[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]
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DEPARTMENT OF TRANSPORTATION
Research and Special Programs Administration
49 CFR Parts 191 and 192
[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).
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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Therefore, the NPRM is withdrawn.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.
SUPPLEMENTARY INFORMATION:
Background
H2S 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.
NTSB Recommendations
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)
The 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,
[[Page 9134]]
or 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 shutoff 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.
The Notice of Proposed Rulemaking
On 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'').
Several 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
[[Page 9135]]
similar 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, INGAA 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 ppm). 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 proposed 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
[[Page 9136]]
offshore pipelines and Part 192 does not outline differences that are
to exist between them.
Technical Pipeline Safety Standards Committee
RSPA 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
pipelines.
Authority: 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
