Transportation of Hydrogen Sulfide by Pipeline

Passage 1[Federal Register Volume 61, Number 46 (Thursday, March 7, 1996)] [Proposed Rules] [Pages 9133-9136] From the Federal Register Online via the Government Publishing Office [www.gpo.gov] [FR Doc No: 96-5374] ======================================================================= ----------------------------------------------------------------------- Research and Special Programs Administration [Docket No. PS-106; Notice 3] RIN 2137-AB63 Transportation of Hydrogen Sulfide by Pipeline AGENCY: Research and Special Programs Administration (RSPA). ACTION: Withdrawal of notice of proposed rulemaking (NPRM). ----------------------------------------------------------------------- SUMMARY: In response to three National Transportation Safety Board (NTSB) Safety Recommendations, RSPA issued an Advance Notice of Proposed Rulemaking (ANPRM) followed by a Notice of Proposed Rulemaking (NPRM) that proposed changes in the Pipeline Safety Regulations to address the hazard of excessive levels of hydrogen sulfide (H2S) in natural gas transmission pipelines. In a final review of information and comment from all sources, including advice from the Technical Pipeline Safety Standards Committee (TPSSC), RSPA determined that a regulation to address H2S in transmission lines is not warranted. Therefore, the NPRM is withdrawn. FOR FURTHER INFORMATION CONTACT: Mike Israni, (202) 366-4571, regarding the subject matter of this notice, or the Dockets Unit, (202) 366-4453, regarding copies of this notice or other material in the docket as referenced above.#

Passage 2H2S is a colorless and flammable gas which is hazardous to life and health at concentrations above 300 parts per million (ppm) . At concentrations of 1000 ppm in air it can cause immediate unconsciousness and death. The Occupational Safety and Health Administration has established an upper concentration level of 10 ppm for prolonged (8 hours) workplace exposure. The current regulations in 49 CFR Parts 192 and 195 address H2S only with respect to its corrosive effect on pipelines, as follows: Sec. 192.125(d) states that copper pipe that does not have an internal corrosion resistant lining may not be used to carry gas that has an average H2S content of over 0.3 grains per 100 standard cubic feet (SCF) of gas. Sec. 192.475 states that corrosive gas may not be transported by pipeline unless the corrosive effect of the gas on the pipeline has been investigated and steps have been taken to minimize internal corrosion. In addition, gas containing more than 0.1 grains of H2S per 100 SCF may not be stored in pipe-type or bottle-type holders. Sec. 195.418 states that no operator may transport any hazardous liquid that would corrode the pipe or other pipeline components unless it has investigated the corrosive effect of the hazardous liquid on the system and taken adequate steps to mitigate corrosion. As a result of the NTSB investigation of an August 1987 accidental release of H2S into a gas supply to Lone Star Gas Company in Texas, and after learning of 11 additional H2S releases since 1977 (none of which involved any fatalities or serious injuries), NTSB issued three Safety Recommendations to RSPA (P-88-1, -2 and -3) which called for (-1) establishing a maximum allowable concentration of H2S in natural gas pipeline systems, (-2) requiring operators to report all incidents in which concentrations of H2S exceed this maximum, and (-3) requiring operators to install equipment to automatically detect and shut off the flow of gas when H2S concentrations exceed the maximum. Advance Notice of Proposed Rulemaking (ANPRM)#

