Federal Register / Vol. 56, No. 52 / Monday, March 18, 1991 / Proposed Rules

DEPARTMENT OF TRANSPORTATION

Research and Special ProgramsAdministration

49 CFR Parts 191 and 192

[Docket No. 106; Notice 2]

RIN 2137-AB63

Transportation of Hydrogen Sulfide byPipeline

AGENCY: Research and Special ProgramsAdministration (RSPA), U.S. Departmentof Transportation (DOT).ACTION: Notice of proposed rulemaking(NPRM).

SUMMARY: This notice proposesregulations to control the concentrationof hydrogen sulfide (II2S in natural gaspipeline systems because highconcentrations of HS are extremelytoxic if released. The proposed rulewould:

(a) Prohibit operators fromtransporting in a transmission linedownstream of gas processing plants,sulfur recovery plants, or storage fields,natural gas containing more than 1 grainof hydrogen sulfide (H2S) per 100standard cubic feet (SCF) of natural gas;

(b) Require that the release of H2S inexcess of 20 grains per 100 SCF ofnatural gas into a transmission line betelephonically reported to DOT; and

(c) Require that onshore and offshoregathering lines carrying H2S in excess of31 grains per 100 SCF of natural gashave a contingency plan in case of therelease of the gas into the atmosphere.DATES- Interested parties are invited tosubmit comments by June 17, 1991.ADDRESSES: Send comments induplicate to the Dockets Unit, room8417, Research and Special ProgramsAdministration, U.S. Department ofTransportation, 400 Seventh Street, SW.,Washirgton, DC 20590. Identify thedocket and notice numbers stated in theheading of this notice. All commentsand docketed material will be availablefor inspection and copying in room 8426between 8:30 a.m. and 5 p.m. eachbusiness day.FOR FURTHER INFORMATION CONTACT:Cesar De Leon (202) 366-4583, regardingthe subject matter of this document, orthe Dockets Unit (202) 366-5046, forcopies of this document or othermaterial in the docket.SUPPLEMENTARY INFORMATION:

Background

The RSPA issued an Advance Noticeof Proposed Rulemaking (ANPRM) onJune 7, 1989 (54 FR 24361) requestinginformation to assist RSPA to determine

the need for regulations to control theconcentration of hydrogen sulfide innatural gas pipeline systems. Hydrogensulfide is a colorless, flammable gaswhich is poisonous if inhaled. It isconsidered to be hazardous to life andhealth at concentrations of 300 parts permillion (ppm). At concentrations of 1,000ppm in air it causes immediateunconsciousness and death. TheOccupational Safety and HealthAdministration (OSHA) has establishedan upper concentration level of 10 ppmfor prolonged (8 hours) work placeexposure to F12S.

Natural gas produced from some gasproduction wells has highconcentrations of H2 S. For example, agas production field that has some of thehighest H2S concentrations in thecountry is the Mary Ann Field in MobileBay in Alabama which produces naturalgas averaging 71/2 percent or 75,000 ppmof 2S. Gas with high concentrations ofH2S, commonly called "sour gas", is"sweetened" by removing the H2S fromthe natural gas in treatment plantsbefore the natural gas is introduced intogas transmission pipelines.

At present, the federal gas pipelinesafety regulations, 49 CFR part 192, donot specifically address the risk to thepublic of being exposed to the toxiceffects of H2S due to its presence innatural gas pipelines. The currentregulations in 49 CFR part 192 addressH2S only with respect to its corrosiveeffects on pipelines, as follows:

0 49 CFR 192.125(d) requires thatcopper pipe that does not have aninternal corrosion resistant lining maynot be used to carry gas that has anaverage hydrogen sulfide content ofmore than 0.3 grains per 100 standardcubic feet of gas.

* 49 CFR 192.475 requires thatcorrosive gas may not be transported bypipeline unless the corrosive effect ofthe gas on the pipeline has beeninvestigated and steps have been takento minimize internal corrosion. Inaddition gas containing more than 0.1grain of hydrogen sulfide per 100standard cubic feet may not be stored inpipe-type or bottle-type holders.

* 49 CFR 195.418 requires that nooperator may transport any hazardousliquid that would corrode the pipe orother pipeline components unless it hasinvestigated the corrosive effect andtaken steps to mitigate corrosion.

The ANPRM set forth many incidentsthat have occurred in California, Texas,and Canada in which I 2S had gottenpast gas treatment plants and gotteninto gas transmission and even intodistribution systems.

The ANPRM also set forth stateregulations in Texas, Michigan, andCalifornia addressing the occurrence ofhigh concentrations of H2S in pipelines,many of which would have beenmitigated if appropriate Federalregulations had been in place. Oneincident occurred on December 28, 1988,when the Pacific Offshore PipelineCompany's (POPCO) Las Flores CanyonTreatment Plant was placed in service.Due to the failure of an automatic gasanalyzer, gas was contaminated by 200PPM of H2S and entered the distributionsystem of Southern California GasCompany (SCG). After the analyzer wasrepaired following the interrruption ofgas flow, the gas flow was reinitiated.Further analysis indicated 16 PPM H2Sin the gas stream and the gas flow wasagain stopped.

Another incident involving H2Sentering the SCG system occurred onMay 12, 1984, at the Wilmington,California, gas delivery plant. Followingthis incident, the California PublicUtilities Commission (PUC) requestedthat all SCG locations that could receivecontaminated gas be equipped with gasanalyzers. As a result of these incidentsin California, the California PUC hasrequired that gas supply be monitoredby automatic equipment at gas supplypoints.

