gaspipelinesafetyoir_plea_wildgoose_20130628_280481.pdf

Operations and Maintenance Procedures ManualGas Pipeline

Gas O&M.doc 6/20/13Section 2.16 Purging of Pipeline 54

When equalizing the movement of air in both directions as indicated by the streamers, the evacuation of the pipeline should continue for fifteen minutes.

Conduct gas test with a combustible gas indicator for the presence of gas in and aroundthe access opening or in the ends of the pipe. If no gas is indicated, the pipeline isavailable for cutting cold operation.

The movement of air into the access hole of open ends of the pipe must be maintainedthroughout the cutting and welding operation.

Prior to cutting out cylindrical piece of pipe, reduce the air mover rate so as to minimizespark travel in the pipe. Before severing, the pipe should be restrained by clamps, sideboom or blocking.

When the cutting has been completed, the air mover may be adjusted to a rate requiredfor the next operation. The air mover should be adjusted to a rate that will minimizewelding problems on the replacement pipe. Control the pressure settings on the airmovers to control vacuum on the pipeline and eliminate blow in of welds as the pipelineis closed to the atmosphere by welding.

Upon completion and acceptance of the welds, remove air mover equipment and returnpipeline to service after purging the pipeline with natural gas.

Source: AGA Purging Principle and Practice 1975.Table 8-2.

AirMoverSizeInch

GagePressure

PSIG

CompressedAir SCFM

DischargeAir

SCFM

InducedAir

SCFM

8 10 12 16 24 20 30 36

Full size access hole w/ air supply

Plug Valve with air supply

Plug valve with gas supply

3

20 19.0 274 255.0

3040

26.433.4

397496

370.6462.6

50 40.8 561 520.2607080

49.860.072.4

614681736

561.2621.0663.6

6

20 48.0 900 852.0

3040

91.0141.0

13501800

1259.01658.0

5060

192.0242.0

22502700

2058.02458.0

70 293.0 3150 2857.0

10

3042

149.0214.0

29003700

2751.03486.0

5570

262.0342.0

42405050

5879.04708.0

81 398 5560 5162.0


Gas O&M.doc 6/20/13Section 2.17 Safety Related Condition Report 55

2.17 Safety Related Condition Report

CODE REFERENCE: Title 49 CFR Sections 191.23, 191.25, 192.485 and 192.605(d)

PURPOSE: To define safety related conditions and establish responsibilities forreporting safety related conditions on company pipelines.

GENERAL: Safety related conditions involving pipeline facilities shall be reported tothe Production Coordinator as soon as they are noted. The Production Coordinator willdetermine if the condition is reportable under the provisions of CFR 49 Section 191.23.

Designated operating personnel will look for possible safety related conditions whileconducting routine operating functions and when following applicable procedures forinspections and surveillance.

The Production Coordinator or designated operating personnel will complete the SafetyRelated Conditions Report form. If completed by operating personnel, it must beprovided to the Production Coordinator as soon as possible, but not more than five (5)working days after discovery.

The Production Coordinator is responsible for evaluating safety related conditions andreporting to governing agencies. Reports must be received by the governing agencies nolater than five (5) working days after the day of determination or ten (10) days after theday of discovery.

If a possible safety related condition is discovered which results in taking the facility outof service due to an incident before determination and not more than five (5) workingdays from discovery, the reporting requirements of this procedure are eliminated.

DEFINITIONSSafety Related Condition as described in the criteria below is a condition, which lieswithin 200 yards of any building intended for human occupancy or outdoor place ofassembly, or within the right-of-way of an active railroad, asphalt or concrete paved road, street or highway.

Discovery Date is the date that a condition is identified that may be classified as asafety related condition under this procedure, but requires additional evaluation oranalysis.

Determination Date is the date when a condition evaluation results in the conclusionthat is a safety related condition.

Working Days are Monday through Friday, except Federal holidays.

SAFETY RELATED CONDITION CRITERIA - The following are safety relatedconditions reportable under CFR 49 Part 191.23, applicable to pipeline facilities:



1. On a pipeline that operates at hoop stress of 20% or more of its SpecifiedMinimum Yield Strength when:

General corrosion has reduced the wall thickness to less than that requiredfor the Maximum Allowable Operating Pressure, and Localized corrosion pitting to a degree where leakage might result.

2. Unintended movement or abnormal loading by environmental causes, such asearthquake, landslide, or flood that impairs the serviceability of pipeline or thestructural integrity or reliability of a facility that contains, controls or processesgas.

3. Any material defect or physical damage that impairs the serviceability of apipeline that operates at a hoop stress 20% or more of its Specified MinimumYield Strength.

4. Any malfunction or operating error that causes the pressure of a pipelinecontaining gas to rise above its Maximum Allowable Operating Pressure plus thebuild-up allowable for operation or pressure limiting or control devices.

5. A leak in a pipeline that is characterized by the need for immediate correctiveaction to protect the public or property and that constitutes an emergency.

6. Any safety related condition that could lead to an imminent hazard and causes(either directly or indirectly by remedial action of the Company ), for purposesother than abandonment, a 20% more reduction in operating pressure or shutdown of operation of a pipeline that contains or processes gas.

7. Reduction in pressure as a precaution to avoid an unsafe condition for thefollowing activities is not reportable:

Abandonment of pipeline facilities,Routine maintenance or construction,Facilitate inspection for potential problems,Avoid problems related to external loading from blasting or subsidence,Provide for safe line movement.

Using the above listed criteria, personnel who perform operation and maintenanceactivities should be able to recognize conditions that may be potentially safety related.

REPORTING OF SAFETY RELATED CONDITIONS- Report safety-relatedconditions to PHMSA and CPUC for all safety related conditions resulting from defectsoutlined above regardless of when the condition is repaired. Use WGS Form 108 SafetyRelated Condition Report and provide the following information:

Name and principal address of Company



Date of reportName, job title, and business telephone number of person submitting the reportName, job title, and business telephone number of person who determined that the condition existsDate condition was discovered and date condition was first determined to existLocation of condition, with reference to the State (and town, city, or county), andas appropriate, nearest street address, survey station number, milepost, landmark,or name of pipeline.Description of the condition, including circumstances leading to its discovery, any significant effects of the condition on safety, and the name of the commoditytransported or stored.The corrective action taken (including reduction of pressure or shutdown) beforethe report is submitted and the planned follow-up or future corrective action,including the anticipated schedule for starting and concluding such action.

A safety related condition is not reportable if:It becomes an incident before the deadline for filing the safety related conditionreport. Report the situation per Section 2.2 Incidents Reporting and Controlof this manual.It exists on a pipeline that is more than 220 yards from any building intended forhuman occupancy or outdoor place of assembly, except that reports are requiredfor conditions within the right-of-way of an active railroad, paved road, street, orhighway.It is corrected by repair or replacement in accordance with applicable safetystandards before the deadline for filing the safety related condition report, exceptthat reports are required for the conditions in SAFETY RELATED CONDITION CRITERIA above, other than localized corrosion pitting on an effectively coatedand cathodically protected pipeline.

Designated operating personnel shall contact the Production Coordinator promptly if apossible safety related condition is discovered.

Operating personnel shall provide relevant information on an expedited schedule tosupport the timely submission of report to the PHMSA. The Safety Related ConditionReport form is to be used as a communication tool by Operating Personnel to provideproper information to the Production Coordinator. If the Production Coordinatordetermines that a reportable safety related condition exists, then he/she shall complete the form. In either case, the form must be completed and a report submitted within five (5)working days after the condition is discovered, but not later than one (1) working dayafter determination.

The Production Coordinator will evaluate and confirm the reportability of a condition. Ifa condition is determined to be reportable, the Production Coordinator will submit thenecessary written report to the appropriate agencies and to the D.O.T./PHMSA withinfive (5) working days (not including Saturday, Sunday or Federal holidays) ofdetermination, but not later than ten (10) working days after discovery of the condition, at the following address:



Office of Pipeline SafetyPipeline and Hazardous Materials Safety AdministrationU.S. Department of TransportationInformation Resources Manager PHP-101200 New Jersey Avenue, SE. Washington, DC 20590-0001

Telephone 800-424-8802

CPUC Reporting:

Copies of all reports submitted to the Secretary of Transportation shall be submitted tothe Commission concurrently.

RECORDS: For intrastate pipelines, and in states where the state is an Agent for theD.O.T., a report copy will be sent to the applicable state agency and CPUC.

Copies of Safety Related Conditions Report form and reports to the D.O.T./PHMSA andother agencies will be sent to the applicable Company offices.

A copy of all correspondence related to reported conditions will be kept the officeexperiencing the incident for five (5) years.

Reports on all corrective action taken will be kept by the local office for at least fiveyears.