Passage 3The RSPA responded to the NTSB recommendations by issuing an ANPRM on June 7,1989 (54 FR 24361). Because the Pipeline Safety Regulations do not require any monitoring of H2S levels in natural gas pipeline systems, the ANPRM included a request for information to be used in assessing the need for any such regulations. The ANPRM provided background information and discussion on gas wells having significant concentrations of H2S (sour gas), on the toxicity of H2S, and on the effects of H2S with regard to sulfide stress and stress corrosion cracking of line pipe. It discussed two H2S incidents in California (1983 and 1984) and one in Texas (1987) that were reported by NTSB, and mentioned some instances where workers were overcome by H2S at a sour gas field in Canada. It quoted the aforementioned three NTSB Safety Recommendations (P-88-1, -2 and -3), summarized the aforementioned Federal Regulations (49 CFR 192.125, 192.475 and 195.418), discussed state regulations on H2S (California General Order 58; Michigan Rules 299, 460 and 81; and Texas Rule 36), and mentioned seven sections in Canadian Standard Z184-1975 that deal with sour gas. For additional information on the above items refer to the ANPRM which is available in the docket. In its request for information, the ANPRM included four questions as follows: Question 1. What factors should be considered in determining the need for a maximum allowable concentration of H2S in natural gas pipeline systems? What should this concentration be? Question 2. Describe events you know of in which H2S has been released from,#

Passage 4or into, a pipeline in dangerous amounts and what were the H2S concentrations? What were the consequences of such releases? What would be the burden associated with mandatory reporting of such events? Question 3. If you are an operator receiving gas from a producer, do you have automatic H2S detection and shut-off equipment? Do these devices work reliably? For such operators that do not have this equipment, what costs and other burdens can be associated with requiring use of the equipment? Question 4. Which pipelines transporting sour gas should be subject to an H2S monitoring requirement? Should rural gas gathering lines be subject to H2S monitoring requirements, even though they are not now subject to any of the part 192 safety standards? RSPA received 54 responses to the ANPRM, mostly from natural gas and hazardous liquid operators. Question 1 produced a wide variety of suggestions for assessing the need for a maximum level of H2S. In addition, most commenters suggested a maximum allowable H2S concentration in the range of 0.25 to 1.0 grains per 100 SCF of natural gas. The suggested factors for assessing the need for a maximum allowable H2S level included such things as the kind of pipeline system (gathering, transmission or distribution); operating conditions (pressure, temperature, rate of flow); presence of contaminants (H2O, CO2, hydrocarbon liquids, inhibitors); time interval of H2S intrusion; piping materials; piping age; gas destination; weather conditions; and provisions for ``grandfathering.'' With regard to a maximum allowable H2S level, RSPA felt that an upper limit of 1 grain per 100 SCF of natural gas would be appropriate because it is consistent with the limit set by OSHA and several states. With regard to question 2, the commenters indicated that H2S releases have not been widespread, significant, or a recurring problem. On the matter of burden associated with mandatory reporting, most distribution operators, as well as many transmission operators, indicated little burden, but they questioned the usefulness of a reporting requirement. However, in spite of this train of comment, RSPA was of the opinion that a release of an excessive amount of H2S into a pipeline system could result in a hazardous situation if there is gas leakage from the piping. Response to question 3 from most operators was that H2S detection equipment and allied gas shuto#

Passage 5ff equipment is generally reliable, with per installation equipment cost in the $10,000 to $30,000 range. Monthly operating cost for the most part was $1500, with one operator reporting $3000. A large midwestern distribution operator reported that it would cost $484,000 for equipment for its entire system with an annual operating cost of $105,000. RSPA felt that, to ensure public safety, high concentrations of H2S should be removed from the gas before delivery to the transmission pipeline. On question 4 most commenters favored a location immediately downstream of where the gas is treated for H2S removal as the place for monitoring. Very few commenters thought that pipelines carrying sour gas should not be monitored. Most commenters were opposed to rural gathering lines being subject to H2S monitoring. RSPA agreed with most commenters that monitoring should be in the interface between the gathering line and transmission line at a point immediately downstream of the H2S removal facility. RSPA also agreed that there is no need for monitoring equipment where transmission pipelines are not receiving gas that could be subject to H2S contamination. In addition, RSPA agreed with the commenters who stated that regulation of H2S in gathering lines is impractical because those pipelines are generally upstream of H2S removal facilities.#

