16 TAC §3.95, §3.97
The Railroad Commission of Texas adopts amendments to §3.95,
relating to Underground Storage of Liquid or Liquefied Hydrocarbons in Salt
Formations, and §3.97, relating to Underground Storage of Gas in Salt
Formations, with changes to the versions published in the July 21, 2006, issue
of the
Texas Register
(31 TexReg 5723). The
Commission adopts the amendments consistent with the Commission's wish to
further the goals of safety and the prevention and control of pollution.
The Commission also adopts these amendments in order to reduce the possibility
of explosion and fire at such facilities and enhance the safety of such facilities
in light of the gas release and fire at the Moss Bluff Hub Partners, LP natural
gas storage facility and incidents at several liquid hydrocarbon storage facilities.
After considering the findings of the investigation of these incidents, the
Commission determined that new safety requirements were necessary and, on
December 7, 2004, directed staff to initiate rulemaking to establish such
requirements. In January 2005, staff sent a questionnaire to all operators
of underground hydrocarbon storage facilities to gather additional information
concerning the current status of construction, maintenance, operations, and
record keeping. In addition, in May 2005, staff held a workshop to review
operator responses from the questionnaire and to gather input from affected
operators to evaluate the advisability, cost, and effectiveness of potential
new safety regulations. The Commission also published on its website a draft
of the proposed amendments for informal comment. Staff used the input from
these forums to draft the original proposed amendments and incorporate new
requirements for integrity management of surface piping, location of emergency
shutdown valves, fire suppression capabilities, data acquisition, and record
retention.
On February 24, 2006, the Commission published the original proposed amendments
to §3.95 and §3.97 (Statewide Rules 95 and 97) in the
Texas Register
for a 30-day comment period. Two associations and seven
companies submitted comments. Because the Commission incorporated substantive
changes as a result of the comments, it withdrew the proposed amendments published
on February 24, 2006, and published new proposed amendments on July 21, 2006
(31 TexReg 3157) for a second 30-day comment period.
The Commission received comments from two associations (Texas Oil and Gas
Association and Texas Pipeline Association) and five companies (Atmos Pipeline-Texas;
ConocoPhillips; Dow Chemical Company; and Kinder Morgan Pipeline and Kinder
Morgan Tejas Pipeline, L.P., filing jointly).
Kinder Morgan, Atmos, Conoco Phillips, and TxOGA all commended the efforts
of the Commission staff to evaluate the comments to previous versions of the
proposed amendments and to revise the proposed rules accordingly. TxOGA also
commended the Commission for recognizing that possibilities other than the
defined acceptable standards exist for achieving a level of safety that equals
or exceeds the requirements, including the option to petition for exceptions,
will allow alternative solutions to piping configuration and other design
features based on site-specific conditions. The Commission appreciates these
comments.
Discussion of Changes Made Upon Adoption
One commenter requested that the Commission revise the proposed wording
"Either within three years of the effective date of this section, or in conjunction
with the next scheduled integrity test of the storage well, . . . ." in §3.95(h)(2)(B)
to clarify whether the intent is to allow the operator three years to select
the best time to install required emergency shutdown valves or whether the
intent is to force the operator to install the required emergency shutdown
valves in conjunction with the next mechanical integrity test if that test
is less than three years away.
The Commission agrees that the proposed wording is confusing. As originally
proposed, the language would have allowed an operator to delay compliance
for at least three years or up to the date the next mechanical integrity test
would have been scheduled after the three-year clock expires, for a maximum
of five years. For example, if a permitted well is tested on the effective
date of the rule, the operator would have had either three years to install
the emergency shutdown valves or could have waited until the next mechanical
integrity test for a maximum of five years. To eliminate the confusion, however,
the Commission has revised the language to require that the emergency shutdown
valves be in place within five years of the effective date of the rule. The
Commission fully anticipates that many operators will install the emergency
shutdown valves in conjunction with mechanical integrity testing.
One commenter noted that §3.95(h)(2)(B) states that emergency shutdown
valves must be installed "between the storage wellhead and the product and
brine surface piping . . . " and requested that the Commission clarify the
classification of the piping between the two emergency shutdown valves in
situations where the operator elects to install secondary emergency shutdown
valves.
The Commission makes no change to the rule wording, but notes that a secondary
emergency shutdown valve may be installed to allow an operator to maintain
surface piping that is not rated for maximum wellhead operating pressure.
All surface piping downstream of the wellhead and primary emergency shutdown
valves must be rated for maximum wellhead pressure unless there is a secondary
automated, fail-closed, pressure control valve separating the under-rated
surface piping from piping connected to the primary emergency shutdown valve.
One commenter recommended that the Commission add language in §3.95(h)(2)
to allow the Commission to authorize the removal of the emergency shutdown
valves and suspend the testing program during brine mining when no hydrocarbons
are being stored in the caverns until the caverns are in the process of being
put back into hydrocarbon storage service. This commenter recommended that
the Commission add as §3.95(h)(2)(E) the following language: "Upon prior
approval of the Commission, the requirements of this paragraph do not apply
during the time the well is not actively storing hydrocarbons."
The Commission disagrees with this comment. The current wording in §3.95(h)
specifically exempts from the safety requirements of subsection (h) "any hydrocarbon
storage well that is out of service and disconnected from all surface piping,"
which in this case is interpreted to mean "product" surface piping. There
should be no product in storage except for that required to maintain a roof
blanket. The Commission has made no change in response to this comment.
One commenter found confusing the language in §3.95(h)(3)(A) and concerning
surface piping and recommended that the Commission either clarify the language
or provide guidance to clarify the jurisdiction of the Oil and Gas Division
and of the Safety Division at these facilities.
The Commission declines to make any changes in response to this comment.
In §3.95(h)(3)(A), the Commission is clarifying the term "product surface
piping." Because the pipeline safety rules do not apply to process piping
and flowlines, the Commission has clarified that the product surface piping
from the wellhead to the first pressure regulation device must be designed
to withstand the permitted maximum operating pressure.
