cost but improved accu-racy may reduce the number of repairsrequired resulting in lower overall project

costsLong sections of pipeline can be inspectedin one run

Battery or data storage limitations mayresult in several runs on long sections toget a complete survey

Fig. 800-14 Tethered vs Self-Contained Tools

Tethered Self-Contained

Real time data transfer Memory storage

Requires no fluid to pump Requires fluid to pump

Controlled logging speed Speed altered by fluid fluctuations

At least 2 passes Only one pass possible

May have to cut the pipe May not have to cut the pipe

3 km runs ~100 km runs

Fig. 800-12 ultrasonic vs MFL Metal Loss Inspection Tools (2 of 2)

Ultrasonic MFL


20/37



Data Developed by Smart Pigging

The amount of data developed by smart pigging is measured in gigabytes. The

computer revolution is just barely keeping up in its ability to analyze data in a

timely fashion. The latest technique developed to improve piggable distance is the

use of real time data filtering on board the pig. Desktop computers have made a big

improvement in the ability to review results of high resolution tools. The major highresolution vendors now deliver the data on floppy or compact disk with special

application software which allows the client to manipulate the information or

combine it with other data bases. The software can also automatically perform

strength calculations based on the inferred shape and depth parameters. It then prior-

itizes the defect areas based on maximum allowed operating pressure at the defect.

However, a waiting period of a month or more is still common before the results of

the run are analyzed by the vendor and returned.

Chevrons Experience With Smart Pigs

Chevron has many varied experiences with smart pigs:

Chevron Canada commonly uses tethered tools to inspect short but high conse-quence sections. Western Atlas is their vendor of choice. CCR also uses the

Tuboscope conventional resolution tool.

Chevron Pipeline regularly runs both high and conventional resolution pigs.

They have set up alliance contracting with PII, formerly British Gas, for high

resolution and with Tuboscope for conventional resolution.

Chevron Marketing Hawaii runs a high resolution Pipetronix UT tool on the hot

Black Oil line.

CNAEP Western Region is required by the MMS and California State Lands

Commission (SLC) to run intelligent pigs on the offshore California lines. They

split the work about 70/30 between high and conventional resolution tools.

Resources

Experience is important in assuring good performance of intelligent pigs. Below are

web sites and contact names for more information.

1. PII (Formerly British Gas) Web Site

http://www.pii.co.uk/

Contact - Keith Grimes at (713) 849-6307 in Houston

2. Pipetronix Web Site

http://www.pipetronix.com

Contact - Neb Uzelac at (905) 738-7559 in Ontario Canada

3. Tuboscope Web Site

http://www.tuboscope.com/

Contact - James Simek at (713) 799-8158 in Houston


21/37



4. Chevron Pipeline Smart Pigging Procedure MIP 305

http://www-cpl.chevron.com/techserv/documents/mip/mip305/97_MIP305.doc

Contact - Mark Hildebrand at CTN/363-7152 / E-mail: HILM

5. CRTC Pipeline Integrity Web Resourcehttp://www-crtc.chevron.com/MEE/pipeline/AssessInteg-

rity/Measure/Pigging/smartpig.htm

Contact - Sam Mishael at CTN/510 242-1726 / E-mail SMIS

833 Corrosion Coupons

For corrosive fluids, for which a specific corrosion allowance has been provided in

determining the pipe wall thickness, it may be advisable to install corrosion coupons

at points in the system representative of flow conditions and where they can be

isolated and removed. These would normally be in the station or terminal piping or

on flowing branch lines, rather than on the main pipeline. Where the piping must bekept in operation while removing or replacing coupons, a valved by-pass can be

provided. If necessary to install a coupon in the main line, devices are available for

withdrawing and re-inserting the coupon with the line in service. The Materials and

Engineering Analysis Division of the Engineering Technology Department can be

consulted regarding the need and type of coupon and method for placing it in the

flowing stream. Also see the Corrosion Prevention and Metallurgy Manualfor a

description of devices for installing corrosion coupons.

834 Hydrostatic Testing

Two types of pressure testing of operating liquid lines are: Testing after displacing lines with water at hydrotest pressures at 1.25 times the

maximum allowable operating pressure.