Passage 6On the basis of its review and analysis of the information and comments received from the ANPRM, RSPA published an NPRM on March 18, 1991 (56 FR 11490) proposing rule changes in parts 191 and 192. The proposed changes were to (1) limit H2S levels in transmission lines downstream of gas processing plants, sulfur recovery plants, and storage fields to 1 grain per 100 SCF of natural gas; (2) require reporting to RSPA if an excessive amount of H2S enters a transmission line; and (3) require that operators of jurisdictional onshore and offshore gas gathering lines containing over 31 grains of H2S per 100 SCF of natural gas have written contingency plans for any release of H2S into the atmosphere. For detail on the changes in the regulations, refer to the NPRM which is available in the docket. RSPA received 30 responses to the NPRM; 23 from gas and hazardous liquid pipeline operators, three from pipeline industry associations (American Gas Association, Interstate Natural Gas Association, and American Petroleum Institute), two from Federal government agencies (NTSB and Minerals Management Service), one from a state pipeline safety agency. (Kansas Corporation Commission), and one from a local government (County of Santa Barbara). The following summarizes the responses: General Comments--Several commenters, particularly distribution system operators, supported limits on the amount of H2S allowable in natural gas transmission pipelines. The distribution operators were concerned about the regulations requiring the installation of H2S monitoring equipment in their systems. NTSB commented that the term ``grains per 100 SCF of natural gas'' should be replaced with ``parts per million'' (ppm). NTSB also suggested that RSPA provide the scientific basis for the H2S limits used in these regulations. Many commenters were concerned that a pending RSPA rulemaking for redefining gas gathering lines would result in some lines being reclassified as transmission lines, and the resulting affects of this on any such lines that transport high concentration H2S natural gas. The API was concerned about the definition of ``gathering lines'' and ``production facilities'', and urged that RSPA adopt the API proposed definitions of these terms (these proposed API definitions are being taken into consideration by RSPA in the development of the rulemaking for redefining ``gathering line''). Sev#

Passage 7eral commenters, especially Monterrey Pipeline Company, were concerned about RSPA proposing regulations in spite of comments that argued against the need for regulations for establishing a maximum H2S level for natural gas in transmission pipelines. In contrast, many commenters, such as Tenneco, felt that RSPA, in developing the proposed regulations, had adequately balanced considerations of public safety with the need for prudent operation of pipeline systems. The Resources Management Department of the County of Santa Barbara commended the effort by the RSPA to address the hazards of sour gas in natural gas. Santa Barbara recommended three levels of protection (operational procedures, H2S detectors, and mechanical means) with standby/duplication at each level. Section 191.3--Several commenters noted that the NPRM definition of an event involving the presence of H2S, as proposed in the Sec. 191.3 definition of an H2S ``Incident,'' should be limited to ``transmission pipelines downstream of gas processing plants, sulfur recovery plants, or storage fields,'' wording#

Passage 8similar to the NPRM proposed Sec. 192.631. Many commenters took the position that there is no need to expand the definition of ``incident'' in Sec. 191.3 by adding an H2S ``incident'' because people are not exposed to the H2S that may be introduced into a pipeline downstream of a gas processing plant, sulfur recovery plant, or storage field. The proposed addition to the definition of ``incident'' read ``An event where hydrogen sulfide in excess of 20 grains per 100 standard cubic feet of natural gas is released into a transmission pipeline''. Interstate Natural Gas Association of America (INGAA) and Enron commented that this wording should be revised to make it clear that it is natural gas, containing a certain concentration of H2S, that enters a transmission pipeline to create the reportable incident. United Gas Pipe Line Company (UGPL) commented that there was nothing to quantify the extent of a release with respect to time. According to UGPL, the small quantity of gas entering a transmission pipeline during the 30 to 60 seconds required to activate shutoff would constitute a reportable incident, even though it would be quickly diluted by the large volume of sweet gas in the pipeline from other sources, and therefore pose no hazard. On the other hand, the Minerals Management Service (MMS) commented that a minimum level of 20 grains per 100 SCF of natural gas (320 ppm) may be too high because at that level the pipe would be subject to sulfide stress cracking. In addition, MMS made reference to the high toxicity level at 20 grains of H2S per 100 SCF (320 ppm) with the following description of toxicity at 200 ppm from API RP 49, Table A.1: ``Burns eyes and throat. At concentration between 200-500 ppm pulmonary edema which can be life threatening almost always occurs.'' The proposed addition to the definition of ``incident'' in Sec. 191.3 included any release (into a transmission pipeline) of natural gas containing in excess of 20 grains of H2S per 100 SCF (320 ppm) a reportable incident. RSPA agreed that because of the dilution mentioned previously, and because the gas would be contained inside the piping (as indicated by many commenters), a hazardous situation would be unlikely. Section 191.5--INGAA, Ocean Drilling and Exploration Co. (ODECO), UGPL, and Colorado Interstate Gas (CIG) opposed the use of the telephonic notice for reporting H2S incidents. CIG, I#