On August 11, 1987, automatic 2Smonitoring equipment at the KG GasProcessors, Limited, near Winston,Texas, indicated that an excessiveamount of I-12S was being delivered toLone Star Gas Company. Gas companypersonnel found H2S in concentrationsof 1600 PPM and greater and purged theentire system. The excessiveconcentrations of HS were not detectedbecause automatic shut-off equipment atKG had failed to operate in response tothe automatic monitor and Lone Star'smonitoring equipment had beenremoved for repair at that time. From itsreview of Lone Star's records NTSBfound that since 1977, 11 incidentsinvolving the release of excessivequantities of -LS into its pipeline systemhad occurred.

As a result of a review of severalincidents involving the release ofexcessive quantities of IKS into pipelinesystems, on May 10, 1988, by letter tothe Administrator of RSPA, the NationalTransportation Safety Board (NTSB)recommended that RSPA:

(1) Establish, based on knowntoxicological data, a maximumallowable concentration of H2S innatural gas pipeline systems, and amend49 CFR part 192 to reflect thisdetermination. (P-88-1; Class II, PriorityAction)

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(2) Revise 49 CFR part 191 to requirethat pipeline operators report allincidents in which concentrations of H 2Sin excess of the maximum allowableconcentration axe introduced intopipeline systems that transport naturalgas intended for domestic or commercialpurposes. (P-88-2; Class III, Longer-Term Action)

(3) Require gas pipdiu:e operators toinstall on their systemtJ equipmentcapable of automatically detecting andshutting off the flow of gas when themaximum allowable concentrations ofH2S-contaminated gas are exceeded. (P-88-3; Class III, Longer-Term Action)

Because RSPA has no carrentregulations that require the monitoringof maximum H2S concentration in gaspipeline systems, RSPA requestedinformation in the ANPRM toappropriately assess the need forestablishing such regulations.

Interested parties were invited toanswer the following questions andsubmit relevant informatioa includingany accident experience (if applicable)associated with HS release(s):

(1) What factors should be consideredin determining the need for a maximumallowable concentration of 112S innatural gas pipeline systems? Whatshould this concentration be?

(2) Describe events you know of inwhich H2S has been released from, orinto, a pipeline in dangerous amountsand what were the S2 concentrations?What were the conseqences of suchreleases? What would be the burdenassociated with mandatory reporting ofsuch events?

(3) If you are an operator receiving gasfrom a producer, do you have automaticHzS detection and shut-off equipment?Do these devices operate reliably? Forsuch operators that do not have thisequipment, what costs and otherburdens can be associated withrequiring use of the equipment?

(4) Which pipelines transporting sourgas should be subject to an HSmonitoring requirement? Should ruralgas gathering lines be subjected to 2Smonitoring requirements, even thoughthey are not now subject to any of thepart 192 safety standards?

As a result of a review of thecomments, RSPA believes thatregulatory action is required to addressthe hazards from the accidental releaseof natural gas having excess quantitiesof .S. There are increasing numbers ofnatural gas production fields producingsour gas that could be released intotransmission pipelines thereby creatinga hazard to people that live along thepipeline, as well as possibly enteringdistribution systems. In addition, thereare many gathering lines in onshore non-

rural areas which are transportinghighly toxic sour gas which put at riskthe people living in close proximity tothose pipelines. Offshore gathering linescarrying sour gas equally put workers atrisk on offshore platforms. Theinhalation by the workers to the sourgas from the offshore Mary Ann Field inMobile Bay in Alabama could result inimmediate death. Appropriateregulations established now shouldminimize the hazards from futurereleases of sour gas into transmissionlines, as well as provide contingencyplans for the accidental release of sourgas into the atmosphere from onshoreand offshore gathering lines.

Discussion of Comments

The RSPA received 54 comments,principally from natural gas andhazardous liquid pipeline operators.There were also comments from twoprivate citizens, two state regulatoryagencies, the Minerals ManagementService (MMS) of Department of theInterior, and five natural gas andhazardous liquid trade associations.

In addition to responding to thespecific questions, there were manycommenters that set forth generalcomments on the need to issueregulations to control the concentrationof H2S in natural gas pipeline systems.The following is a discussion of generalcomments received on the ANPRM.

General Comments

Two private citizens are opposed tothe presence of S25 in pipelines becauseof the possibility of its release. Onecommenter lives near a production welland associated gas gathering lines thattransport natural gas with H2S andaddresses her comments to Question 4.The other commenter complains of thesmell of S2 and also comments that theH2S in these wells has resulted in thedeath of dogs and cattle. She argues thatthere should be restrictions on howclose to homes a company may installan K1S pipeline.

La Clede Gas Company supported theissuance of regulations to establish amaximum concentration of I-2S inpipeline systems to provide safety of thenatural gas consumer and protect theintegrity of the system.

The MMS supports therecommendations made by the NTSB.The DOI supports a rule similar to thatproposed by California General Order58. Order 58 proposes that no gassupplied by any gas utility shall containmore than 0.75 grains of H2S per 100 SCFof natural gas. (1 grain of K1S per 100SCF is equal to 15.9 ppm of H2S. Inaddition, MMS supports the requiredinstallation of I2S monitoring

equipment in these pipelines fordetection and shutoff flow of gas whenthe maximum allowable concentrationof H2S is exceeded.H-S monitoring equipment and gas

purchase contracts use "grains per 100SCF" as a standard unit of S2Smeasurement in natural gas rather than"ppm of H2S". Most state regulationsregarding IS similarly use "grains per100 SCF" as a standard unit of lKSmeasurement in natural gas.