Gas O&M.doc 6/20/13Section 2.18 Security of Facilities 59

2.18 Security of Facilities

CODE REFERENCE: 192.179(b)(1), 192.605(a)

PURPOSE: To protect the health and well being of members of the public who maytrespass on a company pipeline facility.

GENERAL: Pipeline facilities can be very dangerous places to those untrained andthose oblivious of the danger. Security of a facility may not only keep these people outbut may also deter the saboteur or vandal.

SECURITY OF STORAGE AREAS - Jurisdictional facilities such as breakout storagefacilities, well pads, etc. on pipelines shall be secured by installing a fence around eachfacility appropriate for the area. Normally this would include a fence approximately sixfeet high around the perimeter of the facility or around the above ground components ofthe facility not otherwise secured. All gates providing access to the facility shall beequipped with locking devices and shall be kept locked when the facility is unmanned. If a facility is manned continuously, locking gates are not required.

SECURITY OF BLOCK VALVES - All mainline block valves and any other valvesthat has the potential of over pressuring or causing a release of the pipeline product ifopened or closed unexpectedly are located in secured areas with locked facilities and/or24 hour security.

SECURITY OF PUMP STATIONS - Pump stations shall be secured in the samemanner as storage areas. In addition to the general security provided by the fencing,additional security is recommended in the form of locking such things as the doors toelectrical switchgear buildings, offices, transformers and other electrical equipmentcarrying voltages greater than 220 volts.

SECURITY OF RECTIFIERS - Rectifiers installed along the pipeline shall be installed in an enclosure equipped for locking and be kept locked at all times.


Gas O&M.doc 6/20/13Section 2.19 Tapping Pipelines Under Pressure 60

2.19 Tapping Pipelines under Pressure

CODE REFERENCE: Title 49 CFR Sections 192.151, 192.155, and 192.627

PURPOSE: To establish the requirements necessary for the installation of hot taps onpipelines under pressure.

GENERAL: Hot tapping is the installation of a branch connection with a valve on anexisting pipeline while the facility is in service and under pressure.

The Production Coordinator or Engineer will be responsible for the design of the tap andthe maximum allowed pressure in the carrier pipe when welding and cutting the tap.

The tapping machine used and the fittings installed shall be designed to meet or exceedthe operating pressure of the line being tapped.

The Project Engineer will be responsible for procedures to be followed in making hottaps and for installation of the tap.

Split tapping tees will normally be used for branch connections. Saddles will only beused if tapping tees cannot be obtained.

The term saddle shall include reinforcing saddles, wrap around saddles, or wrap aroundpipe, saddles, and proprietary fittings.

Only qualified welders and crewmembers will be utilized in the hot tapping procedure.

All welding performed in the installation of the tap shall be done in accordance with theAPI 1104.

PROCEDURE:

CONDITION OF THE PARENT PIPE - If there is a question concerning the type ofexisting pipe at a proposed tap location, the Production Coordinator will provideassistance in identifying the type of pipe.

Visually inspect the external of the pipe in the area for the defects such as corrosion,mechanical damage, etc.

The pipe to be tapped shall be free of laminations and free of any significant external orinternal corrosion.

The wall thickness of the pipe to be tapped must be 0.156 inch or greater, as determinedwith an ultrasonic thickness gauge.

The pipe to be tapped shall not operate at a temperature above 200 Fahrenheit.



TAP LOCATION - The tap location must be at least 5 feet from a bend on a straightsection of pipe so as to minimize secondary stresses due to shifting of the main line.

The outside edge of the hot tap nipple will be a minimum of two (2) inches from thelongitudinal seam of the parent pipe and shall be a minimum distance of six (6) inchesfrom a girth weld.

Generally, hot taps will be installed on the side; however, where prevailing circumstances warrant, they may be installed on the top of the parent pipe.

The tap shall not be made through any weld circumferential or longitudinal seam weld, or its heat - affected zone. If inspection reveals that the proposed location of the tap falls ina bend or in a weld, another location shall be selected.

INSTALLATION OF HOT TAP NIPPLE AND VALVE

SPECIFICATIONS To provide added structural strength to the branch connectionpoint, unless otherwise specified, pre-tested heavy wall thickness pipe will be used for all hot tap nipples as follows:

For tap sizes 8 and above, wall thickness minimum, a minimum of 35,000 psi specified minimum yield strength (SYMS) up to SMYS of the carrier pipe,seamless, minimum length 8-1/2.For tap sizes 6 and under, use schedule 80 wall thickness, minimum of 35,000psi SYMS, seamless, minimum length 6-1/2.

All hot tap nipples must be cut from pipe that has been pretested to a pressure specified by the Production Engineer.

Nipple length will be a minimum of one diameter except in larger sizes where the length is limited by tapping machine travel.

All valves used in tapping three (3) inches and larger pipe diameters will be flanged.Valves smaller than three (3) inches pipe diameter may be threaded.

PREPARATION AND WELDING OF HOT TAP NIPPLE

FIT-UP WELDING - The hot tap nipple will be fitted, beveled and welded only by aqualified welder.

The hot tap nipple will be fitted and beveled to provide equal spacing around thecircumference of the nipple. The nipple should be beveled at an exaggerated angle in thethroat area to allow sufficient clearance for filling in this area.

Complete penetration of the root bead is necessary; however, excessive penetration isundesirable due to interference with the cutter head of the tapping machine. An inside



pass of the weld joining the nipple to the parent pipe will not be permitted. For assurance of proper nipple weld, the saddle tap nipple should be installed prior to installing thevalve.

Extreme care will be exercised to maintain a true 90-degree angle between the axis of theparent pipe and to maintain a straight centerline between the nipple and valve in order tomaintain the proper position of the cutter head during the tapping operation.

All moisture and condensation shall be dried from the carrier pipe and the saddled end ofthe hot tap nipple by heating immediately before welding commences.

TESTING AND INSPECTION

LEAK TEST Each hot tap fabrication shall be hydrostatically tested. Pretested pipemay be used.

Prior to installation of the weld saddle or split tee, each hot tap installation will besubjected to a leak test within the following pressure range:

Maximum Test Pressure - 10% above line pressure existing at point of tap.Minimum Test Pressure - Line pressure existing at point of tap.

During the test, the weld and valve body will be closely examined for pinhole leaks andother defects.

Radiographic inspection of butt welds is necessary. The fillet weld joining the hot tapnipple to the carrier pipe is to be examined visually and, at the discretion of the weldinginspector, it can be inspected for surface defects utilizing the magnetic particle orpenetrant testing methods.

INSTALLATION OF SPLIT TAPPING TEE

INSTALLATION AND WELDING The split tee shall be installed using a chain andjack or similar arrangement to insure a snug fit around the parent pipe.

The longitudinal welds shall be made first. The welder shall begin at the center of thesaddle and work toward the ends. Each welder shall make each pass, including thestringer bead, for the entire length of the weld before successive passes are added. Noconnecting weld will be made between the split tee and the parent pipe along thelongitudinal seam (using a backing piece when possible).

Weld the ends of the split tee to the parent pipe.

The extruded outlet of the split tee reinforcement will be butt welded to the hot tap nipple or flange.



COMPLETION OF HOT TAP The tapping machine will be bolted to the flange ofthe valve. If a horizontal tap is being made, the tapping machine shall be supported sothat no stress will be placed on the hot tap nipple and valve. Extreme care is to beexercised in properly aligning and operating the tapping machine. The hole will then becut in the carrier pipe to complete the hot tap.

Each hot tap fabrication with the connected tapping machine shall be hydrostatically leaktested prior to cutting the hole. Pressure shall be limited to prevent overstressing thecarrier pipe from external pressure and overpressuring the tapping machine.

The hole will then be cut in the carrier pipe to complete the hot tap.

COATING ASSEMBLY Upon completion of the tap the entire assembly is to bethoroughly cleaned, primed, and coated with a coating that is compatible with the coatingsystem on the carrier pipe.

INSTALLATION OF FULL ENCIRCLEMENT REINFORCING SADDLE

PREPARATION The effectiveness of a full encirclement reinforcing saddle dependsupon a snug fit around the carrier pipe. Maximum surface contact between the outside of the carrier pipe and the inside of the saddle is necessary prior to welding the two halvesof the saddle together.

To accomplish the snug fit it might be necessary to grind a smooth groove inside thesaddle to fit the longitudinal weld of the carrier pipe. The saddle thickness shall not bereduced to less than the thickness of the parent pipe. The groove in the saddle must besuch that the longitudinal parent pipe weld will not contact the bottom of the groovebefore the inside of the saddle contacts the outside of the carrier pipe.

INSTALLATION AND WELDING The saddle shall be installed using a chain andjack or similar arrangement to insure a snug fit around the carrier pipe and the hot tapnipple.