Passage 9NGAA and UGPL suggested using the Sec. 191.25 Safety-Related Condition Report, and ODECO favored a written report similar to that of Sec. 191.9. INGAA and UGPL recommended that the reported information should address the concentration instead of the amount of H2S, and the length of time of the release. They also said that determining how far the H2S had spread could be difficult. Section 192.631--Many commenters indicated that the proposed Sec. 192.631, if taken literally, could require transmission pipelines that are not immediately downstream of a gas processing plant, sulfur recovery plant, or storage field, to be monitored for the presence of H2S. Many transmission pipelines, especially those belonging to gas distribution operators, are many miles downstream of the point (gas processing plant, sulfur recovery plant or storage field) where sour gas could be inadvertently released into the pipeline and there is therefore no need for H2S monitoring. Alabama Gas Corporation commented that the rule should be rephrased so that monitoring is not required where there is no possibility of an H2S release. Several commenters pointed out that the introductory phrase ``Except as set forth in Sec. 192.633,'' should be deleted in proposed Sec. 192.631 because there is no exception in Sec. 192.633 for transmission pipelines. This introductory phrase was included in this proposed rule because, in accordance with the current requirements in Sec. 192.9, gathering lines must comply with rules that are applicable to transmission pipelines. The introductory phrase was intended to except gathering lines from having to comply with Sec. 192.631 so they may carry sour gas by complying with Sec. 192.633. Okaloosa County Gas District recommended that OSHA standards on H2S be implemented by limiting H2S to 0.625 grains per 100 SCF of natural gas. Transcontinental Gas Pipe Line Corporation (Transco) commented that the proposed limit of 1 grain of H2S per 100 SCF of natural gas could conflict with existing gas purchase contract limits and proposed ``grandfathering'' the conditions in existing gas purchase contracts that do not exceed 2 grains of H2S per 100 SCF of natural gas. The NTSB suggested that the maximum permissible concentration of H2S should be 10 ppm (0.625 grains per 100 SCF of natural gas), as established by OSHA, instead of 1 grain of H2S per 100 SCF of natural gas (16 p#