The Texas Railroad Commission,identified by most industry commentersas having adequate regulationsaddressing high concentrations of 11 2S ingas pipelines, stated that RSPA shouldnot extend regulations for K2,S togathering lines in Texas because thoselines were covered by the TexasRailroad Commission under Rule 36entitled "Oil, Gas, or GeothermalResource Operation in Hydrogen SulfideAreas." The Commission also believedthat regulations addressing H2S shouldonly be made applicable to pipelineoperators that transport or transfer gasrequiring 2I2S treatment.

Most industry commenters wereopposed to any regulations addressingIH-S in pipelines. Panhandle EasternCorporation commented that suchrulemaking is ill-advised andunwarranted because there existssufficient requirements in 49 CFR part192 to adequately address the issuesraised. The American Gas Association(AGA) and United Gas Pipe LineCompany, among others, thought thatthe producer of natural gas, rather thanthe transmission pipeline operator ordistribution operator, should beresponsible for monitoring theconcentration of 11S in the gas. TheAGA, Interstate Natural GasAssociation of America (INGAA), theAmerican Petroleum Institute (API), andmany operators stated their oppositionto mandatory monitoring of H2 S

concentrations with automaticshutdown capability. Many of thesecommenters argued that removal of 2Sor treatment to acceptable levels is theresponsibility of the producer asspecified in gas purchase contracts.They also mentioned the possibility offalse closures which would interruptservice to customers unnecessarily if themonitoring equipment is located on thedistribution system.

The Gas Processors Association(GPA), which represents about 170corporate members which process about90 percent of all natural gas in thecountry, opposes a maximum allowableconcentration of 1KS in natural gaspipeline systems. The GPA argues thatcontracts that limit the concentration of

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L2S in natural gas delivered totransmission pipelines protectcustomers and problems are rare. TheGPA further states that theresponsibility of preventing H2S gasfrom reaching domestic customersshould rest in the hands of thedistribution company not with the gasproducer, gas processor, or gastransmission company; The GPA furtherpoints out that although pipeline upsetswhich cause 1-2S to enter thetransmission system are undesirable,they are unlikely to have a significantaffect because of dilution due to co-mingling further downstream in thetransmission system.

The Pacific Gas and Electric Company(PG&E) takes issue with the statement inthe ANPRM that the California PublicUtility Commission (PUC) requires thatits previously determined upper limit ofH2S be monitored by automaticequipment on a daily basis at gas supplypoints. The PG&E understands that theCalifornia PUC required SouthernCalifornia Gas Company to installautomatic H2S monitors and automaticshutoff devices at locations where -H2Scontaminated gas could enter the gassystem. The Southern California GasCompany recommended that theDepartment only require monitoring ofH2S levels at the custody transfer pointwhere contaminated gas is receivedfrom the gas producer rather thanthroughout the operator's pipelinesystem.

Amoco Gas Company did not supportNTSB's recommendation that RSPAestablish a maximum allowableconcentration of H2S in natural gaspipelines for the following three reasons.First, the natural gas purchaser bycontract dictates the maximumallowable concentration of H2S. Thepipeline operator and end user areaware of the end user's risk of exposureto H2S and have taken their ownprecautions by contract. Second, havingestablished a contract maximum and inaccordance with 49 CFR 192.475(a),operators design their pipelines andcomponents to handle the concentrationspecified by the contract. When asystem is properly designed andoperated, the probability of a leak isequal to or less than a line that does nottransport -H2S contaminated gas. Third,a regulation limiting the amount of 2Sin pipeline systems would not haveprevented any of the incidents reportedby the NTSB in this notice because eachof the incidents was the result of two ormore independent equipment failures.

The Town of Boy Springs, Mississippi,commented that attention should befocused on producers and transmission

pipelines so that there would be no needto have W2S detection and automaticshut-off systems for local distributioncompanies. The Northern Illinois GasCompany commented that the presentregulations have served their intendedpurposes appropriately and theconcentration of HKS in gas pipelines areengineering and business mattersbetween the responsible operator andhis supplier.

RSPA Comments

Arguments by some operators thatregulations are not needed because theyhave contractual requirements that limitthe amount H2S in pipelines are notIpersuasive. If contractualresponsibilities were the only control, arelease of excessive quantities of H2Sinto pipelines would only result in aviolation of a contract. Public safetywould be better served by a Federalregulation that sets a limit of -2S inpipelines. A violation of suchregulations could result in penalties.Furthermore, this requirement would notimpose unreasonable burdens, sinceconcentration levels of H2S are routinelyconsidered in the industry.

Further, the current requirements donot address the toxic effects of H2S asalleged by many commenters. Sections192.125, 192.475, and 192.418 are targetedat preventing corrosive effects of H2S inpipelines.

With regard to the private citizensthat appealed for restrictions on howclose to homes a company may installan -I2S pipeline, the Natural GasPipeline Safety Act precludesestablishing location or routing ofpipelines by the regulations issuedthereunder (49 app. U.S.C. 1671(4)). Thelocation and route of a pipeline ishandled better at the local level. Fromthe description of the pipeline locatednear to their houses, it appears that theprivate citizens lived near gatheringlines. Gathering lines are furtherdiscussed in Question No. 4.