One commenter requested clarification in §3.95(h)(3)(C)(ii) as to
whether or not an emergency shutdown valve is required on the fresh water
line if an operator elects to install a secondary emergency shutdown valve
on the brine surface piping and the fresh water line is connected between
the two emergency shutdown valves.
The Commission finds that the wording in the rule is clear that all piping
from the wellhead to the second emergency shutdown valve must be rated for
the maximum allowable wellhead pressure.
Several commenters requested that the Commission revise the language in §3.95(h)(7)
concerning fire suppression capability to provide additional instruction to
allow an operator to determine whether or not the operator's design is in
compliance. These commenters recommended that the Commission develop design
standards that can be used by operators and Commission inspectors to determine
sufficiency prior to the occurrence of an incident. The commenters requested
that the Commission clarify the rule with respect to the length of time that
fire suppression equipment should be able to provide the temporary protection
for workers, the length of time the fire suppression equipment should be able
to cool the wellhead equipment. In the alternative, the commenters recommended
that the Commission require operators to submit to the Commission their fire
suppression plans within one year of the effective date of the rule amendments
and to have the system operational within two years of the Commission's approval
of such plan to allow some flexibility because each facilities' access to
water and proximity to the public may vary, and there may be other circumstances
unique to each location.
The Commission agrees in part with these commenters. Fire suppression capability
need only be sufficient to keep the wellhead equipment cool enough to prevent
further failure and to protect storage personnel long enough to safely evacuate
the area. The Commission provided a fairly lengthy period of time (three
years) for the operator to take into consideration the particulars of each
of their facilities. The Commission's intent was that after carefully designing
its plan, the operator would be able to ascertain compliance with the performance
standard in the rule during annual drills designed to test the operator's
emergency response plan required in paragraph §3.95(h)(8). Nevertheless,
the Commission acknowledges the commenters' concern that the Commission review
the plans before that time to provide some additional assurance that the proposal
complies. Therefore, to clarify its intent, the Commission has added "fire
suppression capability" to the list of items that the emergency response plans
must address, and that the Commission will review and test during drills.
Two commenters recommended that the Commission revise §3.95(h)(7)(C)
to exempt from the fire suppression requirements storage wells located at
large distances from other wells or control facilities.
The Commission declines to make the suggested change because distance is
not the only factor the Commission considered in determining the necessity
of the fire suppression requirements. An operator may request an exemption
under §3.95(h)(7)(C). A great distance between storage wells and control
facilities would be taken into account as a mitigating factor in considering
whether to grant such a request; however, the Commission would also consider
other factors, including worker safety, in determining whether or not to grant
an exemption.
Two commenters recommended that the Commission revise the good cause extension
provided in §3.95(h)(9)(b) to provide for up to 60 days for completion
of the root cause report to provide additional flexibility to address the
analysis necessary in complex situations and allow a more comprehensive report.
One commenter requested that the Commission consider accepting a preliminary
report on the root cause to be followed by a final report after the well has
been investigated.
The Commission agrees that 30 or even 60 days may not be a sufficient amount
of time to adequately determine the root cause of an incident, particularly
a major incident. Therefore, the adopted rule contains a provision for Commission
approval of a reasonable additional amount of time for good cause.
One commenter recommended that the Commission limit the amount of information
required by §3.95(n)(1) by replacing the term "all" with a clear statement
that data recorded at least once per minute is sufficient.
The Commission agrees and has revised both the language and the structure
of subsection (n)(1). Paragraph (1) has been divided into subparagraphs (A)
and (B). Subparagraph (A) specifies the minimum frequency for recording of
electronic data. The Commission has clarified that the hydrocarbon storage
well pressures, flow rates, and hydrocarbon volumes injected into and withdrawn
from each well and the hydrocarbon inventory of each cavern must be recorded
at a frequency of at least once per minute and retained for a period of at
least three months. In new subparagraph (B), the Commission has clarified
that the maximum monthly wellhead pressures on the hydrocarbon and brine sides
of each well and the monthly net volumes of hydrocarbons injected to and withdrawn
from each storage well must be recorded at a frequency of at least once per
day and retained for a period of at least five years.
One commenter recommended that the Commission allow flexibility in the
requirement to inspect and test the storage wellhead under §3.95(o)(3).
The commenter recommended that the Commission modify the language in subsection
(o)(5) in both rules as follows: "(5) Alternative
testing
and monitoring. An operator may request the Commission or its
designee to approve
an alternate means of testing
the integrity of the storage wellhead. Approval may also be requested to
allow
storage well pressure monitoring as an alternative to integrity testing for
hydrocarbon storage wells that are out of storage service." An out-of-service
storage well must be tested for integrity according to the procedures specified
in subsection (o)(2) of this subsection before it may be returned to storage
service.
The Commission declines to make the recommended change. The subsection
already includes language that provides flexibility by allowing an operator
to request Commission approval for storage well pressure monitoring as an
alternative to integrity testing of storage wells that are out of storage
service. The Commission finds that such an option is not appropriate for storage
wells that are in active service.
Several commenters requested that the Commission reconsider implementing
the proposed wellhead testing requirement in §3.97(o)(3), which includes
a requirement to pressure test storage wellhead components to 125% of the
maximum operation pressure at least once every 15 years. These commenters
noted that, while the testing requirement was previously included in informally
circulated draft proposed amendments for salt dome storage for liquid hydrocarbons
(§3.95), it had not been included in any of the earlier informally circulated
draft proposed amendments for natural gas salt dome storage facilities. The
current rule provides for the testing of the wellhead in conjunction with
the mechanical integrity test, which is required every five years to 100%
of the maximum allowable operating pressure of the storage cavern. The commenters
stated that, in order to comply with the testing requirement, natural gas
storage cavern operators must select one of two possible methods, both of
which are extremely burdensome and potentially dangerous. In the first method,
because the pressure in the cavern cannot be brought up to 125% of the maximum
working pressure using natural gas without exceeding permit and Commission
rules, the cavern would have to be isolated from the wellhead.