Line packor standuptesting with the fluid normally handled after isolating

the section, at a pressure not exceeding the maximum operating pressure

The maximum allowable operating pressure should be determined taking into

consideration actual normal and abnormal operating pressures, limitations by design

codes for pipe grades and wall thickness, and limitations by valves, flanges or other

line appurtenances.

Operating demands usually limit the time available for testing. Therefore, the test

procedure must be well planned, giving consideration to all aspects and contingen-

cies. All needed facilities, including communications, should be ready, as well as

materials and construction equipment in event of a leak or a break. When testing in

wet weather or wet areas, using a water-soluble dye in the test water may be

warranted for identifying leak locations. Disposal of displacement water must be

arranged to comply with environmental restrictions.


22/37



Lines that have been idle for over 3 months and up to a year should have a satisfac-

tory standuptest before returning to service. A line that has been idle for a year or

more should be hydrostatically tested with water to 1.25 times the maximum oper-

ating pressure before returning to service.

Guidelines for testing operating pipelines are available from Chevron Pipe Line

Company. These guidelines recommend that lines tested periodically be held at test

pressure for at least 4 hours. Also seeSection 770for discussion of completion

testing of new pipelines.

835 Coating Quality

Overall quality of pipe coating to effectively protect the pipe from corrosion is indi-

cated by cathodic protection surveys at frequent intervals and by monitoring the

current from rectifiers needed to maintain cathodic protection on the pipeline.

If areas of severe coating failures and defects are suspected, coating holidays can be

located with equipment such as the Pearson null-method detector manufactured by

Tinker & Rasor, San Gabriel, CA, providing the pipe is buried in relatively moist

soil conditions. The Pipe-CAMP PCS-2000 equipment recently developed and used

in Australia is claimed to have greater sensitivity and ability to detect defects in dry

and rocky soil and under pavement; it is available through US agents, such as

Farwest Corrosion Control, Gardena, CA.

840 Leak Detection by Physical MethodsSCADA leak detection systems will trigger the need for corrective action or repairs

and may indicate the general area of the suspected leak. To precisely locate a pipe-

line leak, however, on-the-ground detection methods must be used. These include:

Visual observation by air or on the ground for evidence of line stock or effect

on vegetation

Combustible gas detectors

Injection of odorants into gas and odor detectors

Sonic instrumentation

Pressure-wavefront instrumentation

Heath Consultants, Stoughton, MA Goldak, Glendale, CA, and Metrotech, Moun-

tain View, CA, offer instruments and equipment for leak detection.

Information on leak detection for gas lines is presented in ANSI/ASME Code

B31.8, Appendix M, Gas Leakage Control Criteria. Appendix M relates to gas

distribution piping, not transmission pipe lines, so judgment should be used in

considering the action criteria outlined in Section 5 of Appendix M.
http://ppl700__.pdf/http://ppl700__.pdf/


23/37



850 Hot Tapping

Hot tapping of pipelines is similar to both hot tapping of process piping and pipe-

line sleeve repair welding. For more details on hot tapping equipment and proce-

dures see Section 500 of the Piping Manual. The Piping Manualincludes a

checklist of the questions to be asked and preparations to make before preforming a

hot tap.

Wall Thickness

Pipelines with a wall thickness of 0.188 inch and above can be hot tapped with low

hydrogen electrodes without risk of burn-through. Thinner wall thicknesses require

special procedures. See Section 500 of the Piping Manual.Wall thickness at the

point of hot tap should be checked by ultrasonic testing.

Welding Procedure

Low Hydrogen Electrodes. Only welding procedures and welders qualified with

low hydrogen electrodes (vertical up) should be used for hot taps and repair weldson live pipelines. Low hydrogen electrodes have both a lower risk of burning

through and of weld cracking.

Welding Electrode Selection. For high strength pipe, the electrode strength must be

selected to match the pipe strength.

Pipe Grade

Special welding considerations are not required for the high strength X grades (X56

and above). These grades of steel have chemistries that are designed to be very

weldable. A weld rod with sufficient strength should be selected for these grades.