Other general comments areaddressed below in the RSPA commentsto the public comments to the fourquestions set forth in the ANPRM.

The following sets forth the commentsto each of the questions posed in theANPRM:

Question 1: What factors should beconsidered in determining the need for amaximum allowable concentration ofH2S in natural gas pipeline systems?What should this concentration be?

Comments: A wide variety ofcomments were received regarding thefactors that should be considered indetermining the need for a maximumallowable concentration of -2S innatural gas pipeline systems. Phillips

Petroleum Company suggested thefollowing factors:

a. Flow rate.b. Operating pressure.c. Operating temperature.d. H2S and H20 concentration.e. Presence of CO2 and other

contaminants.f. Presence of hydrocarbon liquids.g. Prevailing weather conditions.h. Population density.i. Material specifications.j. Use of inhibitors.k. Gathering vs. transmission

functions.Southern Natural Gas Pipeline

Company suggested the followingfactors:

a. Potential for H2S to be present inthe system.

b. Detrimental effects H2S on pipe andappurtenances.

c. Natural gas end use requirements.d. Potential exposure to company

employees.e. Potential exposure to the public/

property in proximity of that pipelinesystem.

The AGA suggested the followingfactors:

a. Whether the particular system willexperience high concentrations of sourgas for a period of time to create asafety problem.

b. Identification of delivery points thathave the ability to contain highconcentrations of sour gas.

c. Degree of danger presented to thepublic and employees of gas companiesbecause of the toxicity of sour gas.

d. Effect of the gas stream onmaterials used in the pipeline system.

e. Stress level at the pipeline'smaximum allowable operating pressure.

f. Class location.g. Other impurities.The INGAA proposed the following

factors:a. Type and grade of pipe exposed to

H2S.b. Other impurities in the gas stream

(moisture and carbon dioxide).c. Volume of gas containing F12S vs.

volume of gas in the transmissionpipeline.

d. Existing standards such as NACEMR-01-75 and API RP 14E.

e. Availability and use of inhibitors.f. Health effects on company

employees, the public, and theconsumer.

g. Potential detrimental effect on thepipeline system.

h. Population density along thepipeline route.

i. The stress level at the pipeline'sMAOP.

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j. Purpose of the pipeline (gathering,transmission, or distribution).

The Columbia Gas DistributionCompanies stated that the factors canbe focused on two major issues:

a. The safety of employees, customers,and the general public who have thepotential of exposure to the gas streamunder normal and emergency conditions.

b. Operating or maintenancedifficulties in the pipeline system causedby undesirable constituents. /

The Independent PetroleumAssociation of America (IPAA) statedthat the main factor to be considered indetermining the need for a maximumallowable concentration for HS innatural gas pipeline systems is theimmediate destination of the gas.Additionally, the following factorsshould be considered:

a. Population density surroundingpipelines.

b. Leak history.c. Design criteria.d. Performance of proper

maintenance.e. Construction techniques.f. Welding procedures.g. Age of pipelines.h. Type of internal corrosion

mitigation currently on pipelines.i. Maximum allowable operating

pressure of the pipelines.j. Distance of isolation valves on the

pipelines.k. Number of employees per mile of

pipe to maintain the pipelines.Many commenters expressed a view

regarding the concentration of KaS thatshould be allowed in natural gaspipeline systems. The range covered bymost commenters was from 0.25 to 1grain of H2S per 100 SCF of the naturalgas or between 4 and 16 ppm. The gasproducers and transmission operatorsfavored the upper limit or grain of KaSper 100 SCF of natural gas while mostdistribution operators suggested thelower limit or 0.25 grain of HS per 100SCF of natural gas. Mobil Pipe LineCompany commented that the limitsshould be 0.25-0.30 grains of KaS per 100SCF of natural gas, limits that are underconsideration for legislation in Michiganand California. Warren PetroleumCompany commented that the maximumallowable concentration of H2S carriedthrough a pipeline must be unlimited butstates that the company has a plan tocomply with the Texas RailroadCommission Rule 36 requiring acontingency plan for pipelines carryinggas containing H2S in concentrations of100 ppm and greater.

Transcontinental Gas PipelineCorporation (Transco) and INGAAcommented that any rule changeconcerning the allowable limits of HaS

should provide for the "grandfathering"of existing gas purchase contracts.

RSPA CommentsThe commenters presented many

excellent suggestions on the factors thatshould be considered in determining themaximum allowable concentration ofH2 S in natural gas pipeline systems. Thesuggested factors, as can be seen above,covered a wide spectrum of criteria. TheRSPA has included factors proposed bysome of the commenters that representpractically all of the factors proposed bycommenters to this ANPRM. Thesefactors should be of use to commentersin commenting on the proposalsdiscussed below for establishing themaximum allowable concentration of1-12S in natural gas pipeline systems.

As a minimum, the range of limits forHS set forth by most of the commentersshould not be exceeded in light of thetoxic effects of natural gas containingHS that exceeds such limits. The RSPAbelieves that an upper limit of I grain ofHS / 100 SCF of natural gas isappropriate because it is consistent withthe limit set by OSHA and severalstates. Many commenters supported thatlimit to be the maximum concentrationof H2S in natural gas pipelines. Onegrain of H2S / 100 SCF of natural gas isabout 16 ppm of HS in natural gas,which is slightly in excess of the 10 ppmconcentration permitted by OSHA forprolonged (8 hours) workplace exposure.In addition, such a limit would not affectexisting gas purchase contracts because1 grain of H2S / 100 SCF of natural gas isthe upper limit for gas contractsaccording to commenters.