The longitudinal welds shall be made first. The welder shall begin at the center of thesaddle and work toward the ends. The welder shall make each pass, including thestringer bead, for the entire length of the weld before successive passes are added. Noconnecting weld will be made between the reinforcement and the parent pipe (use abacking piece when possible).

The extruded outlet of the reinforcement will be fillet welded to the hot tap nipple.

Do not weld the ends of the reinforcing saddle to the carrier pipe.

COMPLETION OF HOT TAP The tapping machine will be bolted to the flange ofthe valve. If a horizontal tap is being made, the tapping machine shall be supported sothat no stress will be placed on the hot tap nipple and valve. Extreme care is to be



exercised in the properly aligning and operating the tapping machine. The hole will thenbe cut in the carrier pipe to complete the hot tap.

COATING ASSEMBLY Upon completion of the tap the entire assembly is to bethoroughly cleaned, primed, and coated with a coating that is compatible with the coating system on the parent pipe. Special care should be taken to effectively seal the ends of the full encirclement saddle so that no moisture can penetrate and enter the area between thesaddle and parent pipe. This is extremely important since the ends of the saddle are notwelded to the parent pipe.

CONCRETE SUPPORT Horizontal tap installations will be supported by concretefoundations extending back and under the line being tapped, placed on firm soil andinstalled as soon as possible after the side connection is welded in place.

RECORDS: Submit as-built documentation for updating of drawings.

On buried pipeline, complete WGS Form 109 Pipeline Leak Repair Form.

A record shall be made of each hot tap installed on a pipeline, and records shall beretained for the life of the pipeline in the appropriate file.

SECTION 3.0 PIPELINE MAINTENANCE


Gas O&M.doc 6/20/13Section 3.1 Abandonment or Inactivation of Facilities 66

SECTION 3.0 PIPELINE MAINTENANCE

3.1 Abandonment or Inactivation of Facilities

CODE REFERENCE: Title 49 CFR Section 192.727

PURPOSE: To establish minimum requirements for the abandonment of naturalgas pipeline facilities.

DEFINITIONS - Abandoned facilities are those which have been determined tohave no present or future use, and have ceased operation, either due todeterioration or because they are not needed for gas transportation use now or inthe future. An abandoned pipeline is a pipeline that is physically separated fromits source of gas and is no longer maintained under CFR 49 Part 192.

Inactive facilities are those that have ceased operation, but may be returned toservice in the future. An inactive pipeline is maintained under Part 192.

GENERAL: Facilities to be abandoned will be evaluated and handled on anindividual basis.

All applicable Federal, State, county, and local regulations or ordinances shall becomplied with in the abandonment of gas facilities.

Physically remove all abandoned facilities if practical. If this is not feasible,sever below grade and remove all aboveground piping and equipment.

Pipeline facilities abandoned in place will not be maintained and should not beconsidered for reactivation for service at a later date.

PROCEDURE ABANDONMENT: Facilities to be abandoned shall bedisconnected from all potential sources and supplies of gas, such as other pipelinemains, producer's piping, crossovers, control lines, metering and regulatingstations, etc. by a physical separation. All associated valves shall be locked andtagged closed and/or disconnected.

Abandoned facilities shall be purged of natural gas. If air is used as a purgingmedium, precautions shall be taken to ensure that a combustible mixture is notpresent after purging and that the mixture cannot ignite during purging.

After purging, the abandoned pipeline must be sealed at both ends, using one ofthe following methods:

Normal end closures,Welding steel plate to pipe ends,


Gas O&M.doc 6/20/13Section 3.1 Abandonment or Inactivation of Facilities 67

Pinching the ends closed and welding shut, orPlugging the ends with a suitable material.

Abandoned pipelines may be filled with air, inert gas, inhibited water, BentoniteClay (drilling mud), sand slurry, lean cement slurry or other inert materials.

Any valves left in the abandoned segment should be closed. If there are few linevalves, and the segment is long, consideration should be given to cutting andplugging the segment at intervals.

All aboveground piping, valves, meters, and risers should be removed from theabandoned segment.

Any belowground valve boxes or vaults should be filled with compacted inertmaterial. Acceptable backfill material includes but is not limited to nativematerial, sand slurry or lean cement slurry.

PROCEDURE - INACTIVE PIPELINES: Protect inactive facilities usingcathodic protection or other means to prevent deterioration. Generally, pipelinesshould remain filled with natural or inert gas and be pressurized aboveatmospheric pressure.

Inactive facilities must be treated the same as active facilities and all requirements of the Operating and Maintenance Procedure Manual for Gas Pipelinesrequirements must be carried out on inactive facilities.

Inactive, unmaintained facilities may be returned to service after a thoroughengineering review, testing and conversion to service.

RECORDS: Complete a WGS Form 110 Pipeline Abandonment Form andsend to the Production Coordinator for filing and historical reference.

Update drawings with abandonments or removals.

Pipelines that have been removed, or abandoned in-place and sold, will beeliminated from the drawings. Other in-place abandonments need to be indicatedon drawings as being abandoned-in-place.


Gas O&M.doc 6/20/13Section 3.2 Blowdown of Pipes 68

3.2 Blowdown of Pipelines

CODE REFERENCE: Title 49 CFR Sections 192.179, 192.629, and 192.751

PURPOSE: To establish criteria for identifying obstructions, which may bepresent at blowdown locations, and to establish safety practices to follow whenpurging or blowing down gas facilities.

GENERAL: Whenever a pipeline or pipeline facility filled with gas is blowndown as a result of a scheduled construction or maintenance project, it isnecessary for personnel to exercise extreme safety precautions during the blowdown activities.

The identification of blow-off locations that are close to overhead or otherobstruction (i.e. electrical lines, building, etc.) is necessary so that precautions can be taken to provide safe conditions during blowdown operations.

When practical, the attempt should be made to prevent having electrictransmission lines installed near blowdown valves. If the electric transmissionlines cannot be moved and the blowdown connections cannot be employed todirect the gas away from the electric transmission lines, then the blowdown mustbe done at a location where the safety conditions can be met, possibly at anotherblow off valve.

Affected compressor station compressor, suction and discharge piping shall beisolated, blowndown, and purged prior to work on the compressor or piping.Compressors and piping shall be purged of air per Section 2.16 of this manualprior to recommissioning.

PROCEDURE:

IDENTIFICATION OF BLOW-OFF LOCATIONS - Identify blow-offlocations where precautions should be taken during a blowdown.

Mark each such location with a sign indicating Controlled Blowdown RequiredDue to Overhead or Adjacent Facilities.

BLOWDOWN PLANNING - Prepare a plan and review it with the crew prior to purging or blowing down a gas facility. Discuss any hazards involved, such aspower lines, public highways and railroads.

Use silencers in populated areas when necessary.

Post warning sign where appropriate.



Notify the following regarding the time and place before blowing pipeline gas toatmosphere:

People living/working in the area;Public agencies such as the county sheriff, local police or fire departmentas required;Facilities supplying the pipeline and receiving from the pipeline whichwill be interrupted.

Traffic control, if required, should be performed by local law enforcementofficials on all preplanned activities.

Ensure that appropriate fire extinguishing equipment is available at strategiclocations.

Do not begin work until communications have been established with personneldiverting traffic and among personnel at the ends of pipeline sections being blown down or purged.

BLOWDOWN OPERATIONS - Blow down of natural gas, which has beenodorized, should not be performed in a heavily populated area. If there is noalternate location where the odorized gas can be vented to atmosphere,consideration should be given to flaring (burning) the gas.

Employees and other personnel in the vicinity of the blowdown shall wearadequate safety equipment, including eye and ear protection.

Be careful not to provide a source of ignition for the escaping gas, such assmoking, electric tools, sparks, etc.

All valves should be opened and closed in a steady, controlled manner.

Do not exhaust gas, at any time, into overhead electrical wires or into theatmosphere when an electrical storm is in the vicinity.

Prevent a hazardous mixture of gas and air in the pipeline.

Control gas pressure using experienced personnel. Do not allow unauthorizedcontractor or Company employees to operate valves.

Locate personnel a safe distance upwind.

Block or divert traffic as gas may drift across public roadways.



Locate vehicles or equipment, which might cause ignition, at least 500 feetupwind from a horizontally severed pipeline. (Do not allow vehicles orequipment anywhere except upwind of the severed pipeline.)

Do not allow vehicles closer than 100 feet upwind from a vertical blow-off. (Donot allow vehicles anywhere except upwind of a blow-off.)

Continue using these precautions throughout the entire blow-off period, until allvalves are shut and flow has stopped, and until all gas has had time to disperse.