InspectionPreweld Inspection. Prior to hot tapping, the wall thickness at the proposed hot tap

location should be checked with an ultrasonic thickness gauge.

Postweld Inspection. Following completion of the hot tap welding, a visual

inspection and magnetic particle inspection of the attachment welds should be done.

Inspection methods and procedures are explained inSection 700of this manual.

860 Pipeline Repairs

When pipeline repairs are required because of corrosion, defects, or damage to the

pipe, the Company preference is to replace the section of pipe requiring repair. Thisgenerally entails cutting out the affected section and installing a new piece of pipe

(pup). The circumferential welds to install the pup piece are straightforward pipe-

line welds that can be inspected by standard radiographic practices and the pipeline

can be returned to service in good condition. However, this practice requires shut-

ting down the pipeline. When schedule considerations make this impractical, other

repair methods have to be employed, such as Plidco sleeves and Stopple fittings,

Clock Spring fiberglass coils, or full encirclement welded sleeves.


24/37



861 Special Repair Fittings

The various Plidco fittings described inSection 365are useful in maintenance

repairs to damaged or corroded pipe, particularly Plidco Weld & Ends couplings. A

pair of these fittings with a length of replacement line pipe can be used to quickly

repair a leak or install a prefabricated line valve or branch assembly, without

requiring any hot work until the line is back in service. The section of pipe

containing the leak, or at the location of the new prefabricated assembly, is removed

by cold-cutting, taking proper action to control drainage from the line. Before

making a cut, the bonding cable should be clamped to the line to electrically bond

across the gap. A Weld & Ends coupling is then slipped over each exposed end of

the line; the replacement pipe section is positioned to fill the gap; the couplings are

then centered on the joints and the clamping and thrust screws tightened to seal the

connections. See Figure 800-15.

Also useful are Stopple fittings, used with sandwich valves and Stopple plugging

machines, such as furnished by T. D. Williamson, Tulsa, OK. These are installed

before cutting out a sectional pipe and will plug the line to avoid draining the line.T. D. Williamsons Lock-O-Ring flanges can be provided on the Stopple fittings and

for flanges on hot-tapped tees for temporary by-pass lines; Lock-O-Ring plugs can

be inserted after line modifications are made, so that it is not necessary to leave

branch valves on the line. Refer to the T. D. Williamson catalog for details of use

and installation.

862 Clock Spring Fiberglass Coils

Description

The Clock Spring fiberglass coil was introduced in the mid 1980s as a cost saving

repair method for pipelines suffering from localized external corrosion. It can be

installed while the line is still in operation.

Clock Springs are typically a 12" wide by 0.06" thick cured sheet of polyester resin

reinforced by glass filaments composite wrap. The cured composite wrap comes in

one continuous piece that is wound around the pipe, typically 8 times. Adhesive

glues the multiple layers into a -inch thick monolithic wrap. Before the adhesive

sets, the layers are tightened to the required compressive load by cinching down on

Fig. 800-15 Repair with Weld & Ends


25/37



the last wrap, causing all the layers to wind around the pipe more tightly. This tight-

ening process is similar to winding up a spring-driven watch or clock, thus the name

Clock Spring.

Companies wishing to use Clock Springs for Gas Transmission must inform Federal

and local agencies prior to installing the repair per the current waiver. The Waiver is

expected to be lifted in 1999 at which time the notification clause will likely be

dropped.

Appropriate Use

Clock Spring repairs

can be made on lines ranging from 6" to 52" in diameter.

should only be used on lines having externally corroded areas where wall loss

is less than 80% of wall thickness.

The standard product is limited, by the manufacturer, to applications where contin-

uous temperature is 130F or less, with transients not to exceed 180F.

A modified version using different resins and adhesives is rated to 180F contin-

uous with transients not to exceed 210F.

Inappropriate Use

Clock Spring repairs should not be used

to repair internal corrosion.

for leak prevention from through-wall internalpitting.

to cover linear crack-like defects such as stress corrosion cracking.

to cover gouges.

when there is concern of the pipe pulling apart.