Question 2: Describe events you knowof in which HS has been released from,or into, a pipeline in dangerous amountsand what were the H2S concentrations?What were the consequences of suchreleases? What would be the burdenassociated with mandatory reporting ofsuch events?

Comments: Many companies reportedevents in which H2S was released into apipeline in dangerous amounts but mostof the companies indicated that the H2Swas diluted further downstream. TheAGA indicated that such releases do notappear to be significant, widespread, ora recurring problem. The AGA reportedone instance in which the release was2,000 ppm. The IPAA indicated severalsituations that may present a potentialfor a release of H2S from a pipeline orinto a pipeline, and then includedprocedures to prevent such releases.Tenneco indicated several instanceswhere a treatment facility failed toreduce K1S to the contract requirementlevel but the HS was diluted furtherdownstream. The GPA also pointed out

that while gas containing I-HS thatexceeds the contract limits may enterthe transmission line, the gas is unlikelyto have a significant effect because ofdilution due to co-mingling in thetransmission system.

With regard to the question regardingthe burden associated with mandatoryreporting of such events, many industrycommenters questioned how reportingof these incidents would increase publicsafety and what, if any, benefits couldbe derived from the reports. Mostdistribution system operators indicatedlittle or no burden because most hadnever had excessive concentrations ofHS in those systems. Manytransmission operators also indicatedlittle burden with reporting excessiveamounts of H2S in transmissionpipelines. The AGA, Columbia Gas-Transmission, and Colorado Interstateobserved that the burden would dependon the scope and depth of the reportingrequirements. Columbia Gas-Distribution commented that it would bereasonable to report incidents usingcriteria similar to pipeline failureincidents where death or injury,extensive property damage, and mediacoverage are involved. Northern IndianaPublic Service Company commentedthat the reporting burden would result in$484,000 of capital costs and $105,000annual costs. Consumers Power statedthat it believed that a reporting trigger of300 ppm or over of H2S would cause arelatively light reporting burden. Therewere several commenters, especiallythose operating closer to the source ofgas, such as GPA and EquitableResources, that indicated there wouldbe a reporting burden.

RSPA Comments

The comments indicate that thereleases of HS into pipeline systemshas not been a widespread, significant,or recurring problem. Nonetheless, arelease of an excessive amount of KaSinto a pipeline system may result in ahazardous situation if a leak in the linecarrying the higher concentration of H2Sescapes from the line before the gas isburned. Such releases have occurred,and the gas with high concentrations ofHS has been released into distributionsystems. The gas was not diluted asindicated by some commenters. RSPAbelieves that a reporting requirement isalso needed to determine if the releaseof excessive amounts of H2S intotransmission pipelines is a problem. Theproposed reporting threshold for H2Sreleases in this NPRM is set sufficientlyhigh to gain information only wheredangerous amounts of 1-hS have beenreleased into transmission pipelines.

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The proposed threshold for reporting is20 grains of H2S / 100 SCF of naturalgas, or over 300 ppm.

Question 3: If you are an operatorreceiving gas from a producer, do youhave automatic H2S detection and shut-off equipment? Do these devices workreliably? For such operators that do nothave this equipment, what costs andother burdens can be associated withrequiring use of the equipment?

Comments:Practically all of the operators that

received gas from a producer, such asTenneco Gas, Corp., Midcon, PanhandleEastern Corporation, Questar PipelineCo., Transco, Texaco USA, Delhi GasPipeline Corp., and Northwest PipelineCorp., had either monitoring orautomatic shutoff I2S detectionequipment. Most of these operatorsindicated that the equipment operatedreliably. Only two commenters, Tennecoand Columbia Gas-Transmission,indicated that the equipment was notreliable. Most operators that hadequipment indicated a cost of $10,000 to$30,000 per installation. Two significantdepartures from this range wereNorthwest that indicated that a gaschromatograph analyzer would cost$14,000 to $45,000 per installation andMidcon indicated up to $45,000 perinstallation. IPAA and INGAA indicatedthat the annual operating andmaintenance cost reported by theiroperators was about $1,500 perinstallation. However, SouthernCalifornia Gas reported $3,000 in annualoperating and maintenance costs;Questar indicated $1,000 in monthlyoperating costs; and Phillips Petroleumreported $2,000 in monthly operatingand maintenace costs. PG&E reportedunspecified low maintenance costs.Northern Indiana, a distributioncompany, stated that it would cost$484,000 to install equipment for theirentire system and that it would cost$105,000 annually to operate andmaintain the equipment.

RSPA CommentsRSPA believes that high

concentrations of I-I2S should beremoved from the gas before it isdelivered to the transmission pipeline toensure public safety. Under therequirements proposed in this Notice,RSPA would limit the amount of I-I2S innatural gas in transmission lines,thereby establishing a limit of H2Swhere gas is delivered to thetransmission operator. This will put theburden on the producer or the operatorof the processing plant to provide gasthat does not contain highconcentrations of HS to thetransmission pipeline. The limitation of

the high concentration of HS is notaimed at the distribution systembecause this would allow transmissionlines to transport gas with highconcentrations of -2S thereby creating ahazard to people living near atransmission pipeline.