If required, a useful formula in estimating blowdown gas losses, is as follows:

V = (ID) 2 (Pressure) (Length) (1.97) where V = Volume of gas blown down, standard cubic feet (Divide by 1000 to obtain MCF)

ID = Pipe Inside Diameter, inches(ID = OD - 2 times wall thickness)

Pressure = Initial Pipeline Pressure, PSIALength = Pipeline length, miles(Divide feet by 5,280, if necessary)

RECORDS: File pre-job safety plan and tailgate meeting roster.


Gas O&M.doc 6/20/13Section 3.3 Clearing Pipeline Freezes and Ice Blocks 71

3.3 Clearing Pipeline Freezes and Ice Blocks

CODE REFERENCE: Title 49 CFR Section 192.703

PURPOSE: To establish safety practices to follow when clearing pipelinefreezes and ice blocks.

GENERAL: When it is suspected that a freeze exists in a line notify theProduction Coordinator of the freeze.

The Production Coordinator will send assistance, when necessary, and maintainsupervision throughout the operation.

Isolate the line. On high-pressure systems the well(s) should be shut in first toprevent over pressuring the line.

Eliminate all sources of ignition in the immediate area where gas will be blown(engines, heaters, etc.).

Park vehicles upwind of the operation at a distance to insure safety to personneland unit.

Open all valves cautiously; beware of any sudden pressure drop. There is alwaysthe possibility of a freeze near any valve.

Reduce pressure on the high-pressure side of the freeze. This step should beperformed with extreme caution.

A one-inch or smaller valve should be cracked open and if a rapid decrease inpressure is noted, either by gauge or sound, the valve should be closedimmediately. If no pressure decrease is noted, the valve may be opened slowly tolower the pressure to design pressure - constantly watching for any rapid pressuredrop.

Attempt to locate freeze by checking pressures at available points, i.e., wells, tie-ins, and drips.

PROCEDURE - SOLID FREEZE: The information gathered in the stepsabove, will determine the next procedure to be followed.

When freeze is located close to blowoff:

Blow down the long section of line without attempting to equalizepressures across the freeze.Blow down short section of line with one-inch or smaller valve.


Gas O&M.doc 6/20/13Section 3.3 Clearing Pipeline Freezes and Ice Blocks 72

When freeze is located relatively near the center of the isolated section:Blow down the high-pressure side of the freeze until it is 50 psiless than the low-pressure side. This should be done through aone-inch or smaller valve.

When a double freeze is encountered:Reduce pressure on each side of the section maintaining adifferential of 50 psi or less across the freeze.

When freezes are not located close to either end, blow the line at each endand between the freezes by means of one-inch or smaller valves. Maintain a differential of 50 psi or less across the freezes.When both freezes are located close to blowoffs at each end, blow the linebetween the freezes and then the short sections at each end.When one freeze is located close to a blowoff, blow the line between thefreezes and at the end away from the close freeze, maintaining adifferential of 50 psi or less. When these sections are blown down, blowthe short section.Allow the line to air for several hours or overnight. A vent stack shouldbe used in hazardous areas (near roads, engines, etc.).

RETURNING LINE TO SERVICE - Install a gauge at the inlet end, give theline a good blow maintaining between 25 psi and 150 psi while making certainthat there is no pressure buildup. (This will also act as a purge prior to putting the line back in service.)

Stand well away from the outlet end during the blow. Wait until the blowclears sufficiently before shutting in the outlet.Notify the Production Coordinator that the freeze is cleared and line isback in service.

PROCEDURE - PARTIAL FREEZES - Notify Production Coordinator offreeze.

Attempt to clear freeze with methanol.If freeze persists, shut in and blow down the line, maintaining a minimalpressure differential across the freeze.Depending upon conditions, either allow the line to vent or purgemethanol through the line to clear the partial freeze.

RETURNING LINE TO SERVICE - Return line to service as outlinedpreviously.

Notify Production Coordinator that freeze is cleared and line is back in service.

RECORDS: Document maintenance of the pipeline on the daily operating reportform.


Gas O&M.doc 6/20/13Section 3.4 Compressor Stations 73

3.4 Compressor Stations

CODE REFERENCE: Title 49 CFR Sections 192.167, 192.169, 192.171,192.729, 192.733, and 192.735

PURPOSE: To establish minimum requirement for the safe operation, inspection and maintenance of compressor stations.

GENERAL: All Plant Personnel shall follow established detailed procedures.The Plant Engineering Group will establish the startup and shutdown, ESD, andisolation procedures. Inspection, Storage, Safety and reporting are established bythe Governing agencies. As a group the plant personnel creates a TIP sheet andreview as operations change. Each gas compressor unit will include:

Start-up/ShutdownInspection and Testing Relief DevicesStorage of Combustible MaterialsEmergency Shutdown SystemsSafety EquipmentIsolation of Equipment for MaintenanceReport Requirements

STARTUP/SHUTDOWN PROCEDURES - The startup/shutdown proceduresshall give sufficient detail to assure that field operations personnel can clearlyunderstand the proper sequence necessary for the safe startup and loading of eachtype of gas compressor unit.

Particular attention should be given to purging the air from the gas cylinders andpiping. This is extremely important as any air left in a compressor cylinder cancause an explosion upon compression.

In addition, detailed procedures shall provide for the necessary steps to assureshutdown of the unit in a safe manner and the proper method of blowing downany gas within the compressor unit piping.

They shall differentiate whether the unit starts while still pressured up or after ithas been blown down completely.

The procedures shall provide for the proper valve sequencing required to start orshutdown the unit. In addition, instructions concerning checking or bypassingshutdowns on the Tattletale panel shall be clearly indicated to assure properstartup/shutdown in accordance with the operator's manual.

The compressor manufacture's manual shall be reviewed by the ProductionCoordinator to assure all procedures are in accordance with approved methods



outlined by the manufacture and not harmful to the continued operation of theunit.

The Production Coordinator and Lead Operator is responsible for assuring thateach person assigned the task of compressor operation has been given sufficientinstructions for operation and is familiar with the proper startup/shutdown method for the respective type of units within the station.

INSPECTING AND TESTING OF RELIEF DEVICES (TITLE: CFR 49SECTION 192.169)

GENERAL: Each compressor station must have pressure relief valves or othersuitable protective devices of sufficient capacity and sensitivity to ensure that themaximum allowable operating pressure of the station piping and equipment is notexceeded by more than 10 percent in the event of an equipment failure ormalfunction.

Each vent line that exhausts gas from the pressure relief valve of a compressorstation must extend to a location where the gas may be discharged without hazard.

Plant Operations shall maintain written records to ensure the periodic inspectionof compressor station relief valves has been properly performed and thatoperating conditions have not changed the required relieving capacity.

The periodic inspection of relief devices shall be in accordance with the procedure outlined in Section 3.10 Pressure Regulators and Relief Devices.

All incidents of over pressure shall be brought to the attention of the ProductionCoordinator to assure continued safe operation of the system.

All incidents where an accidental ignition of gas vapors occur within acompressor station limits shall be reported to the Production Coordinator.

The maintenance personnel shall contact the Production Coordinator whenever acompressor unit is taken out of service for maintenance or repairs.

STORAGE OF COMBUSTIBLE MATERIALS (TITLE: CFR 49 SECTION192.735)

GENERAL: Flammable or combustible materials in quantities beyond thoserequired for everyday use, or other than those normally used in the compressorbuilding, must be stored a safe distance from the compressor building.Aboveground storage tanks must be protected in accordance with National FireProtection Association Standard No. 30.



The Production Coordinator shall ensure periodic inspections of the compressorlocations are performed and notify Operations personnel concerning anyflammable material storage problems.

EMERGENCY SHUTDOWN SYSTEM (TITLE CFR 49 SECTION 192.167)

GENERAL: Each compressor station of more than 1,000 horsepower must havean emergency shutdown system that complies with the minimum designrequirements provided by the Code of Federal Regulations. These regulations donot apply to compressor stations that are unattended field stations with less than1,000 horsepower installed on site, or stations which were constructed beforeNovember 1970.

The emergency shutdown system must meet the following requirements:

It must be able to block pipeline gas out of the station and blow down thestation piping.It must discharge gas from the blow down piping at a location where thegas will not create a hazard.It must provide means for the shutdown of gas compressing equipment,gas fires, and electrical facilities in the vicinity of gas headers and in thecompressor building, except that:

Electrical circuits that provide emergency lighting required toassist station personnel in evacuating the compressor building, andthe area in the vicinity of the gas headers, must remain energized;andElectrical circuits needed to protect equipment from damage mayremain energized.

It must be operable from at least two locations, each of which is:Outside the gas area of the station;Near the exit gates, if the station is fenced, or near emergency exits, if not fenced; andNot more than 500 feet from the limits of the station.