Determining If Clock Springs are Appropriate

GRIWRAP, a software package developed by the Gas Research Institute, mustbe

used to verify design appropriateness prior to making pipeline repairs using Clock

Springs. Either GRI or the Clock Springs manufacturer will run the software which

weighs site-specific variables such as type of pipe, grade of steel, existing pressure,

and amount of corrosion present against the reinforcing properties of Clock Springs.

The software will indicate whether or not the use of Clock Springs is appropriate for

a particular pipeline repair.

The design protocol is based on static accelerated aging tests of the material at

140F, selecting a design stress appropriate for a 50 year life and then halving the

value. The tests were performed in water with pHs ranging from 4 to 10. Thisdesign basis methodology is typical for fiberglass pipe and so represents a histori-

cally proven process.

Basis for Design

In laboratory burst tests on X-60 pipe, Clock Spring repairs with no service time

were found to contain up to 240% of maximum allowable operating pressure


26/37



(MAOP) without bursting. In these tests, defects were machined into pipes and

Clock Springs were wrapped around the affected areas. Pipes burst in the bare steel

outside of the repaired area.

Over 70 Clock Springs with service exposures up to six years have been excavated

and inspected by GRI. No changes were observed at the site, and subsequent lab

chemical analysis and mechanical testing detected no difference from the original

material composition and performance.

The DOT waiver on gas transmission lines requires a small number of installed

Clock Springs to be monitored by GRI to verify aging properties. There is no such

requirement on liquid service lines. Clock Spring repairs are considered permanent

and good for at least 20 years. The Canadian National Energy Board Standard for

gas and liquid pipelines, Z662, also accepts Clock Springs as a permanent repair as

of July 11, 1997.

In April 1998, GRI submitted to DOT a recommendation to lift the waiver for Gas

Transmission service as aging properties have been sufficiently verified by field

experience.

Preparation for Use

1. Obtain assessment of the external corrosion.

2. Determine confidence in the assessment.

Many methods are used to detect areas of corrosion, one of which is intelligent

pigging. The major pigging vendors provide a Fitness for Service assessment of

the corroded areas found.

Until confidence in the contractor and his technique is established, perform

confirmation digs to verify corrosion. Manual ultrasonic thickness measure-

ment of the pipe wall in the ditch will confirm that wall loss is not more than80% and that the area in general matches the profile predicted by the pig.

3. Clean the pipe before applying a Clock Spring.

Clean means all loose materials and all thick or soft coatings have been

removed.

Sand blasting to SSPC SP3 is the most common method of preparation.

However, if coal tar has been used, it is usually necessary to also perform a

solvent wash to remove the residual.

Only thin and hard coatings, like Fusion Bonded Epoxy (FBE), may be left on

the pipe.

4. Fill the externally corroded area with pit-filler compound prior to wrapping the

Clock Spring. If welds exist in the area to be covered, the pit-filler compound

should also cover the welds to provide a smooth load bearing surface for the

Clock Spring.


27/37



Installation

Clock Spring installation requires no welding and can be accomplished while the

line is in service. For buried lines, a few inches of clearance are required beneath the

pipe in order to facilitate wrapping.

1. Locate the adhesive pad attached to one end of the Clock Spring and apply it tothe pipe.

2. Apply adhesive to the pipe and then to each wrap as the Clock Spring is wound

around the pipe. Eight wraps are recommended, giving a final thickness of 1/2".

3. Cinch down the wraps to squeeze out excess adhesive from between the wind-

ings. Adhesive will ooze out from between the wraps.

4. Apply additional adhesive to fully cover the " edge thickness all around the

pipe.

5. Allow adhesive to cure 2-4 hours. The Clock Spring forms a monolithic sleeve

which has a higher tensile strength than the surrounding steel.

6. For buried pipelines, the manufacturer recommends covering the Clock Spring

with the tape wrap or shrink sleeve that will be used to protect the adjacent

pipe, filling out the corners of the Clock Spring repair to create a smooth transi-

tion for the coating. This prevents the coating from tearing if there is any pipe

movement.