RSPA has not specified the type ofequipment necessary to meet thisproposed requirement. The commentsindicate that many operators receivinggas from a producer have automatic ISdetection and shut-off equipment andthat these devices work reliably. RSPAbelieves that the operator should makethe decision on the type of equipment itwill use in complying with this proposedrequirement.

RSPA has used the cost figures of -I2Sdetection and shut-off equipmentacquired in the comments to theANPRM to assess the relative costs inhaving the industry comply with thisproposed requirement.

Question 4: Which pipelinestransporting sour gas should be subjectto an IH2S monitoring requirement?Should rural gas gathering lines besubject to 12S monitoring requirements,even though they are not now subject toany of the part 192 safety standards?

Comments: With regard to thequestion of which pipelines transportingsour gas should be subject to an H2Smonitoring requirement, very fewcommenters thought that such linesshould not be monitored. However,Transco argued that although sour gaspipelines usually contain extremelycorrosive gas (more than 300 ppm), theselines are designed and maintained toaccommodate the corrosive effects ofhigh concentration of FI2S. Therefore,monitoring would serve no usefulpurpose. Chevron Pipe Line Companycommented similarly.

Washington Gas Light Companycommented that monitoring of 1-I2Sshould occur at the point of origin or theclosest point to the source and notrequire redundant monitoring atdistribution systems. PG&E and UnitedGas Pipe Line Ccmpany commentedsimilarly, stating that the monitoringshould be required at the point ofdelivery when (1) the source gas hasbeen processed for 1-I2S removal and (2)the source gas (before processing)contains unacceptably high levels of -tSwhich the downstream pipeline systemis not designed to handle. Mountain FuelSupply Company believes that operatorstransporting sour gas that are presentlyunder the jurisdiction of DOT shouldhave the responsibility of insuringpipeline quality of gas, including 142Smonitoring. IPAA and Delhi GasPipeline Corporation suggested that onlythose pipelines with known -12S gas that

deliver into a distribution systemdownstream of a treating facility shouldbe subject to an H2S monitoringrequirement. Texaco commented thatany monitoring should be directed at gasdistribution operators who supply gasfor consumer use.

With regard to the question ofwhether rural gas gathering lines shouldbe subject to H2S monitoring, mostcommenters were opposed to the idea.Phillips Petroleum Company commentedthat gathering lines routinely transportvolumes of very sour gas because this isa normal part of gas gatheringoperations and these lines should not besubject to KIS monitoring equipment.The AGA commented that gatheringlines in sour gas service are designedand maintained to accommodate thecorrosive effects of high concentrationsof H2 S and that these lines areadequately regulated by stateregulations in states having sour gasproduction. The IPAA made the samearguments as AGA and furthercommented that monitoring equipmentshould be located at the point at whichgas enters a transmission line ordistribution system after which nofurther treatment of gas occurs. Conoco,Inc., while disagreeing with thenoncompliance procedures, generallyagrees with the technical requirementsand limitations of a Bureau of LandManagement proposal (54 FR 21075;May 10, 1989) for H2S monitoring forFederal and Indian leases. The GPAstated that the regulation of 2S ingathering lines is impractical as thesepipelines are generally upstream of thegas processing facilities which removethe H2S. If a maximum allowableconcentration in gas gathering pipelinesis established many sour gas fields maybe forced to shut down. The IPAA hadsimilar views as those set forth above.Several commenters stated that thecontingency plan required by the TexasRailroad Commission for gathering lineshaving excessive amounts of -12S is agood regulatory approach.

The MMS commented that the hazardof an accidental injection of H2S in apipeline system in populated areas issufficient justification for requiring KISmonitoring equipment on any pipelinewhere any connecting pipeline deliversgas that has been treated to remove KISprior to injection.

RSPA Comments

The RSPA agrees with mostcommenters that the monitoring shouldbe conducted at the interface betweenthe gathering line and a transmissionline, immediately downstream of thepoint where the gas has been treated for

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H2S removal. The RSPA believes thatthis is the appropriate point to detect thepossible failure of the treatmentequipment for H2S removal. If themonitoring is accomplished at this point,there will not be any need to monitor forlKS farther downstream at the point ofdelivery to a distribution system assome commenters suggested. The RSPAalso agrees with those commenters thatargued that there was no need formonitoring equipment when thetransmission pipelines are not receivingnatural gas that may be subject to H2Scontamination. The proposed regulationstates that no operator may transport ina transmission line natural gascontaining more than 1 grain of H2S per100 SCF of natural gas (15.9 ppm of I2Sin natural gas). Therefore, if thetransmission pipeline is not receivinggas that has been subject to I-I2Scontamination, monitoring equipmentwould not be required.

The RSPA also agrees with thosecommenters who stated that theregulation of HS in gathering lines isimpractical as these pipelines aregenerally upstream of the gas processingfacilities which remove the gas.However, some of the gathering linesare currently subject to part 192regulations because the lines areoffshore or ure onshore gathering lineswithin the limits of any incorporated orunincorporated city, town, or village; orwithin a designated residential orcommerical area, such as a subdivision,business, or shopping center, orcommunity development. Persons insuch non-rural areas having gatheringlines with high concentrations of H2S

should also be afforded protectionagainst the possible release of HI2S.Similarly, personnel on offshoreplatforms that have gathering linesshould also be protected against thepossible release of H2 S.