Remote control shutdown devices must be inspected and tested at least annually at intervals not exceeding 15 months. Record this inspection on WGS Form 111 Remote Control Shutdown Device Test.

RESPONSIBILITIES - The Production Coordinator shall review themaintenance reports of the emergency shutdown devices to assure properperformance.

A record of the date and person performing the emergency shutdown testing shallbe recorded and a file kept at the Field Office. WGS Form 111 Remote Control Shutdown Device Test



Any required maintenance and inoperable shutdown shall be noted and remedialaction taken.

In the event an emergency shutdown system becomes inoperable, the ProductionCoordinator shall be notified and necessary actions taken to assure the continuedoperation of the station in a safe manner.

Plant Operations shall maintain a log of shutdowns to assure that the system isfunctioning properly and causing a minimum of unintended outage.

SAFETY EQUIPMENT (TITLE: CFR 49 SECTION 192.171)

GENERAL: The Production Coordinator shall inspect the operation of hiscompressor facilities to ensure their proper operation in accordance with thefollowing general requirements:

Each compressor station must have adequate fire protection facilities. Iffire pumps are a part of these facilities, their operation must not beaffected by activation of the emergency shutdown system.Each compressor station prime mover, other than an electrical induction or synchronous motor, must have an automatic device to shut down the unitbefore the speed (RPM) of either the prime mover or the driven unitexceeds a maximum safe speed.Each compressor station engine that operates with pressure gas injectionmust be equipped so that stoppage of the engine automatically shuts offthe fuel and vents the engine distribution manifold.Each muffler for a gas engine in a compressor station must have vent slotsor holes in the baffles of each compartment to prevent gas from beingtrapped in the muffler.Each compressor control panel shall be inspected in accordance withmanufacturers guideline to assure proper operation of all shutdowndevices and their indicators. Any shutdowns found inoperable shall benoted on the daily compressor report each day the shutdowns areinoperable. The Production Coordinator shall give approval to bypass apanel shutdown on a continuous basis.Each compressor station building shall be properly ventilated to ensureemployees are not endangered by the accumulation of gas in rooms orother enclosed places.All gas detection devices within the compressor building shall be checkedfor proper performance. WGS Form 123 Gas Detection and AlarmSystem Test and Evaluation.Any continuous bypass of alarm devices shall be brought to the attentionof the Production Coordinator. WGS Form 123 Gas Detection andAlarm System Test and Evaluation.The continuous safe operation of a compressor station requires thatsufficient maintenance functions be performed on pressure gauges,



temperature gauges, coolers, and other performance measurement devices.These shall be properly maintained to assure their proper operation in caseof emergency.

ISOLATION OF EQUIPMENT FOR MAINTENANCE OR ALTERATIONS (TITLE: CFR 49 SECTION 192.733)

GENERAL: All personnel shall inspect and ensure a proper method for unitisolation. During the maintenance or alternation of compressor units this methodof isolation is to be followed. The following will be included in any method:

Each compressor unit shall be installed with suction and discharge blockvalves on the lead lines to provide for the isolation of the compressor unitduring maintenance.The block valves shall be maintained and periodically inspected to ensureproper operation in accordance with the Section 3.16 of this manualconcerning valve maintenance.If gas leakage occurs across the isolation block valve seats, then blinds orskillets shall be installed to assure proper isolation of the unit.Each isolation valve shall be properly tagged to indicate its intendedposition during the maintenance work.A manual vent valve shall be provided within the unit piping to properlyprovide for blow down and purging of the compressor unit to a safelocation.Each compressor unit shall be properly purged of air with sufficientquantities of gas to ensure no "mixing" will occur and that a hazardousair/gas mixture does not remain within the compressor cylinder or unit gaspiping.

REPORT REQUIREMENTSPlant Operations shall maintain reports of operation/maintenance activity for eachcompressor station/system and emergency generator.


Gas O&M.doc 6/20/13Section 3.5 Corrosion Control 78

3.5 Corrosion Control

ATMOSPHERIC CORROSION

CODE REFERENCE: Title 49 CFR Sections 192.479, 192.481, 192.485,192.491, 192.605, 192.613 and 192.709

PURPOSE: To establish the requirements for inspection and maintenance ofabove ground pipeline systems for atmospheric corrosion.

GENERAL: A pipeline system includes all pipeline facilities used in thetransportation of gas, including, but not limited to, line pipe, valves and otherappurtenances connected to line pipe, fabricated assemblies, and meteringstations.

Pipeline systems or portions thereof, subject to atmospheric corrosion or moisturepenetration and retention, shall be inspected to assure detection of corrosionbefore detrimental damage, Category 3 Corrosion (heavy, obvious pitting inexcess of 10% of new nominal wall thickness) is sustained.

The facilities operating history, future anticipated operating conditions, evidenceof possible corrosion found during routine observations, and actual inspectionresults shall be considered when establishing inspection frequencies.

Inspection programs for atmospheric corrosion shall include, but not be limited to, areas such as:

Under hold-down straps, Between pipe and pipe supports, Platform risers and riser clamps, Pipe penetrations of building walls, and Thermally insulated meter piping.

Periodically, not exceeding 3 years between inspections, check the condition of

Wear pads, Supports or sleeves on a sample basis to confirm continued protection ofthe pipe, especially in areas conductive to corrosion.

Such areas would typically be those where moisture is present on the pipe due to areason other than normal precipitation. The results of inspections, geographiclocation, and pipe environment will be used to determine an appropriatecontinuing inspection level.



Corrosion, leaks, and defects may be Safety Related Conditions. Refer to Section2.17 Safety Related Conditions Reporting procedure.

PROCEDURE: Inspect all bare aboveground piping at intervals not exceedingthree (3) years.

The primary method of inspection is visual. Further non-destructive testing(NDT) techniques (such as ultrasonic thickness measurements, pit depth gaugereadings, radiography, etc.) may be implemented if visual evidence of corrosiondamage or other conditions warrant.

Maintain a continuing program of painting based upon results of the externalinspection program.

Inspect the transition zone of pipe entering the ground to confirm it is properlycoated whereby penetration of moisture between the pipe and coating isprevented. Whenever a condition is observed where moisture may be retainedbetween the coating and pipe, remove the coating, inspect the pipe, evaluateseverity of corrosion if present, take remedial actions if necessary, and recoat thepipe prior to the next inspection.

For thermally insulated systems, visual inspection of the external jacket to ensureits integrity against moisture intrusion under the jacket is usually sufficient; if theintegrity of the external jacket has been breached and liquid water may be presentagainst the carrier pipe surface, additional inspection techniques may be requiredto detect possible corrosion.

Areas where liquid water may accumulate or be trapped against the outside of thepipeline (including, but not limited to, under pipe hold-down straps or at piesupports) may require special attention. Caulks, mastics or other sealants shouldbe used to prevent water accumulation at these sites.

Repairs and preventive maintenance actions necessitated by these inspectionsshall be completed prior to the next inspection.

In cases where pipe wall loss exceeds 10% of the nominal new pipe wallthickness, an Engineer shall review the pipeline MAOP for possible revisionand/or recommend pipeline repair requirements.

References for determining the remaining strength of a pipeline are:

ASME/ANSI B31G (latest edition), Manual for Determining the RemainingStrength of Corroded Pipelines.

AGA Pipeline Research Committee, Project PR-3-805, A Modified Criterion forEvaluating the Remaining Strength of Corroded Pipe, (latest edition).



RECORDS: Complete WGS Form 112 Corrosion Control Report todocument the external corrosion on aboveground facilities.

Complete WGS Form 103 Pipeline Inspection Report whenever externalcorrosion is identified and a repair or a preventative maintenance action, otherthan painting, is required.

Maintain the above records for at least five years.

INTERNAL CORROSION

CODE REFERENCE: Title 49 CFR Sections 192.475, 192.477, 192.485,192.491, 192.605 and 192.613

PURPOSE: To establish the requirements for the detection, monitoring, andcontrol of internal corrosion, and required corrective actions for pipeline facilities.

GENERAL: This procedure is required if liquids or corrosive gas are everallowed to flow through or remain in the pipeline.

A pipeline system includes all pipeline facilities used in the transportation of gas,including, but not limited to, gathering lines, line pipe, valves and otherappurtenances connected to line pipe, fabricated assemblies, and meteringstations.

Corrosive gas shall not be transported unless the corrosive effect of the gas hasbeen investigated and measures have been taken to eliminate or minimize internalcorrosion.

Potential corrosive gas shall not be transported without monitoring equipment thatwill detect the presence of internal corrosion. Where corrosive gas is beingtransported, coupons or other suitable means shall be used to determine theeffectiveness of the steps taken to minimize internal corrosion.