The Commission agrees in part with these comments. The Commission proposed
in §§3.95 and 3.97 a test pressure of 125% of the maximum operating
pressure to be consistent with the general testing requirements for pipelines
under the pipeline safety regulations understanding that it would require
isolating the wellhead from the cavern. However, the Commission agrees that
there may be methods other than such a pressure test that may be more appropriate
in assessing the integrity of all storage well components and has changed
the test pressure requirement. The new language in adopted §3.95(o)(1)
and §3.97(o)(1) requires that each storage well be tested for integrity
a minimum of once every five years; therefore, the Commission has deleted
the language in §3.95(o)(3) and §3.97(o)(3) regarding pressure testing
to 125 percent of the permitted maximum allowable pressure and has clarified
that each storage wellhead and cemented casing must be inspected for corrosion,
cracks, deformations, or other conditions that may compromise integrity (and
that may not be detected from the 5-year test) at least once every 10 years
under §3.95 and at least once every 15 years under §3.97. This change
provides the time and opportunity for an operator to propose alternative,
and less costly, means of confirming storage well component integrity.
The Commission received no comments on the 10-year inspection requirement
under §3.95. Two commenters recommended that the Commission carefully
consider the benefits to be gained by the new gas storage integrity inspection
requirement. These commenters provided a conservative estimate of approximately
$2 million for the average facility, not including the impact of increased
commodity costs as a result of having to refill the caverns or the lack of
storage capacity. These commenters stated that, while the amendments only
require testing once every 15 years, testing will most likely interrupt normal
operation and use of a storage facility for up to a year. In addition, because
several facilities are used to provide support for service to human needs
customers in large metropolitan areas, removal of the facilities from service
during testing could prevent the operator from honoring commitments to provide
support to meet the demands of human needs customers during the winter.
The commenters stated that in most cases an operator must remove hanging
pipe strings from the wellbore while maintaining normal storage pressure on
the wellhead. Mechanical plugs are set in the cemented production casing to
isolate the cavern from the wellhead in order to allow the wellhead to be
tested at the proposed pressure while preventing overpressure of the cavern
casing seat. The commenters stated that, in addition to the cost, there is
a risk of well blowout during this process, which is exactly what the rule
is seeking to eliminate. In other cases, the operator would have to remove
the storage facility from active service for an extended period of time to
empty the caverns of gas, fill the cavern with brine, empty the cavern of
brine, test the cavern, and then refill the cavern with gas. This method assumes
that sufficient quantities of brine and water are available and that brine
dispose capacity is available. This method of preparing the cavern for testing
is more expensive than snubbing since a hanging string may need to be extended
below the brine interface in the cavern to allow fluid injection.
The Commission is aware of the possible difficulty, risk and cost that
could result from the testing requirement, particularly if isolation of the
casing from the wellhead is required, and has clarified and revised this requirement
in both §3.95(o)(3) and §3.97(o)(3) in response to comments. The
Commission anticipates that operators will devise less costly alternatives
that accomplish the intended purpose. Under the current rules, operators always
have been required to maintain the integrity of the wellhead, cavern, and
ancillary equipment at any storage facility subject to these rules. Because
of past incidents and because the current rules do not include a minimum inspection
frequency, the Commission adopts a reasonable and prudent 15-year inspection
cycle to ensure wellhead and casing integrity, assuring that every component
of liquid and gas storage systems will be subject to periodic examination.
The Commission also notes that the potential cost in human lives and the
cost of inventory loss and cleanup from only one catastrophic incident would
dwarf the new inspection costs.
The commenters urged the Commission to investigate alternative means of
determining the integrity of the wellhead-related components before adopting
the amendments in §3.95(o)(3) and §3.97(o)(3). Testing of all wellhead
related components other than the actual wellhead might provide an adequate
safety check on components that have been shown to have previously failed
without impacting those that have not been shown to fail in the past. These
commenters stated that wellheads built to API 6a specifications are believed
to be robust and adequate for prevention of wellhead failure. These commenters
stated that the proposed testing requirements for testing of wellhead piping,
which is easily isolated from the wellhead using wellhead valves and therefore
can be tested at higher pressures if needed, will adequately protect the wellhead.
The Commission declines to make any change in response to these comments.
Integrity testing of the wellhead components does not allow a determination
of the integrity of the wellhead itself. In order to perform this testing,
the operator must isolate the wellhead, fill with water or snub out the brine
line. Gas storage testing is at least--if not more--important as testing liquid
storage wells which have 5 to 10 year inspection requirements. While the Commission
agrees that no one can predict how technology may evolve, it is important
that rule is not open ended (with respect to inspection and testing).
Both §3.95 and §3.97 currently include requirements for conducting
a mechanical integrity test (MIT) at least once every five years on storage
wells. The MIT is designed to observe whether there is a measurable loss of
stored product at the maximum allowable operating pressure. However, the MIT
cannot detect corrosion, deformation or other problems that may signal an
impending lack of integrity. For this reason, most liquid hydrocarbon storage
wells completed in salt domes have been subject to periodic inspection requirements
either by field rule or permit. For instance, all active liquid hydrocarbon
storage wells in the Barbers Hill field must be inspected at least once every
five years (Final Order No. 03-0223293). The permits for liquid hydrocarbon
storage wells in other salt domes include similar inspection requirements
with inspection intervals ranging from five to 10 years based on well-specific
factors. Currently, there are no similar inspection requirements for gas storage
wells.
Periodic inspection has been effective in detecting problems that the MIT
cannot detect and that may signal an impending lack of integrity before failure
occurs. Some examples are as follows.
1. A well operated in the Hull salt dome in Liberty County was equipped
with a cemented casing liner after casing inspection conducted during an MIT
indicated extensive corrosion damage (April 2002).
2. A well operated in the Barbers Hill salt dome in Chambers County was
removed from storage service after inspection revealed extensive casing deformation
(July 2002).
3. A well operated In the Tyler, East salt dome in Smith County was equipped
with a cemented casing liner after inspection identified extensive corrosion
(November 2003).