Intelligent Pigging Marker. A common installation detail is the use of a few wraps

of steel shipping bands, directly on the pipe on both sides of the Clock Spring,

where they will be covered by the adhesive. This is an inexpensive way to provide a

marker for Magnetic Flux Leakage Intelligent Pigs. The manufacturer will typically

provide the straps at no charge in the shipping kit if asked.

Avoiding Adhesive Failures. Approximately 20 adhesive failures have occurred in

the 29,000+ applications of Clock Springs. These failures were caused by one of the

following:

Catalyst was stored for too long and became deactivated.

Catalyst was stored at too high a temperature and became deactivated.

Adhesive did not cure before going to hydrotest.

An incorrect amount of catalyst was used, or temperatures changed, and the

adhesive either did not set, or set too quickly.

The catalyst used today is labeled with an expiration date and instructions to keep it

refrigerated. It also has a longer shelf life than the catalyst used several years ago.

For overseas installations, the manufacturers policy dictates that it will not ship the

catalyst until receiving notification that installation is imminent.

Chevron Pipe Line Co.s first installation in California had to be reinstalled because

the catalyst cured too fast the first time due to the rapid temperature rise of the

surrounding air on a hot, sunny day.


28/37



In 1993, the Clock Springs manufacturer began refusing installations where

customers would not agree to use certified installers. The certified installer require-

ment was picked up by DOT in their waiver for Gas Transmission applications.

Certification is not difficult to acquire and the Manufacturer is happy to provide the

training.

Affect on Cathodic Protection

The " thick composite repair is well sealed, so there is minimal moisture transport

through the layers. Consequently, no significant corrosion has been observed on the

70 repairs that have been excavated and evaluated. Testing did find a slight drop in

voltage from impressed current cathodic protection systems beneath Clock Spring

wraps. Voltage drops off significantly but only temporarily after the repair is

completed. After a short incubation time, the voltage beneath the repaired area typi-

cally returns to near normal. A permanent loss of about 100mV can be expected on

a line with a nominal 1250mV potential.

Quality Control

The manufacturer verifies strength properties at a frequency of one in every 200

springs made. To test strength, a 3" wide layer is made and split in a spreader.

Failure must be above the minimum strength requirement and must fail across the

fibers. Delamination is cause for rejection of the preceding two hundred windings.

Cost

The October 9, 1995 edition of Oil & Gas Journalpublished a survey showing the

cost of installing Clock Spring was 60% of the cost of a Type A welded steel sleeve

(no circumferential weld), and 40% of the cost of installing a Type B welded steel

sleeve (including a circumferential weld).

Chevron Pipe Line Co. analysis suggests that welded steel sleeves are comparable in

cost. A process penalty for slowdown or downtime is needed to justify the use of

Clock Springs.

Chevron Experience

Chevrons experience with Clock Spring repairs has so far been limited. Seven

Clock Spring repairs have been in service in the Gulf of Mexico (Eugene Island) for

one year with no problems. The repairs were made in the splash zone of riser piping,

and so can be considered a severe test. Prior to the repairs, the piping was being

operated at reduced pressure due to external corrosion. More Gulf of Mexico repairs

are planned if the Eugene Island repairs pass visual inspection during Summer 1998.

In April 1998, Chevron Pipe Line Co. installed several clock spring repairs overcorroded areas found by intelligent pigging in the central valley of California.

More Information

Information is available through M&EE or the manufacturer:


29/37



Clock Spring

14107 Interdrive West

Houston, TX 77032.

M&EEs contact at Clock Spring:

Norm Block(800) 471-0060 or (281) 590-8491.

863 Full Encirclement Sleeves

Many of the considerations applicable to hot tapping discussed inSection 850also

apply to pipeline repairs that are made using full encirclement sleeves.

Full encirclement sleeves are recommended for repairs because, when properly

installed, they are load bearing, and Type B sleeves (fillet welded endssee

Figure 800-16) are pressure retaining for through-wall defects. The practice of using

partial sleeves (half soles) is restricted by the codes to lower strength, older mate-

rials and has generally been discontinued because of the stress intensification alongthe longitudinal fillet welds and the greater risk of failure if a surface defect such as

an undercut or toe crack has been left.