If repair, replacement or operating pressure reduction is necessary, review Section 2.17, Safety Related Conditions Reporting, to see if a reportable safety relatedcondition exists.

CORROSIVE CONDITIONS: Gas containing water in liquid phase and at least one of the following components is considered to be potentially corrosive. Acombination of two or more components is considered to be potentially corrosive.A combination of two or more components with water in liquid phase may bepotentially corrosive at lower concentrations of each component. Gas having awater vapor below the point of saturation may contain concentrations of H2S andCO2 and O2 greater than those listed below and remain non-corrosive.



Hydrogen sulfide (H2S) concentration greater than .05 psia partial pressure for systems operating at or above 65 psia total pressure. For systempressure less than 65 psia total pressure, H2S content of 50 ppm or greateris considered corrosive.

Gas containing more than 0.25 gram of H2S per 100 SCF (4ppm) may not be stored in pipe-type or bottle-type containers.

Carbon dioxide (CO2) concentration greater than 3 psia partial pressure regardless of total pressure.

Oxygen (O2) concentration greater than 50 ppm or greater than 20 ppb where dissolved in a liquid phase.

Review the gas source dew point history. Water dew points within 10 Fof the minimum ambient temperature to which the pipeline is exposedmay indicate the presence of liquid water in the pipeline.

Corrosion will be more severe if any of the following conditions arepresent in conjunction with the conditions listed above.

Produced liquids containing sulfate-reducing (SRB) or acid-producingmicrobiological colonies with culture test indicating over ten (10) colonies per milliliter should be considered to be potentially corrosive.

Liquids or materials having a pH less than 5.5.

PROCEDURE:

INTERNAL INSPECTIONS

Whenever any pipe section is opened or removed from a pipeline system, thatpipe section and any adjacent pipe sections shall be inspected visually todetermine evidence and/or extent of internal corrosion. If internal corrosion isnoted visually, other Non-Destructive Testing (NDT) techniques such asultrasonic thickness measurements, pit depth gauge readings, radiography, etc.shall be used to quantify the extent of the corrosion.

Vessels and other fabrications shall be visually internally inspected when theopportunity to do so exists in conjunction with other maintenance activities or atintervals dictated by code requirements.

When internal corrosion or metal loss is observed in piping not previouslymonitored, remedial action and monitoring shall be initiated prior to the nextinspection.



A sample of any foreign material recovered from inside the pipeline system shallbe submitted for analysis and any necessary remedial action indicated by theanalysis must be taken prior to the next inspection.

Electromagnetic flux leakage or ultrasonic smart pigs may be run in a pipelineat intervals of two to five years, or as required, to supplement other inspectiontechniques.

GAS ANALYSIS AND EVALUATION - Gas samples shall be taken atapplicable locations and tested for the presence and concentration of corrosivecomponents if there is a reasonable possibility that corrosive gas could occur in apipeline system. Testing shall be done at least twice each year with intervals notexceeding 7-1/2 months.

Dew point (water content) analysis shall be performed on gas sources once eachmonth not to exceed 6 months between inspections. Where potentially corrosivegas is found as a result of gas testing, initiate the remedial action prior to the nexttest.

INSTALLATION AND MONITORING DEVICES - Identify checkpointlocations at places most susceptible to internal corrosion such as low elevationpoints, dead ends and drips.

Select and install monitoring devices such as weight loss coupons or electricalprobes, either resistance or polarization, giving consideration to size of pipe, typeof system, operating conditions, simplicity of installation and ease of gatheringinformation. Install liquid sampling facilities if applicable.

Prepare and maintain a schematic diagram showing physical and operatingcharacteristics of the pipeline system, the location of checkpoints and the type ofmonitoring devices used.

Monitoring and Detection:

Monitor checkpoint and record the results at least twice each calendar year with intervals not exceeding 7-1/2 months. Monitor more frequently if the level of the corrosive component increases or the effectiveness of the anti-corrosion measures needs to be confirmed. If liquids are present, collect and analyze liquid samples semiannuallyfrom the gas stream.

Remedial Action:

Make a study of the pipeline systems to determine the scope of thepossible internal corrosion if it is determined by inspection or analysis that internal corrosion is occurring, or has occurred.




AMSE/ANSI (latest edition) Manual for Determining the RemainingStrength of Corroded Pipelines.AGA Pipeline Research Committee, Project PR-3-805, A ModifiedCriterion for Evaluating the Remaining Strength of Corroded Pipe, (latest edition).

Apply at least one of the following mitigation measures prior to the nextinspection if inspection reveals internal corrosion to be occurring, or if previouslyinstalled monitoring equipment shows corrosion to be occurring:

Eliminate free water in the pipeline by implementing an adequate piggingprogram, or by other appropriate methods. Remove corrosive components.Inject corrosion inhibitors.

REPAIR - If internal corrosion has or may have reduced the wall thickness of asegment of pipe to less than that required for the maximum allowable operatingpressure, pipe repair or replacement should be planned or the working pressurereduced prior to the next inspection.

CONVERSION EQUATIONS

Partial pressure (psia) = PPM x Line Pressure (psia)/1,000,000Partial pressure (psia) = Mole % x Line Pressure (psia)/100ppm = parts per million 1/1,000,000ppb = parts per billion 1/1,000,000,000

RECORDS: Complete the WGS Form 103 Pipeline Inspection Report and/orWGS Form 112 Corrosion Control Report forms whenever pipeline is checkedinternally, repaired, or replaced.

Retain all studies, reports, checks of monitoring devices and other data that maybe accumulated, at the local field office for the pipeline. Inspection reports are tobe retained for at least five years while smart pigging results are kept for the lifeof the facility.

Maintain gas water dew point historical log for gas sources where dew points orgas analysis are being performed for at least five years.

EXTERNAL PROTECTIVE COATING

CODE REFERENCE: Title 49 CFR Sections 192.455, 192.457, 192.459,192.461, 192.463, 192.483, 192.491, and 192.613.



PURPOSE: To outline the practice for the installation of external protectivecoating for all buried or submerged gas pipelines.

GENERAL: Buried or submerged natural gas pipelines installed after July 31,1971 must have an external protective coating system unless:

It can be demonstrated by tests, investigation, or experience in the area ofapplication that a corrosive environment does not exist. This includes at aminimum, soil resistivity measurements and tests for corrosionaccelerating bacteria. Within 6 months after installation, the line must befurther tested per 192.455(b) to evaluate the potential profile along theentire pipeline. If these tests indicate that a corrosive condition exists, thepipeline must be cathodically protected.The pipeline is a temporary installation with an operating period of service not to exceed 5 years beyond installation and any anticipated corrosionwill not be detrimental to public safety.

If any pipeline is externally coated (notwithstanding the criteria above), it must be cathodically protected along the entire area that is effectively coated. A pipelinedoes not have an effective external coating if its cathodic protection currentrequirements are substantially the same as if it were bare.

When choosing the material to use for repairing a coating, every effort should bemade to choose the original material or to come as close to it as possible withcompatible coating material.

In all cases of coating repair, whether during construction or after the pipeline isin service, the pipeline surface to be coated should be cleaned as well as possibleof all dirt, grease, weld splatter or other foreign material. Instructions for thecoating application prepared by the manufacturer should be followed.

COATING PROCEDURE

The purpose of external protective coating is to isolate the pipeline from itsenvironment and provide primary corrosion protection. Additionally, externalprotective coatings facilitate the application of cathodic protection.

The external protective coating applied for corrosion control must have thefollowing characteristics and properties:

The coating must be applied on a properly prepared surface asrecommended by the coating system manufacturer. The coating must have sufficient adhesion to the metal surface toeffectively resist underfilm migrations of moisture. The coating must be sufficiently ductile to resist cracking.



The coating must have sufficient strength to resist damage due to thehandling and in-service soil stress.The coating must have properties compatible with the applications of cathodic protection to the pipeline. The coating must have low moisture absorption and high electrical resistance.Each external protective coating must be inspected by electrical testmethods just prior to lowering the pipe into the ditch and backfilling, and any damage detrimental to effective corrosion control must be repaired.Each external protective coating must be protected from damage, which could result from adverse ditch conditions or from supporting blocks.If coated pipe is installed by boring, driving, or other similar method, precaution must be taken to minimize damage to the external coating during installation.

Coated pipe sections connected by welding and/or mechanical coupling includingvalves or other underground or submerged appurtenances will be considered fieldjoints. External coating of field joints must be equal to or better than the coatingof the pipeline.

Existing Coated PipelinesApply an external protective coating to:

Poorly coated or bare portions of pipeline segments that have beenexposed for repair of inspection.Pipeline segments that replace existing pipe.

Inspect and repair all coating on replacement segments and coating repairs fordefects caused by installation activity.

Existing coating may require repair or upgrading in areas where criteria forachieving cathodic protection is not being met.