4. Three gas wells operated in the Boling salt dome in Wharton County have
been found to have parted casing and undergoing further inspection and repair
operations (September 2005 to present). The nature of the casing damage could
not be determined without inspection even though the wells had successful
MITs in 2001.
In addition, significant events have occurred at facilities outside of
Texas and where inspection after the event revealed significant defects that
may have been detected with adequate inspection prior to the events occurring.
The proposed rule amendments codify in §3.95 the inspection requirement
that currently is required by permit or field rule for liquid hydrocarbon
storage wells and add a new inspection requirement to §3.97 for gas storage
wells.
One commenter recommended that, if the Commission retains the proposed
wellhead testing requirement for gas storage wells, the Commission develop
an implementation schedule spread out over several years--rather than all
in a single year--in order to minimize the disruptions to the gas supply market
and to the service and material suppliers necessary for the testing.
The Commission declines to make any changes in response to this comment.
The Commission anticipates that the 15-year inspection cycle provides sufficient
time to develop schedules that will prevent or minimize interruption of market
supply.
The Commission considered well-specific factors when it determined appropriate
inspection intervals to include in permits for liquid hydrocarbon storage
wells. Although the Commission has required inspection of some liquid hydrocarbon
storage wells every five years, in general permits for such wells require
inspection every 10 years.
In determining the appropriate inspection interval for gas storage wells,
the Commission considered the factors used in determining the inspection schedule
for liquid hydrocarbon storage wells as well as factors unique to gas storage
operations. The Commission adopts less frequent inspection of gas storage
wells to account for the increased technical complexity, length of time, risk,
impact on market demand, and cost required to perform an inspection on a gas
storage well as compared to that required to inspect a liquid hydrocarbon
storage well.
There are significant technical impediments to conducting the inspection
of gas storage wells that are not present for liquid storage wells. Operators
of liquid hydrocarbon storage wells routinely remove the product from the
cavern and fill it with brine in order to conduct the required 5-year MIT.
While the caverns are empty, the operators are able to remove the brine tubing,
disassemble, test and inspect wellhead components, and run wireline inspection
tools to examine the casing.
Gas storage caverns, once leached to full capacity, are filled with only
gas and removal of the de-brining string in order to expose the casing to
wireline inspection is a complex and risky process. The proposed inspection
using current technology would require that the operator isolate the wellhead
and casing.
An operator may isolate the wellhead and casing of a gas storage well from
the normally pressurized, gas-filled, cavern by either snubbing out the brine
tubing and inserting a temporary plug in the bottom of the casing or removing
all of the gas, filling the cavern with brine, and then removing the tubing.
Both of these methods have major drawbacks. A temporary plug poses a greatly
enhanced risk of blowout or other failure because the temporary plug may leak
or the casing may be damaged during plug installation and/or removal. If the
operator chooses to isolate the wellhead and casing by emptying the cavern,
the operator would have to remove the storage facility from active service
for an extended period of time to empty the caverns of gas, fill the cavern
with brine, test the cavern, and then refill the cavern with gas and dispose
of the displaced brine. This method assumes that sufficient quantities of
brine or water are available and that capacity is available for disposal of
vast quantities of brine.
Both methods are very costly because the cavern must be removed from service
for an extended period of time, the operator must empty the cavern, fill the
cavern with brine, dispose of the brine after inspection, and refill the cavern
with gas at an unknown price. In addition, in the second method of preparing
the cavern for inspection, a hanging string may need to be extended below
the brine interface in the cavern to allow fluid injection.
Furthermore, natural gas storage plays a vital role in maintaining a reliable
supply of natural gas to meet the demands of consumers. Natural gas traditionally
has been a seasonal fuel, with demand higher in the winter for heating; however,
recent trends towards natural gas-fired electric generation has increased
demand for natural gas during the summer months. Stored natural gas also plays
a role as insurance against unforeseen supply disruptions and peak demand
supplies.
Based on these factors, as well as the fact that gas storage facilities
are relatively young compared to liquid storage operations, the Commission
adopts a 15-year inspection interval for gas storage wells. The inspection
interval is a multiple of the current five-year MIT schedule (ten years for
liquid hydrocarbon storage wells and 15 years for gas storage wells). Regardless
of the proposed inspection requirement, the Commission always has required
that operators maintain the integrity of the wellhead, cavern, and ancillary
equipment at any storage facility subject to its rules. The Commission finds
that it is reasonable to allow sufficient time for operators of gas storage
wells to develop the technology, plans and procedures for conducting the inspection
as safely, effectively, and efficiently as possible. The Commission anticipates
that these operators will devise less costly alternatives that accomplish
the intended purpose.
One commenter recommended that the words "stored gas" be used in the definition
of "leak or fire detector" at §3.97(a)(7) to focus only on the contents
of the storage well because the use of the word "gas" or "hydrocarbon vapor"
can be applied broadly to many substances while the intent is to detect a
leak of whatever gas is stored in the cavern.
The Commission agrees with this comment for the most part and has replaced
the existing terms "vapor" and "hydrocarbon vapor" in §3.97 with the
term "stored product."
One commenter requested that the Commission revise the proposed wording
"Either within three years of the effective date of this section, or in conjunction
with the next scheduled integrity test of the storage well, . . . ." in §3.97(h)(2)(B)
to clarify whether the intent is to allow the operator three years to select
the best time to install required emergency shutdown valves or whether the
intent is to force the operator to install the required emergency shutdown
valves in conjunction with the next mechanical integrity test if that test
is less than three years away.
The Commission agrees that the proposed wording is confusing. The intent
of the language is to allow an operator to delay compliance for at least three
years or up to the date the next mechanical integrity test is scheduled after
the three-year clock expires for a maximum of five years. For example, if
a permitted well is tested on the effective date of the rule, the operator
has either three years to install the emergency shutdown valves or may wait
until the next integrity test for a maximum of five years. In order to eliminate
the confusion, the Commission has revised the language to require that the
emergency shutdown valves be in place within five years of the effective date
of the rule. The Commission fully anticipates that many operators will install
the emergency shutdown valves in conjunction with mechanical integrity testing.