Consequently, while RSPA isproposing that these gathering lines beexcepted from the limitation of H2S thatcan be transported in transmission lines,the RSPA is proposing that pipelineoperators develop a contingency plan incase of the release of H2S into theatmosphere for gathering lines whichtransport H2S in excess of 31 grains per100 SCF of natural gas (about 500 ppm)in nonrural areas and on offshoreplatforms. The proposed contingencyplan for onshore gathering lines is basedon the contingency plan requirements inRule 36 issued by the Texas RailroadCommission which requires differentcontingency plans at 100 ppm and 500ppm, as well as emergency planrequirements in part 192. It should benoted that a state may adopt more

stringent standards for gathering linesthat are compatible with the federalstandards. Therefore, the contingencyplan of the Texas Railroad Commissionand other state contingency plans wouldstill apply, if they are more stringent anddo not conflict with this proposedrequirement. The proposed contingencyplan for offshore gathering lines is basedon emergency plan requirements in part192 to the extent that such requirementsare applicable on offshore platforms.

Paperwork Reduction ActThe proposed information collection

requirement under § § 192.27 and 192.637(contingency plan) have been submittedto the Office of Management and Budgetfor approval under the PaperworkReduction Act of 1980 (44 U.S.C. chapter35). Persons desiring to comment onthese information collectionrequirements should submit theircomments to the Office of RegulatoryPolicy, Office of Management andBudget, 728 Jackson Place, NW.,Washington, DC 20503, attention: DeskOfficer, Research and Special ProgramsAdministration [RSPA]. Personssubmitting comments to OMB are alsorequested to submit a copy of theircomments to RSPA as indicated aboveunder ADDRESSES.

Impact AssessmentThe proposed rules tracks many of the

industry contractual requirementsregarding the presence of H2S in naturalgas in transmission pipelines. Thecommenters indicated that currentindustry contracts limit the H2S contentto 0.25 to 1.0 grains of H2S per 100 SCFof natural gas being provided totransmission operators from gasproducers. The proposed rule wouldpropose the upper limit of 1.0 grain ofH2S per 100 SCF of natural gas intransmission lines. Therefore, thisproposed rule would have minimaleconomic impact. Comments areparticularly solicited on this issue.

With regard to gathering lines in non-rural areas that carry significantamounts of H2S in natural gas, theproposed rules would use the TexasRailroad Commission's Rule 36 as amodel for developing a contingency planin case of an accidental release of sourgas into the atmosphere. The states ofTexas, Michigan, and California, whichInclude 40 percent of the gathering linesin the country, already have similarrequirements for all onshore gatheringlines in those states so that thedevlopment of contingency plan foronshore gathering lines would minimallyaffect pipeline operators in those states.Louisiana, which has about 28 percent ofthe gathering lines carrying natural gas

containing H2S in excess of.31 grains per100 SCF of natural gas, so such a rulewould have very limited impact ofLouisiana. This proposed requirementwould have an affect in the states ofOklahoma, New Mexico, Wyoming, andAlabama which have sour gas fields, butonly for gathering lines that have H2S inexcess of 31 grains per 100 SCF ofnatural gas in non-rural areas. Becausemany of the pipeline operators in thosestates also have pipeline systems inTexas, the costs of developing similarcontingency plans in those states wouldbe minimal. Comments are particularlysolicited on whether the development ofcontingency plans would have aminimal economic impact.

With regard to developingcontingency plans for offshore gatheringlines, the gathering lines off the coast ofCalifornia and Alabama would be themost affected. A contingency plan for anoffshore platform would be easy todevelop because the area affected iswell defined and only employeesworking on the platform would beaffected. In addition, a contingency planfor one offshore platform could beadapted to other offshore platforms withminimum revisions. Consequently, thecost of development of contingencyplans for offshore gathering lines wouldbe minimal.

The proposed rule would require thatthe release of H2S in excess of 20 grainsper 100 SCF of natural gas into atransmission line be telephonicallyreported to DOT. RSPA believes thatabout 5 reports per year, would bereceived annually. Again the costswould be minimal.

Therefore, the NPRM is considered tobe non-major under Executive Order12291, and is not considered significantunder DOT Regulatory Policies andProcedures (49 FR 11034; February 26,1979). Since the proposed rule wouldrequire minimal compliance expense, itdoes not warrant preparation of a DraftRegulatory Evaluation. Also, based onthe facts available concerning theimpact of this proposal, I certify undersection 605 of the Regulatory FlexibilityAct that it would not if adopted as final,have a significant economic impact on asubstantial number of small entities.This action has been analyzed under thecritieria of Executive Order 12612 (52 FR41685) and found not to warrantpreparation of a federalism Assessment.

List of Subjects

49 CFR Part 191

Incident, Hydrogen sulfide, pipelinesafety.

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49 CFR Part 192

Hydrogen sulfide, Pipe, Pipelinesafety.

In consideration of the foregoing,RSPA proposes to amend 49 CFR parts191 and 192 as follows:

Part 191-[AMENDED].

1. The authority citation for part 191continues to read as follows:

Authority: 49 App. U.S.C. 1681(b) and1808(b); § § 191.23 and 191.25 also issuedunder 49 App. U.S.C. 1672(a); and 49 CFR1.53.

2. The definition of "Incident" in§ 191.3 would be revised to read asfollows:

§ 191.3 Definitions.