New PipelinesApply an external protective coating to all new buried pipelines.

Inspect all coating on new pipeline segments and repair defects caused byinstallation.

Surface PreparationIn removing coating to make tie-ins, care must be taken to avoid disbanding of the adjacent coating. Edges of thick film coating must be tapered and enough of thewrapper removed to ensure adhesion of the new coating to the existing coating.

The surface to be coated must be thoroughly cleaned with solvents to remove oiland grease. All dust, dirt, rust, mill scale, loose shop coating, dead primer,welding slag, and burrs must be removed with wire brushes or scrapers.



Nicking the coating to bare the pipe surface must not be permitted.

Repair of Coating DefectsInspection shall follow all coating applications. Any defects shall be repaired.

A sufficient portion of the coating must be carefully removed from defective areas of pipe to ensure that the remaining coating is satisfactory and well bonded.Edges of the area should be tapered to increase the strength of the patch.

Foreign matter must be removed from the area to be repaired.

Primer applied to the area, if required, must be allowed to dry properly before thecoating is applied.

The coating material used for patching must be such that proper adhesion willoccur between the existing coating material and the patching material.

RECORDS: Submit appropriate as-built information to the field office forupdating drawings and records.

Retain these records for as long as the pipeline is in service.

INTERNAL AND EXTERNAL EXAMINATION OF BURIED PIPELINES

CODE REFERENCE: Title 49 CFR Sections 192.459, 192.475, 192.485,192.491, 192.605, 192.613

PURPOSE: To establish a standard program of examination of buried pipelinesfor evidence of internal or external corrosion.

GENERAL: A continuing program of examination and recording of the resultsof the inspection of buried pipelines is mandatory for both internal and externalcorrosion.

It is intended that examinations will monitor pipelines for the effectiveness ofboth internal and external protective measures.

Corrosion, leaks, and defects shall be evaluated to determine if they are safety-related conditions.

PROCEDURE: Whenever buried piping is exposed for any reason, the exposedportion of the coating must be visually examined to determine external coatingcondition. Complete WGS Form 104 Pipeline Exposure and InspectionReport.



If a line is bare or the coating has deteriorated, or the coating is removed on awell-coated line, inspect the pipe for external corrosion.

If corrosion is observed on a coated line, a condition may exist, warranting further investigation (disbanded coating, unique soil environment, etc.).

Whenever any pipe section is opened or removed from a pipeline system that pipe section and any adjacent pipe sections shall be inspected visually to determineevidence and/or extent of internal corrosion. If internal corrosion is notedvisually, other NDT techniques shall be used to quantify the extent of thecorrosion.

Visually inspect the full circumference of piping if one or more of the followingconditions exist.

Continuing corrosion is observedCP test, current requirements or surveys indicate corrosion may beoccurringPreviously unidentified coating deterioration is observed or suspectedCorrosion is observed on the piping, which is of a magnitude notpreviously documented or which may require repair. If repair is required,continue inspection longitudinally until pipe condition is satisfactory.

If visual examination indicates corrosion has occurred, initiate one or more of thefollowing actions:

Calculate the acceptable minimum wall thickness limit after corrosion. If wallthickness is less than the calculated minimum, initiate a repair method as outlinedin Section 3.15 Repair Procedures or reduce the pipeline MAOP.


AMSE/ANSI (latest edition) Manual for Determining the RemainingStrength of Corroded PipelinesAGA Pipeline Research Committee, Project PR-3-805, A ModifiedCriterion for Evaluating the Remaining Strength of Corroded Pipe, (latest edition).

If repair is required, limit the operating pressure accordingly, until the repair ismade.

Apply coating and/or additional cathodic protection, as necessary, where activeexternal corrosion is present.



If internal corrosion is noted, apply or confirm compliance with the requirementsof Internal Corrosion Procedure above.

Determine if a safety related condition exists.

RECORDS: Complete WGS Form103 Pipeline Inspection Report and/orWGS Form 109 Pipeline Leak Repair Report. WGS Form 104 PipelineExposure and Inspection Report.

Keep the records for the life of the pipeline.

CATHODIC PROTECTION/EXTERNAL CORROSION CONTROL

CODE REFERENCE: Title 49 CFR Sections 192.455, 192.457(a), 192.463,192.465, 192.469, 192.471, 192.473, 192.491, and 192.613

PURPOSE: To prescribe the minimum installation, maintenance, survey and testrequirements to monitor and control external corrosion on buried or submergedsteel pipelines.

GENERAL: Buried or submerged gas pipelines installed after July 31, 1971must have a cathodic protection system to protect the pipeline, installed andplaced in operation within one year after completion of pipeline constructionunless:

It can be demonstrated by tests, investigation, or experience in the area ofapplication that a corrosive environment does not exist. This includes at aminimum, soil resistivity measurements, and tests for corrosionaccelerating bacteria. Within 6 months after installation, the line must befurther tested per 192.455(b) to evaluate the potential profile along theentire pipeline. If these tests indicate that a corrosive condition exists, thepipeline must be cathodically protected.The pipeline is a temporary installation with an operating period of service not to exceed 5 years beyond installation and any anticipated corrosionwill not be detrimental to public safety.

If any pipeline is externally coated (notwithstanding the above criteria), it must be cathodically protected along the entire area that is effectively coated. A pipelinedoes not have an effective external coating if its cathodic protection currentrequirements are substantially the same as if it were bare.

Buried or submerged gas pipelines installed before August 1, 1971 must have acathodic protection system when active corrosion is found for the following:

Bare or ineffectively coated pipelines.



Bare or coated pipes at compressor or regulator stations.

Active corrosion means continuing corrosion, which unless controlled, couldresult in a condition that is detrimental to public safety.

The amount of cathodic protection must be controlled so as not do damage to theprotective coating or the pipe.

Cathodic protection test stations or contact points shall normally be located atpipeline mile markers, cased crossings, and other convenient locations.Recommended test station spacing should generally not exceed 1 mile.

For new construction after January 1, 1992, cathodic protection test leads shall beanchored by wrapping around the pipe or providing a separate anchor to avoidstraining the pipe to wire cad-weld.

Pipelines receiving cathodic protection from a single CP source of current must be electrically continuous with itself and the source of current. Additionally, thestructure to be protected must be electrically isolated from structures, which arenot intended to be protected.

Each impressed current type or galvanic anode CP system must be designed andinstalled so as to minimize any adverse effects on existing adjacent undergroundor submerged metallic structures.

Interference effects from impressed current CP systems on foreign structures shall be minimized. Mitigation of interference effects may employ one or more of thefollowing techniques:

Installation of sacrificial anodes on the affected structure;Bonding the affected structure to the offending CP system;Coating the affected structure;Providing sacrificial anodes connected to each pipeline and buriedimmediately adjacent to each other in the same backfill.

PROCEDURE: The CP system provides a level of protection that complies withone or more of the criteria listed below.

D.O.T. acceptable criteria to assure adequate cathodic protection for steelpipelines are:

A negative polarized (current switched off) potential of at least 0.85 voltrelative to a saturated copper-copper sulfate reference electrode.A minimum of 100 mV of cathodic polarization. The formation of decayof polarization can be used to satisfy criterion.



A negative (cathodic) potential of a least 850 mV with the cathodicprotection applied. This potential is measure with respect to a saturatedCu/CuSo4 reference electrode containing the electrolyte. Voltage dropsother than those across the structure to electrolyte boundary must beconsidered for valid interpretation of this voltage measurement (seeNACE RP0169-2002) without current interruption.

Special Conditions

For pipelines installed before August 1, 1971 which are bare or poorlycoated externally, the measurement of a net protective current from theelectrolyte to the pipe surface (as measured by the earth current technique) at predetermined discharge points may be sufficient proof of adequatecathodic protection. In some situations, such as the presence of sulfides, bacteria, elevatedtemperature, acid environments and dissimilar metals, the criteria in theD.O.T. acceptable criteria section above may not be sufficient protection.

At pipeline locations where external corrosion-related leaks are discovered, ameasurement of the pipe-to-soil cathodic potential shall be taken. If the level isless than that required by regulations, the Engineer shall reevaluate the CP system capacity and upgrade it as necessary prior to the next inspection.

Test and survey of CP systems according to the frequency schedule listed in Table 3.5A.

Prompt remedial action, at least prior to the next required survey, must be taken to correct condition which caused the pipeline to fail to meet the applicable criterion.

RECORDS: Record the location of cathodically protected pipeline, cathodicprotection facilities, and neighboring structures bonded to cathodic protectionsystem on WGS Form 113 Cathodic Protection System Record. (See pipelinedrawings.)