One commenter noted that §3.97(h)(2)(B) states that emergency shutdown
valves must be installed "between the storage wellhead and the product and
brine surface piping . . . " and requested that the Commission clarify the
classification of the piping between the two emergency shutdown valves in
situations where the operator elects to install secondary emergency shutdown
valves.
The Commission makes no change to the rule wording, but notes that a secondary
emergency shutdown valve may be installed to allow an operator to maintain
surface piping that is not rated for maximum wellhead operating pressure.
All piping downstream of the wellhead and primary emergency shutdown valves
must be rated for maximum wellhead pressure.
One commenter requested that the Commission revise the proposed wording
"Either within three years of the effective date of this section, or in conjunction
with the next scheduled integrity test of the storage well, . . . ." in §3.97(h)(2)(B)
to clarify whether the intent is to allow the operator three years to select
the best time to install required emergency shutdown valves or whether the
intent is to force the operator to install the required emergency shutdown
valves in conjunction with the next mechanical integrity test if that test
is less than three years away. If the Commission wants to "provide an operator
with the flexibility to choose the most appropriate alternative," as indicated
in the preamble, then it is unclear how requiring installation in conjunction
with the next scheduled mechanical integrity test provides flexibility. The
commenter recommended removing the words "or in conjunction with the next
scheduled integrity test of the storage well."
The Commission acknowledges the confusion. The intent of the language is
to allow an operator to delay compliance for at least three years or up to
the date the next mechanical integrity test is scheduled after the three-year
clock expires for a maximum of five years. The language is intended to provide
an operator with the flexibility to select the most appropriate and efficient
alternative. In many cases, if the operator must empty a cavern to perform
a mechanical integrity test, it may be more efficient to install the necessary
emergency shutdown valves at that time because the wellhead may be in a more
favorable operational status for a workover. However, the rule requires that
the required emergency shutdown valves be installed no later than five years
after the effective date of this rule.
One commenter found confusing the language in §3.97(h)(3)(A) concerning
surface piping and recommended that the Commission either clarify the language
or provide guidance to clarify the jurisdiction of the Oil and Gas Division
and of the Safety Division at these facilities.
The Commission declines to make any changes in response to this comment.
The pipeline safety rules do not apply to process piping and flowlines. The
Commission is amending the rules to ensure maximum safety for all piping.
The Texas Pipeline Association commented that, because its members have
been unable to identify any natural gas storage facility in Texas, whether
intrastate or interstate, with a salt dome cavern that is not subject to the
Safety Division's authority, the Commission should eliminate the requirement
in §3.97(h)(5)(A) to install leak or fire protection devices in "structurally
enclosed compressor sites." The Commission justified this requirement by stating
that "not all storage facilities are subject to the Safety Division's authority."
However, the pipeline safety regulations enforced by the Safety Division already
require gas detectors to be installed at enclosed compressor sites. See 49
CFR 192.736.
The Commission disagrees with this comment. The current rule requires heat
and fire detectors at each wellhead and each structurally enclosed compressor
site, but only for facilities within 100 yards of public areas. Because of
the extensive fire damage associated with the wellhead failure of a gas storage
well, the Commission has determined that it is appropriate to require heat
and fire detectors at each wellhead and each structurally enclosed compressor
site for all facilities whether or not they are located within 100 yards of
public areas. Although in some instances the requirements may duplicate the
pipeline safety regulations in 16 TAC Chapter 8 (relating to Pipeline Safety
Regulations), they do not conflict. In addition, for facilities regulated
under §3.95, the pipeline safety rules do not apply to brine piping.
Including the requirement in these rules ensures that it will apply to storage
facilities that are not subject to pipeline safety regulations (
e.g.
, not connected to transmission pipelines).
One commenter recommended that the Commission revise the good cause extension
provided in §3.97(h)(8)(B) to provide for up to 60 days for completion
of the root cause report since the longer time period would provide additional
flexibility to address the analysis necessary in complex situations and allow
a more comprehensive report. Another commenter expressed concern that the
proposed 30-day deadline (or the 60-day deadline if an extension is granted)
in §3.97(h)(8)(B) for submitting the report on the root cause of an incident
would not allow sufficient time to determine the root cause. The commenter
requested that the Commission consider accepting a preliminary report on the
root cause to be followed by a final report after the well has been investigated.
The TPA recommended that the good cause extension be revised to provide for
up to 60 days for completion of the root cause report to provide additional
flexibility to address the analysis necessary in complex situations and allow
for a more comprehensive report after completion of the analysis of the incident.
The Commission agrees that 30 or even 60 days may not be a sufficient amount
of time to adequately determine the root cause of an incident, particularly
a major incident. Therefore, the Commission has added a provision for Commission
approval of a reasonable additional amount of time for good cause.
Several commenters requested that the Commission revise the language in §3.97(h)(11)
concerning fire suppression capability to provide additional instruction to
allow an operator to determine whether or not the operator's design is in
compliance. These commenters recommended that the Commission develop design
standards that can be used by operators and Commission inspectors to determine
sufficiency prior to the occurrence of an incident. The commenters requested
that the Commission clarify the rule with respect to the length of time that
fire suppression equipment should be able to provide the temporary protection
for workers, the length of time the fire suppression equipment should be able
to cool the wellhead equipment. In the alternative, the commenters recommended
that the Commission require operators to submit to the Commission their fire
suppression plans within one year of the effective date of the rule amendments
and to have the system operational within two years of the Commission's approval
of such plan to allow some flexibility since each facilities' access to water
and proximity to the public may vary, and there may be other circumstances
unique to each location.
The Commission agrees in part with these commenters. Fire suppression capability
need only be sufficient to keep the wellhead equipment cool enough to prevent
further failure and to protect storage personnel long enough to safely evacuate
the area. The Commission provided a fairly lengthy period of time (three
years) for the operator to take into consideration the particulars of each
of their facilities. The Commission's intent was that after carefully designing
its plan, the operator would be able to ascertain compliance with the performance
standard in the rule during annual drills designed to test the operator's
emergency response plan required in paragraph §3.97(h)(7). Nevertheless,
the Commission acknowledges the commenters' concern that the Commission review
the plans before that time to provide some additional assurance that the proposal
is on compliance. Therefore, to clarify its intent, the Commission has added
"fire suppression capability" to the list of items that the emergency response
plans must address, and that the Commission will review and test during drills.