Fig. 800-16 Types of Full Encirclement Sleeves Evaluated


30/37



Another application of full encirclement sleeves has been the attachment of anode

leads when greater than a No. 15 Cadweld charge is required because of the risk of

copper contamination and cracking on the surface of the pipe. Direct attachment of

the anode leads to the pipe has been permitted for Cadwelds using a No. 15 or

smaller charge.

Because full encirclement sleeves are generally used to repair pipelines that cannot

be taken out of service, their use must be given the same considerations as required

for hot tapping. These are:

Stability of the product in the pipeline during welding and risk of explosive

reaction (e.g., spontaneous decomposition of ethylene)

Minimum thickness to avoid burnthrough (0.188 inch)

Reducing the operating pressure (generally to two-thirds or less) during repair

for personnel safety and to allow the sleeve to share hoop stress at operating

pressure. This is frequently not possible with liquids that convert into a vapor at

lower pressures (e.g., liquid petroleum gas and carbon dioxide)

Risk of hydrogen cracking in the heat-affected zone for sour service operating

conditions

Welding Procedures

API RP 1107 coversRecommended Pipe Line Maintenance Welding Practicesfor

qualification of welding procedures and welders for full encirclement sleeves.

Welding procedures qualified to API RP 1107 are valid within the range of essen-

tial variables of their qualification. The test assembly for procedure qualification is

shown in Figure 800-17. Changes in essential variables requiring requalification are:

Change in welding process

Change in pipe, fitting, and repair materials. Materials are grouped into three

categories:

a. SMYS of 42 ksi or less

b. SMYS of more than 42 ksi but less than 65 ksi

c. SMYS of more than 65 ksi (each grade requires separate qualification)

Change in joint design

Change in position, except qualification in the 6G positions (45 degrees from

horizontal) qualifies for all positions

Change in material thickness group:

a. Less than 3/16 inch

b. 3/16 inch to 3/4 inch inclusive

c. Over 3/4 inch


31/37



Change in filler metal or shielding (change from cellulosic to low hydrogen or

more than one electrode size)

Change in direction of welding (vertical uphill versus vertical downhill)

Change in travel speed range or time lapse between passes

Welder Qualification

Welder qualification requirements for pipeline welding are discussed in Section 750.

The multiple qualification test does not qualify for sleeve welding performed with

low hydrogen (E7018) electrodes as recommended later on in this section. The use

of low hydrogen electrodes requires a separate welder qualification test (a separate

welding procedure qualification test is also required) which consists of welding with

the pipe and sleeve positioned 45 degrees from the horizontal (seeFigure 800-18).

Essential variables requiring requalification are:

Change in process

Change in direction of welding (vertical uphill versus vertical downhill)

Fig. 800-17 Procedure Qualification Test Assembly for Position 6G


32/37



Change from cellulosic to low hydrogen electrodes

Change in diameter group except qualification on NPS 12 pipe qualifies for all

pipe diameters

Change in nominal wall thickness group (same as procedure)

Sleeve Design

Several options exist regarding the design of full encirclement sleeves. Choices

exist for the welding of the ends of the sleeves and the joint design of the longi-

tudinal seams (see Types A and B sleeves inFigure 800-16)[1]. Sleeves with theends not welded are referred to as Type A sleeves. Type B sleeves have welded

ends. Longitudinal seams are either butt welded or lap welded using a butt strap.

The Company practice is to weld the ends (Type B sleeve) in order to retain pres-

sure and prevent corrosion in the crevice between the sleeve and the pipe. The use

of lap-welded joints is not recommended because tests [1] have shown them to be

inferior to butt-welded sleeves. The joint preparation for the butt welds in the sleeve

should be beveled and have a gap sufficient to be able to obtain a full penetration

Fig. 800-18 Welder Qualification Test Assembly


33/37



weld. Full penetration sleeve welds will penetrate into the carrier pipe. In cases

where local wall thinning causes the wall thickness under the sleeve welds to be less

than 0.188 inch, a thin mild steel backing strip (1/16 inch) should be used to help

prevent burnthrough. These should be slipped underneath the sleeve as shown in

Figure 800-19. Backing strip material should be weldable and compatible with the

pipeline material. Materials other than mild steel should not be used.