The pipe-to-soil surveys are to be recorded or plotted on the form or chartsprovided for that purpose. The annual pipe-to-soil surveys, reports, and anyremedial action, are to be retained for the life of the facility.

Except for annual pipe-to-soil surveys, these records are to be maintained for atleast five years.

Annual pipe-to-soil surveys and reports, and remedial action reports, if any, shallbe retained for the life of the facility.



TABLE 3.5AREQUIRED TESTS FOR CATHODIC PROTECTION

SURVEY OR TEST FREQUENCYPipe-to-Soil Once each calendar year, but with

intervals not exceeding 15 months. Critical Bond Six times each calendar year, but with

intervals not exceeding 2-1/2 months.Non-critical Bonds Once each calendar year, but with

intervals not exceeding 15 months. Insulation Test Once each calendar year, but with

intervals not exceeding 15 months. Rectifier Inspection Six times each calendar year, but with

intervals not exceeding 2-1/2 months. SUPPLEMENTAL TESTING

Foreign Crossing Interference Initially and as required, if survey done on recurring basis indicated the need.

Soil Resistivity Initially for magnesium anode or impressed current ground bed installations.

Current Requirement Initially and as required to determine current density, coating condition and cathodic protection sizing.

Deep Ground Bed Data Initially to record all ground bed data during installation.

Deep Well Anode Performance Initially and as required to record anode current outputs and look for ground bed deterioration.

Galvanic Anode Record Initially to record all data during installation.

Rectifier Efficiency Initially and as required.



ELECTRICAL ISOLATION

CODE REFERENCE: Title 49 CFR Sections 192.467 and 192.613

PURPOSE: To outline requirements for electrical isolation of buried orsubmerged pipeline facilities.

GENERAL: In order to successfully and efficiently cathodically protect a buriedor submerged pipeline system, it is vital that the system be electrically isolatedfrom foreign structures.

Electrical isolating devices are installed on pipeline systems to control currentflow to or from foreign structures. Insulating devices are also used to isolatesections of the same pipeline (which can facilitate the application of cathodicprotection) and to isolate the pipeline from a casing or structural supports attached to other unprotected metallic structures.

No electrical isolating device shall be installed in a closed area that could retainan explosive mixture unless provisions are made to prevent electrical arcing. This includes situations similar to insulating flange kits in vaults.

STANDARD ELECTRICAL ISOLATION METHOD

FLANGE INSULATION An insulating kit consists of an electrically non-conductive gasket, non-conductive sleeves to encase the studs, and non-conductive washers for both nuts of a stud. Steel washers should also be placedimmediately under nuts to protect the insulating washer from being crushedduring torquing.

When welding the insulating flange unit or the weld type insulated coupling intothe line, care shall be exercised to be sure that the current arc, which couldoccur from welding, does not damage the insulation. This can be achieved bymoving the ground cable to the same side of the flange set as the electrode cablethus eliminating current arc across the insulating flange during welding.

MONOBLOCK INSULATING JOINTS Monoblock insulating joints arefactory-assembled insulating assemblies, which are welded into a pipeline; theyhave no serviceable parts.

INSULATED UNIONS Insulating unions are usually used for small diameter(3 inches or less) piping attachments, which required electrical insulation.

CASING CENTRALIZERS AND END SEALS Non-conductive centralizingdevices are attached to pipelines where the carrier pipe passes through a casedcrossing. Casing end seals prevent water or soil from entering the annular space



between the carrier pipe and casing and causing an electrolytic short betweenthe casing and the pipe.

OTHER DEVICES Frequently, high pressure laminated (e.g. Micarta)dielectric blocks or neoprene rubber pads are used to electrically isolate pipelinefrom supports or other structural appurtenances, which are not a part of thecathodically protected pipeline.

CASED CROSSINGS - Whenever possible, casing installations should beavoided. In some cases, however, railroad or public highway regulations requiredthe installation of a casing for railway right-of-way or road crossings. Whencasing are required, the carrier pipe must be electrically isolated from the casing.

PROCEDURE:

LOCATION AND INSULATING DEVICES Generally, insulating devicesshould not be buried in the soil (or submerged), but located in pipe above groundor in a vault. At the termination of a pipeline, the insulating device should be asclose as possible to the point where the pipeline comes above grade. Laterals,pressure taps, etc. should have insulating devices located as close as possible tothe cathodically protected pipeline.

Electrical isolation equipment or devices should be installed to isolate structurefrom the following locations:

At the termination points of a pipeline system and entering or leaving apump or compressor station;At exchanges or interconnect point with other pipeline companies;At connection points for gas operated control lines, electrical conduitattachments or instrumentation connections;At established above ground Company facilities;On the downstream side of metering stations;Between the casing and carrier pipe;Between supporting structures and the carrier pipe on bridge crossings;Between all metallic structures not requiring cathodic protection, such asmetal valve boxes, conduit, fences, etc. and a cathodically protectedpipeline;Where fault currents or lightning can affect the pipeline, such as close toelectrical transmission tower footings or ground cables;At point where dissimilar metals are attached to the pipeline, provided that both the pipeline and the dissimilar metal are buried or submerged.

REPAIRS Prompt remedial action (at least prior to the next required test) shallbe taken where the loss of electrical isolation causes a failure to meet theapplicable cathodic protection criterion or causes detrimental effects to a foreignstructure.



The remedial action should be restoration of electrical isolation; in somecases, other measures (such as increasing the amount of cathodicprotection current applied to the pipeline) can be taken that willadequately protect foreign structures.If the loss of isolation does not require prompt action, the insulatingdevice should be repaired at the earliest opportunity in conjunction withother scheduled maintenance or modifications to the piping system.

SHORTED CASING Pipeline, in casing where isolation was intended wheninstalled, shall be evaluated and acted upon as outlined below:

If casing-to-soil potential is within 100 millivolts of the carrier pipe-to-soilpotential, further testing is required to determine if electrical isolationexists.Determine whether the situation is an electrolytic condition or ametallic shorted casing.Electrolytic conditions in casings require no remedial action.Retest the casing when a future survey indicates a significant decrease inpotential separation from the previous test, at a casing where the testprocedures previously indicated an electrolytic condition.Attempt to clear a shorted casing promptly, within 6 months, afterdiscovery by implementing the following actions.

Inspect the test wires for possible direct shorts, and repair asnecessary;If practical, excavate the ends of the casing and inspect theclearance between the casing and carrier pipe. If contact exists,reposition the carrier pipe and replace damaged insulators and endseals;When a shorted casing cannot be cleared by implementing theabove actions, consider installing new carrier pipe insulators whenthe pipeline segment is out of service for other scheduled repair,replacement, or modification; or consider filling the casing/pipeannulus with high dielectric casing filler.Remove shorted casing when convenient.Electromagnetic flux leakage or ultrasonic smart pigs may confirmpipe wall metal loss.

Casings that are determined to be shorted and impractical to promptlycorrect, shall be monitored by using leak detection instruments as shownin Table 3.5B. If a leak is found, it must be repaired immediately.

INSPECTION AND TESTING - Inspection and testing frequency requirementsfor the electrical isolations and shorted casing are shown in Table 3.5B.



TABLE 3.5BTEST FREQUENCIES FOR ELECTRICAL ISOLATION AND SHORTED

CASINGSTEST: FREQUENCY:

Electrical Isolation Once each calendar year at intervals not exceeding fifteen (15) months.

Shorted Casings:Class 1,2,3&4 locations Twice each calendar year at intervals

not exceeding 7-1/2 months. (Flame Ionization Inspection)

RECORDS: Document all electrical isolation and casing gas leak testing. Keepthese documents for at least five years.

Record the test on possible shorted casing. Retain the record for each shortedcasing until is it removed.

IMPRESSED CURRENT POWER SOURCE INSPECTION

CODE REFERENCE: Title 49 CFR, Sections 192.465, 192.491, and 192.613

PURPOSE: To establish the requirements for inspecting and checking impressed current cathodic protection systems.

GENERAL: Rectifiers and ground beds provide a driving voltage and currentgreater than can be produced by galvanic anodes. Compared to sacrificial anodes, this type of protection covers a much larger area and gives greater flexibility tothe cathodic protection system by allowing control of the current output.

The rectifier ground bed method develops an electrolytic cell making the structure to be protected the cathode, and the ground bed of the rectifier, the anode.(Reversing the polarity will cause rapid corrosion of the pipeline.)

To gain the greatest benefit from corrosion control, it must be a continuousprocess. The rectifier will not give protection if it has not been properly installed.Therefore, proper installation of any rectifier is of utmost importance and willserve to prevent trouble later.

PROCEDURE: Inspect each cathodic protection rectifier or other impressedcurrent power source at least six (6) times each calendar year, but at intervals notexceeding 2-1/2 months.

Conduct the following tasks during each inspection:

Operations

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