Three commenters recommended that the Commission reconsider the provisions
of §3.97(l)(3)(a), which require individual metering of each wellhead.
One of these commenters stated that most operators calculate individual well
injections from data from a master meter and that this method of determination
of individual well injection rates and pressures generally is sufficient to
meet market needs and provide a general overview of facility operations. Individual
wellhead meters will suffer from some level of inaccuracy depending upon the
type of meter used and the effort made to stabilize flow for accurate measurement.
In addition, accurate metering of individual wellhead injection will require
an expenditure of approximately $250,000 per wellhead. In the alternative,
one commenter recommended that the impose the individual metering requirement
only on new facilities because the cost could be factored into the initial
business plan.
The Commission disagrees with these comments. While master meters may be
adequate for "business related purposes," the common meter is subject to significant
inventory inaccuracies, which are unacceptable for the purposes of safety.
In addition, §3.97(l)(3)(b) provides for approval of an alternate method
of determining volumes.
Several commenters urged the Commission to reconsider imposition of costly
wellhead testing requirements in §3.97(o)(3) in light of the fact that
the only incidents cited by the Commission in the proposal preamble all involved
failure of wellhead related equipment and the Commission cited no instances
where a storage wellhead failed. The commenters requested that the Commission
allow testing of such equipment without the need to subject the wellhead to
the proposed pressure. Installation of valves between the wellhead and the
downstream components would allow an operator to test the wellhead equipment
without subjecting the well or the wellhead to these significantly larger
pressures. In addition, it is rare that a salt dome storage facility would
operate at its maximum permitted operating pressure except during testing
periods.
The Commission agrees in part. Testing of the wellhead equipment will not
allow an operator to determine the integrity of the wellhead. However, the
Commission's intent is to require periodic inspection of the wellhead and
cemented casing to determine integrity and has made changes in response to
comments.
Other Proposed Amendments Adopted without Changes
The Commission adopts amendments to §3.95(a), relating to definitions,
to amend the definition of "emergency shutdown valve" to substitute the term
"wellhead" for "well." The Commission also amends the definition of "hydrocarbon
storage well or storage well" to clarify that the well includes the storage
wellhead, casing, tubing, borehole, and cavern.
The Commission adopts two new definitions. The Commission defines the term
"storage wellhead" as "equipment installed at the surface of the wellbore,
including the casinghead and tubing head, spools, block or wing valves, and
instrument flanges." In addition, the new definition limits the length of
spool pieces to less than six feet to allow the operator flexibility in aligning
wellheads, emergency shutdown valves, and surface piping. The limitation on
length is necessary because investigation results indicate that long spool
pieces are subject to failure by water hammer effects. Industry input suggested
limiting spool piece length to six feet.
The Commission adopts a new definition for the term "surface piping" as
"any pipe within a storage facility that is directly connected to a storage
well, outboard of the wellhead emergency shutdown valve and used to transport
product, brine, or fresh water to or from a storage well whether such pipe
is above or below ground level."
New definitions for "storage wellhead" and "surface piping" were needed
because other proposed rule amendments specify that an emergency shutdown
valve must be located between the storage wellhead and surface piping and
such terms are not defined in the current rule.
The Commission adopts amendments to §3.95(c)(4) to specify that a
permit application must be filed for storing saltwater or brine in a pit,
as well as for disposing of saltwater or other oil and gas waste arising out
of or incidental to the creation, operation, or maintenance of an underground
hydrocarbon storage facility.
The Commission adopts amendments to §3.95(d), relating to standards
for underground storage zone, to change the heading of subsection (d)(1) from
"Impermeable salt formation" to "Geologic, construction, and operating performance,"
to more accurately describe the subject matter of this subdivision.
The Commission adopts substantive amendments to §3.95(h), relating
to safety. The Commission adopts amendments to §3.95(h) to specify that
active storage wells must possess a functional emergency shutdown valve when
the well is in service, notwithstanding compliance time periods for configuring
the emergency shutdown valve on the wellhead. The adopted amendments change
the heading of §3.95(h)(2) from "Emergency shutdown valves" to "Storage
wellhead" to reflect the fact that the Commission is adopting safety requirements
for the entire storage wellhead, not just the emergency shutdown valves. The
Commission re-designates subsection (h)(2)(A) as subsection (h)(2)(D) and
adds a new subsection (h)(2)(A), which requires that a storage wellhead be
designed, operated, and maintained to contain the contents of the storage
well and protect against the loss of stored product.
The Commission adopts amendments to §3.95(h)(2) to require that, within
five years of the effective date of this rule, the operator must install,
as required, emergency shutdown valves in a position between the storage wellhead
and the product and brine surface piping of each of hydrocarbon storage well
and, if required, between the storage wellhead and fresh water surface piping
of the well. The Commission adopts the revised language in response to comments
that the proposed language was confusing. The adopted amendment also allows
an operator to file a request, within one year of the effective date of the
section, for an exception to the storage wellhead configuration requirement
or the compliance date of this subparagraph and to propose an alternative
configuration for approval by the Commission or its designee.
The adopted amendment mandates locating the wellhead emergency shutdown
valve directly between the wellhead and surface piping. This change in location
of the wellhead emergency shutdown valve is intended to increase the safety
of the emergency shutdown system. The current rule does not address the physical
position or location of the emergency shutdown valve. Experience has shown
that the emergency shutdown valve is most effective when the valve is flanged
directly to the wellhead. The recent gas release and wellhead failure at a
gas storage facility resulted, in part, from the location of an emergency
valve on surface piping approximately 35 feet from the wellhead. After the
emergency shutdown valve closed as designed, a pressure transient, believed
related to water hammer, fractured the brine surface piping, allowing gas
to escape and ignite. A water hammer-induced pressure transient also is implicated
in at least two release incidents associated with the failure of surface piping
at liquid hydrocarbon storage facilities operating at Mont Belvieu.