In all cases, a sleeve should be fit as tightly as possible against the pipe in order to

provide structural strength. Sleeve thickness should provide sufficient strength to at

least match the line pipe strength or system flange rating pressure, whichever is

limiting. Where line pipe is limiting, sleeve thickness can be calculated as follows:

(Eq. 800-2)

where:

Ts = minimum sleeve thickness, in.

Tp = nominal pipe thickness, in.

Sp = SMYS for pipe, psi

Ss = SMYS for sleeve, psi

D = pipe outside diameter, in.

If flange rating pressure Pf is limiting,

Fig. 800-19 Longitudinal Sleeve Weld with Backup Strip


34/37



(Eq. 800-3)

In either case, the sleeve thickness should not be less than the pipe wall thickness.

Welding

From the section on hot tapping, it can be noted that welding sleeves on pipelines

containing fluids can produce faster quench rates in the welds and heat-affected

zones. Depending upon the grade and carbon equivalent (C.E.) of the pipe, calcu-

lated by the following,

C.E. = C + Mn/6 + (Cr + Mo + V)/5 + (Cu + Ni)/15(Eq. 800-4)

heat-affected zone hardness can rise above the threshold where cracking can occur if

hydrogen is present from the weld metal. This is called hydrogen-assisted cracking

and is generally thought to require a microhardness above about 350 Vickers (Rc

35) in the heat-affected zone, high tensile stress, and a source of hydrogen for it to

occur. Heat-affected zone hardness is difficult to control because, more frequently

than not, pipeline materials, thicknesses, and fluids being carried will combine to

produce fast cooling rates and high hardness. Residual stresses are inherent to the

welding process and also difficult to reduce. Of the three variables, only hydrogen

can be controlled to reduce the risk of cracking. This can be done through the use of

a welding procedure using low hydrogen electrodes (E7018). An additional feature

of using low hydrogen electrodes is their characteristic of less penetration than

obtained with cellulosic electrodes (e.g., E6010 and E7010) conventionally used for

pipeline welding. This provides an additional margin of safety to avoid burnthroughwhen welding on thinner materials.

Dents

When full encirclement sleeves are used to repair dents, the space between the dent

and the sleeve should be filled with a hardenable material like an epoxy resin so

there is good contact between the pipe and the sleeve. One method is to apply the

epoxy resin to the dent with a trowel and then contour it to the original pipe circum-

ference before the sleeve is installed and welded in place. Care should be taken to

assure that the void between the sleeve and the pipe is completely filled.

Inspection

The fillet welds at the ends of full encirclement sleeves have been the site of under-

bead cracking which was the cause of at least one recent pipeline failure [2]. While

the use of cellulosic electrodes and higher strength pipe (X52) were separated out as

the main causes of cracking, it was brought out that inspection of these welds should

be routinely done even with low hydrogen electrodes. Inspection should be by

visual examination and magnetic particle inspection. Particular attention should be

given to looking for cracks along the toe of the fillet on the pipeline side.


35/37



870 Maintenance Programin Areas of Unstable Soils or Earthquakes

Nearly all pipeline systems are required to have normal operating and emergency

contingency plans. These plans specify immediate operating action in event of land-

slide, subsidence, or earthquake. In addition to normal maintenance surveillance, the

following measures are suggested for areas of unstable soils and seismic risk:

As-built documentation should be on hand so that any changes from design or

design assumptions are recognized, documented, and evaluated for their effect

on pipeline integrity

The inspection plan should include a recognition of the key components of

design, to ensure the integrity of the line, and a program for monitoring these

components

Measurement surveys should be conducted periodically to detect changes in

field conditions and in the line

A contingency repair plan should be prepared for corrective actions for situa-

tions of varying degrees of severity. It should identify (1) recurring problemsrequiring routine periodic correction, (2) problems that may arise for which

standard procedures can be implemented without engineering involvement, and

(3) critical problems requiring engineering investigation and resolution. Neces-

sary materials and construction equipment to make repairs on an urgent basis

should be available near the areas of risk

A postevent monitoring plan with checklist for reporting as soon as possible

whether damage is severe or relatively minor. The initial inspection checklist

should identify specific system components and ground conditions that are

good indicators of damage. Ground condition indicators include: ground

cracks; misalignment of roads, trees, fences, pole lines, railroad tracks, etc.;

ground sags, sinkholes, or uplifts; signs of damage to other nearby utility lines.As soon as possible after strong events, a thorough investigation should be

made by responsible operations and technical personnel to determine the condi-

tion of the pipeline, safety of resuming operations, and necessary corrective

repairs or replacement

In making repairs to a line damaged by ground displacement, precautions should be

taken in cutting the pipe to avoid fire or injury in case of likely sudden release of

high-strain energy stored in the line. Precautions should also be taken for possible

hydrocarbon spills in the soil and for unstable ground conditions.

880 In-Service Line LoweringWhen land surface grading is to be done over an existing pipeline, such as for a new

highway or other new land use, that will expose the pipeline either to mechanical

damage and/or excessive stresses from wheel loads, measures must be taken to

protect the pipeline, preferably without removing the line from service. One method

consists of lowering the pipeline into a deeper trench so that it will be positioned

farther below the new graded surface. The rationale for lowering is that in its new,


36/37



deeper position the pipeline will experience stresses from wheel loads that are

acceptably small and that the pipeline will be safe from mechanical damage during

the grading and excavation.

Guidelines for safely lowering pipelines without taking them out of service were

established by a Batelle Columbus Laboratories study published in 1985,

undertaken jointly by the Office of Pipeline Safety Regulation of the U.S. Depart-

ment of Transportation, ASME, and API [3]. The study presents detailed guidelines

for conducting a pipeline lowering operation, equations for predicting the lowering

induced stresses; it establishes reasonable limits on the lowering-induced stresses,

so that the pipeline will not be damaged or ruptured due to lowering operations. The

study is not an endorsement of lowering as a method of addressing the safety of an

existing pipeline, but provides guidance to pipeline operators or contractors who

choose lowering as their preferred alternative. Elements to be considered in

lowering a line are:

Factors that affect loweringthe pipe, the pipeline and its condition, terrain,

soil, and stress

Safetypressure reduction, excavation safety, response to emergencies, protec-

tion of personnel and the public

Stressesexisting stress in the pipeline, lowering induced stresses, measuring

and calculating stresses, support spacing, safe limits on stresses

Failure modesruptures, leaks, or buckles from improper lowering operations

ProceduresInitial review, trench types and profiles, lowering alternatives,

measuring stresses, minimizing temporary stresses, inspection

The following computer programs are available from Chevron Pipeline Co., San

Francisco.

PDROP. Calculates trench length, maximum pipeline stress, and added stress for

free deflection of a pipeline

TRENCHZ. Calculates trench length and profile during lowering while keeping

below a given stress limit

SUPPORT. Calculates the range of distance between pipeline supports required to

minimize the stress in the pipeline during lowering

PLIFT. Calculates the lift-off lengths, maximum stress, and force required to lift the

center of the pipeline to the specified height. (This program can be used to deter-

mine initial pipeline stress)

These programs have been validated. However, the TRENCHZ program may not

produce exact results in every situation, especially with small diameter pipelines,

due to the inaccuracy of the PC FORTRAN in calculating soil/pipeline interaction

stresses. The accuracy level is adequate for most pipeline applications.


37/37


890 References

1. Kiefner, J. F.,Repair of Line Pipe Defects by Full Encirclement Sleeves ,

Welding Journal, June 1977.

2. U.S. Department of Transportation, Office of Pipeline Safety. Alert Notice.

March 13, 1987.

3. Kiefner, J. F., T. A. Wall, N. D. Ghadiali, K. Prabhat, and E. C. Rodabaugh,

Guidelines for Lowering Pipelines While in Service, Batelle Columbus Labora-

tories, February 25, 1985.

Documents

PPL800 Operations and Maintenance