Passage 10pm). The MMS commented that 15.9 ppm (1 grain per 1000 SCF) is very conservative and appropriate for transmission pipelines, and pointed out that 1 grain of H2S per 100 SCF of natural gas (16 ppm), as specified in Sec. 192.631, is the short term exposure limit established by OSHA as the `` * * * employee's 15-minute time weighted average which shall not be exceeded at any time during a work day * * * '' (54 FR 2920). Section 192.633--Several commenters supported the use of the Texas Railroad Commission Rule 36 in developing regulations for gathering lines that carry high concentrations of H2S. Pennzoil was concerned that the regulations proposed in Sec. 192.633 may be misinterpreted to apply to gathering lines in rural areas. As noted in the NPRM, these regulations do not apply to gathering lines in rural areas. In accordance with the applicability regulations in Sec. 192.1(2), Part 192 does not apply to the onshore gathering of gas outside one of the following areas: (i) An area within the limits of any incorporated or unincorporated city, town, or village. (ii) Any designated residential or commercial area such as a subdivision, business or shopping center, or community development. It should be noted that Sec. 192.633 applies to offshore gathering lines since Sec. 192.1(2) only excepts onshore gathering lines from the requirements of Part 192. Lone Star Gas Company (LSG) commented that Rule 36 was intended to apply to production wells producing natural gas having high concentrations of H2S; i.e., a single point source of possible H2S release. LSG commented that applying the formula in proposed Sec. 192.633(b)(1) to pipelines needed some clarification, particularly regarding the term ``maximum volume of gas available for escape.'' LSG also commented that Sec. 192.633(b)(2) should be clarified since Rule 36 requires a plat detailing the area around a production well which again is a point source of possible escape of natural gas carrying high concentrations of H2S. LSG argues that a pipeline subject to Sec. 192.633(b)(2) is not a point source. Both LSG and Enron suggested that contingency plans proposed in Sec. 192.633 be incorporated into Sec. 192.615 since such plans for hydrogen sulfide emergencies would probably be incorporated into emergency plans currently existing under Sec. 192.615. Both commenters observed that many of the requirements in the propo#

Passage 11sed Sec. 192.633 were taken from Sec. 192.615 and no purpose is served by requiring that the information be repeated. Enron commented that there is no reason to differentiate between contingency plans for onshore as opposed to offshore pipelines. According to Enron, current emergency plans exist for onshore and offshore pipelines and Part 192 does not outline differences that are to exist between them. Technical Pipeline Safety Standards Committee#

Passage 12RSPA presented the NPRM to the TPSSC for its consideration at a meeting in Washington, DC on March 11, 1992. The TPSSC is RSPA's statutory advisory committee for gas pipeline safety. It is composed of 15 members, representing industry, government, and the public, who are technically qualified to evaluate gas pipeline safety. The TPSSC expressed concerns about adopting the proposed changes in 49 CFR Part 192 to address H2S in natural gas transmission pipelines. The TPSSC 's concerns centered around the need for such a regulation considering the limited number of incidents involving the release of H2S natural gas into transmission pipelines, and whether it would increase safety, be cost effective and redundant to already existing state regulations. Therefore, the TPSSC recommended that the incidence of H2S in transmission lines did not warrant a rulemaking. On the basis of that finding, an analysis and review of the comments to the NPRM, and further analysis of the comments to the ANPRM, RSPA decided to re-consider the need for the proposed regulation and concluded that the proposed H2S regulations are not warranted because they are oriented/directed toward transmission lines. No injuries or deaths have been attributed to H2S in natural gas transmission lines. H2S releases into transmission lines to date have been infrequent, have been of extremely brief duration, and have involved only very minute amounts of H2S. H2S that is released into a transmission line remains confined with very little likelihood that there would happen to be a leak in the transmission line at the same time and in the same general vicinity as the release. And lastly, H2S released into a transmission line from a processing plant would most likely be diluted by natural gas from other sources. Rather than applying rule changes affecting transmission pipelines, RSPA's regulatory efforts on H2S should be redirected to gathering lines. The source of H2S is the gas well, and the gathering line is the first pipeline facility downstream of the well. It is on gathering lines transporting H2S laden natural gas from wells to processing plants that regulations may be needed. Future development with respect to H2S in gathering lines may be addressed in a later rulemaking. On the basis of the foregoing, RSPA hereby withdraws the NPRM proposing to limit H2S levels in natural gas in gas transmission pip#

Passage 13Authority: 49 U.S.C. 60102 et seq.; 49 CFR 1.53. Issued in Washington, D.C. on March 4, 1996. Richard B Felder, Associate Administrator for Pipeline Safety. [FR Doc. 96-5374 Filed 3-6-96; 8:45 am] BILLING CODE 4910-60-P#