The Commission adopts amendments to change the heading of §3.95(h)(3)
from "Brine and fresh water piping" to "Product, brine, and fresh water surface
piping" to expand the requirements to address all surface piping and to clarify
that specific requirements in the paragraph apply to specific types of surface
piping. The adopted amendments also add a new subparagraph (A), which requires
that the product surface piping be designed for the permitted maximum allowable
operating pressure on the hydrocarbon side of the well. The adopted amendments
also specify that, for facilities under the administrative authority of the
Commission's Safety Division, product surface piping extends from the wellhead
emergency shutdown valve to the first point of downstream pressure regulation.
This identifies the boundary between the respective administrative authorities
of the Safety Division and of the Oil and Gas Division for hazardous materials
piping for those facilities under the administrative authority of both divisions.
The Oil and Gas Division has administrative authority over all fresh water
and brine surface piping at hydrocarbon storage facilities under the jurisdiction
of the Railroad Commission of Texas. In addition, the Oil and Gas Division
has administrative authority over all product surface piping directly connected
to storage wells at those hydrocarbon storage facilities not under the administrative
authority of the Safety Division, such as underground hydrocarbon storage
facilities physically located within oil refineries. The Safety Division does
not have administrative authority over storage facilities located within facilities
that are not under Railroad Commission jurisdiction, such as oil refineries.
The Safety Division also does not have administrative authority over piping
that does not transport hazardous materials, such as fresh water or brine
piping.
The Commission adopts amendments to add a new §3.95(h)(3)(B) to require
that brine surface piping be designed for the maximum operating pressure on
the brine side of the well and designed to transport, under emergency conditions,
product to the brine system vapor control system, unless protected by a secondary
emergency shutdown valve and unless the brine surface piping between the wellhead
emergency shutdown valve and the secondary emergency shutdown valve is designed
for the permitted maximum allowable operating pressure on the hydrocarbon
side of the well.
The Commission amends §3.95(h)(3)(C) (re-designated from subparagraph
(B)) and adds new §3.95(h)(3)(D) to clarify that the requirements in
the subparagraph pertain to fresh water surface piping, and to clarify the
requirement that such piping must be protected by an emergency shutdown valve,
unless certain standards or design configurations are employed. For instance,
fresh water surface piping that is disconnected from the wellhead or is connected
to brine surface piping outboard of the emergency shutdown valve need not
be protected by an emergency shutdown valve. Similarly, fresh water piping
need not be protected by an emergency shutdown valve if it has a small internal
diameter (less than two inches) and is designed to withstand the permitted
maximum allowable operating pressure of the hydrocarbon side of the well and
is monitored by an onsite attendant when in use. An emergency shutdown valve
on small diameter (less than two inches) fresh water piping also is exempt
from the requirement that the valve be located on the wellhead or separated
from the wellhead by no more than a six-foot spool.
The Commission amends §3.95(h)(4)(C), regarding overfill detection
and automatic shut-in methods, to require that, within one year of the effective
date of the proposed amendments, each storage cavern shall have at least two
required devices or methods of overfill detection. Previously, the rule did
not specify that the devices or methods must be redundant. It has always been
the intent of the Commission that in the event of the failure of some component,
another method of overfill detection would remain functional. The Commission
intends to insure that the failure of a single device does not disable both
methods of overfill detection. The Commission amends subsection (h)(4)(C)(ii)
to allow operators the flexibility of using pressure transducers on the brine
piping in addition to pressure switches.
The Commission amends §3.95(h)(5) and (6), relating to leak detectors
and brine system gas vapor control, respectively, to delete references to
deadlines that already have already passed.
The Commission amends subsection (h)(7), relating to fire detection devices
or methods, to add requirements for fire control systems and to delete a reference
to a deadline that has already passed. The Commission adds new subparagraph
(C) to require that, within three years of the effective date of the amendment,
fire suppression capability, designed for personnel rescue and equipment protection
and cooling, be available at each storage wellhead in active storage service.
The new subparagraph allows an operator to request Commission approval of
an exception to this schedule or to the fire suppression requirement, as long
as the request includes a proposal for an alternate schedule or means of protection
from wellhead fire, and provided the request is made within one year of the
effective date of the amendments.
The fire suppression requirement is intended to provide protection for
rescue personnel and equipment cooling. The absence of such fire control systems
contributed to the complete wellhead failure of a gas storage well and damage
to adjacent structures associated with the gas release and fire at Moss Bluff
Hub Partners. The fire suppression capability is not necessarily directed
toward capacity sufficient to extinguish a wellhead fire. Extinguishing such
a fire could be an imprudent course of action, unless the source of the leak
was found and repaired. Rather, the fire suppression capability should be
sufficient to provide for short-term protection for emergency personnel and
for cooling of structures and wellheads potentially affected by a fire at
a wellhead or surface pipe.
The Commission amends §3.95(h)(8), relating to emergency response
plan, to delete a reference to a deadline that already has passed.
The Commission amends §3.95(h)(9)(B), relating to notification of
emergency or uncontrolled release, to require that, within 30 days of any
emergency, significant loss of fluids, significant mechanical failure, or
other problem that increases the potential for an uncontrolled release, an
operator file with the Commission a written report on the root cause of the
incident, and, within 90 days of an incident, file with the Commission a written
report describing the operational changes, if any, that will be implemented
to reduce the likelihood of the recurrence of a similar incident. For good
cause, the Commission may allow a reasonable amount of additional time for
an operator to file a report on the root cause of the incident. The provision
of a "reasonable amount of additional time" replaces the additional 30-day
extension proposed on July 21, 2006. The current rule requires only written
confirmation of an event within five working days of the event. The adopted
amendments will make hydrocarbon storage operations safer in the future by
better helping the Commission and operators identify causes of uncontrolled
releases and make corrections to prevent or reduce releases.