Incident means any of the followingevents:

(1) An event that involves a release ofgas from a pipeline or of liquefiednatural gas or gas from an LNG facilityand

(i) A death, or personal injurynecessitating in-patient hospitalization;or

(ii) Estimated property damage,including costs of gas lost, of theoperator or others, or both, of $50,000 ormore.

(2) An event that results in anemergency shutdown of an LNG facility.

(3) An event where hydrogen sulfidein excess of 20 grains per 100 standardcubic feet of natural gas is released intoa transmission pipeline.

(4) An event that is significant, in thejudgment of the operator, even though itdid not meet the criteria of paragraphs(1), (2), or (3) of this definition.

3. Paragraph (b) in 1 191.5 would berevised to read as follows:

§ 191.5 Telephonic notice of certainIncidents.

(b)(1) Each notice required byparagraph (a) of this section shall bemade by telephone to 800-424-8802 (inWashington, DC, 202-366-26751 andshall include the following information.

(i) Names of operator and personmaking report and their telephonenumbers.

(ii) The location of the incident.(iii) The time of the incident.(iv) The number of fatalities and

personal injuries, if any.(v) All other significant facts that are

known by the operator that are relevantto the cause of the incident or extent ofthe damages.

(2) If the incident involves the releaseof hydrogen sulfide, each notice willinclude the following additional

information. (If all information is notavailable, the missing information willbe provided as soon as practicablethereafter).

(i) The amount of hydrogen sulfidethat enter the transmission line and howfar it spread.

(ii) The reason why the eventoccurred.

(iii) Corrective action taken.4. Paragraph (c) in § 191.15 would be

revised to read as follows:

§ 191.15 Transmission and gatheringsystems: Incident reporL

(c) The incident report required byparagraph (a) of this section need not besubmitted with respect to LNG facilitiesand an event set forth in paragraph (3)of the definition of "Incident" in § 191.3.

PART 192-[AMENDED]

1. The authority citation for part 192continues to read as follows:-

Authority- 49 App. U.S.C. 1672 and 1804; 49CFR 1.53.

2. A new § 192.631 would be added toSubpart L to read as follows:

§ 192.631 Hydrogen sulfide Intransmission pipelines.

Except as set forth in § 192.633, nooperator may transport in atransmission line downstream of gasprocessing plants, sulfur recoveryplants, or storage fields, natural gascontaining more than 1 grain ofhydrogen sulfide per 100 standard cubicfeet of natural gas.

3. A new J 192.633 would be added tosubpart L to read as follows:

§ 192.633 Contingency Plan for gatheringlines carrying hydrogen sulfide.

(a) A gathering line need not meet thetransmission pipeline requirements of§ 192.631, but if the line is carrying morethan 31 grains of hydrogen sulfide per100 standard cubic feet of natural gas,the operator must have a contingencyplan for the release of hydrogen sulfideinto the atmosphere for onshoregathering lines in accordance withparagraph (b) of this section and foroffshore gathering lines in accordancewith paragraph (c) of this section.

(b) A contingency plan for onshoregathering lines must be written, and, at aminimum, must provide for thefollowing:

(1) Applying the contingency plan to aradius of exposure of 500 ppm inaccordance with the formula:X= [{0.4546) (12S concentration) (QI] 0,258

where:

X=radius of exposure in feetQ=nmaximum volume of gas determined to

be available for escape from thegathering line in cubic feet per day atstandard conditions of 14.65 psig and60"F

H2S concentration= decimalequivalent of the mole or volumefractions (percent) of hydrogen sulfide inthe gaseous mixture

(2) A plat detailing the area ofexposure which must include locationsand name and telephone number ofresponsible persons of schools,churches, hospitals, businesses or othersimilar areas where the public mightreasonably be expected.

(3) Coordinating with appropriatepublic officials in preparation of anemergency plan, which sets forth thesteps required to protect the public inthe event of an emergency.

(4) Establishing and maintainingadequate means of communication withappropriate fire, police, and other publicofficials.

(5) The availability of personnel,equipment, tools, and materials, asneeded at the scene of an emergency.

(6) Provide for notification of thepublic of the hazardous andcharacteristics of hydrogen sulfide, thesources of hydrogen sulfide within thearea of exposure, instructions forreporting a gas leak and steps to betaken in case of an emergency.

(7) Placing and maintaining a linemarket as close as practical over thepipeline at each crossing of a publicroad and railroad and wherevernecessary to identify the location of thepipeline to reduce the possibility ofdamage or interference, with letters atleast one inch high with one-quarterinch stroke on a background of sharplycontrasting colors, containing the nameand telephone number of the operatorand the words "Caution" and "PoisonGas."

(c) A contingency plan for offshoregathering lines must be written, and, at aminimum, must provide for thefollowing:

(1) Applying the contingency plan toeach platform located offshore.

(2) Coordinating with appropriatepublic officials in preparation of anemergency plan, which sets forth thesteps required to protect the personnelin the event of an emergency.

(3) Establishing and maintainingadequate means of communication withappropriate fire, police, Coast Guard,and other public officials.

(4) The availability of equipment, gasmasks, tools, and materials as needed atthe scene of an accident.

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(5] Provide for notification of thepersonnel of the hazardouscharacteristics of hydrogen sulfide andsteps to be taken in case of anemergency.

Issued in Washington, DC on March 13,1991.George W. Tenley, Jr.,Associate Administrator for Pipeline Safety[FR Doc. 91--6381 Filed 3-15-91; 8:45 am]BILUNG CODE 4910-40-U