The Commission amends §3.95(h)(10) relating to public education, §3.95(h)(12)
relating to employee safety training, §3.95(h)(13), relating to warning
systems and alarms, and §3.95(h)(14), relating to wind socks, to delete
references to deadlines that already have passed.
The Commission amends §3.95(h)(15), relating to Barriers, to delete
reference to a deadline that already has passed and to require barriers around
above ground hydrocarbon piping, process equipment and storage vessels in
areas within 100 feet of a public road, in addition to the previous requirement
that barriers be placed where vehicles normally may be expected to travel.
The Commission makes this amendment because there has been at least one incident
in which a driver lost control of a vehicle on a public road, causing the
vehicle to leave the roadway and hit surface piping at a gas storage facility.
The Commission adds new §3.95(h)(16), relating to wellhead, surface
piping, and associated valves, to require that such piping and equipment be
designed, installed, and operated in accordance with engineering standards
appropriate to the expected service conditions to which the piping and equipment
will be subjected.
The Commission amends §3.95(i)(6) to make a conforming change.
The Commission amends §3.95(k)(1) to clarify that the operating pressure
of each hydrocarbon storage well may not exceed the permitted maximum allowable
operating pressure. This change is intended to conform the rule language generally
accepted use of the phrase "maximum allowable operating pressure."
The Commission amends §3.95(l), relating to monitoring requirements,
to add a new paragraph (5) on data recording. The new paragraph requires that,
within three years of the effective date of the amendments, operators have
in place and functioning a system to electronically record all liquid and
gas pressures, injection volumes, and rates at least once per minute and that
operators record all emergency actuations of the emergency shutdown valve.
This increased frequency of data recording is needed to insure that the operator
records sufficient information relating to the physical conditions that immediately
precede an accident or incident to help diagnose the root cause or causes
of an incident. Experience with several incidents at hydrocarbon storage facilities
has revealed that operators did not record operational data at a sufficient
frequency to help diagnose the root cause of the incident.
The Commission amends the heading of §3.95(n) from "Records retention"
to "Operations, construction, and maintenance records retention." In conjunction
with a change the Commission made in response to a comment, the Commission
revised this paragraph to include subparagraphs (A) and (B). The amendments
to subsection (n)(1)(A) require that operators retain electronic records of
well pressures, flow rates, and hydrocarbon volumes for three months instead
of five years. The amendment also adds flow rates and hydrocarbon volumes
to the record keeping requirement for each well, and would delete interface
levels from the recording requirement. Because these operational data are
primarily intended to diagnose accidents and incidents, long-term retention
is unwarranted. In response to a comment, the Commission clarified that the
electronic data must be recorded at a frequency of at least once per minute.
The adopted amendments in subsection (n)(1)(B) also clarify that the records
of maximum wellhead pressures on the hydrocarbon and brine sides of each hydrocarbon
storage well and the net volumes of hydrocarbons injected into and withdrawn
from each hydrocarbon storage well which the operators are required to report
to the Commission under subsection (m) must be retained for five years. In
response to comment, the Commission also clarified that the electronic data
must be recorded at a frequency of at least once per day.
Adopted amendments in subsection (n)(2) clarify that records associated
with testing and performance measurement, required under subsection (l)(4),
and testing of safety devices, required under subsection (h), must be retained
for five years. The Commission amends the heading of subsection (n)(3) from
"Equipment data" to "Construction and maintenance data," and to require an
operator to retain for the life of the facility documents and records pertaining
to drilling, mining, and completion of storage wells, testing of storage well
integrity, and major repairs on and workovers of the well. The extension of
the retention period is prudent and necessary to insure that critical information
on well construction, workovers, repairs, and testing is retained for the
life of the facility. It is often necessary to examine the results of original
completion, workovers, and testing procedures to properly interpret current
test results, particularly for tests that have recurrence intervals of five
years, such as mechanical integrity tests. Obviously, in cases where these
records are currently unavailable, the Commission does not intend for the
new requirement to be applied retroactively. However, with the new requirement,
the Commission intends to insure that if the records currently are available,
they will be preserved for the life of the facility, and will pass to future
owners or operators of the facilities with the transfer of ownership or operatorship.
The Commission amends the heading of §3.95(o) from "Testing" to "Testing
and Maintenance." New paragraph (1) requires that all hydrocarbon storage
wells drilled into salt domes with a single casing string cemented to the
surface have the casing inspected by mechanical, ultrasonic, or magnetic methods
at least once every five years and after each workover that involves physical
changes to the cemented casing string. Previously, all operators of liquid
hydrocarbon storage wells drilled into salt domes with a single casing string
cemented to the surface are required by permit to have the casing inspected
by mechanical, ultrasonic, or magnetic methods at least once every five years.
Since the Commission and operators agreed to implement the permit conditions
requiring such testing, the tests have detected significant casing damage,
allowing the operators at four facilities to repair the damage or remove the
wells from service before a significant leak could occur. Nitrogen-brine mechanical
integrity tests are not capable of detecting most classes of casing damage.
The adopted amendment would insure that in the event of transfer of ownership
of well facilities, the new operators are bound to the same requirements of
previous owners.
The Commission adds a new paragraph (3) to subsection (o), relating to
Storage wellhead and casing, to require operators to inspect the storage wellhead
and casing at least once every ten years. In addition, upon a showing of good
cause, an operator may request up to an additional five-year extension. The
Commission further adds factors that the Commission may consider in determining
good cause. Such factors include but are not limited to age, location, and
configuration of the well, well and facility history, operator compliance
record, operator efforts to comply with the section, and accuracy of inventory
control. Although it is typical industry practice to test wellhead components
in conjunction with a storage well mechanical integrity test, such tests currently
are not mandated by rule. The Commission deleted the language in §3.95(o)(3)
regarding pressure testing to 125 percent of the permitted maximum allowable
pressure and has clarified that each storage wellhead and cemented casing
must be inspected at least once every 10 years for corrosion, cracks, deformations,
or other conditions that may compromise integrity and that may not be detected
from the 5-year test. This change provides the opportunity for an operator
to plan for the inspection, and to evaluate alternative means of confirming
storage well component integrity.
The Commission adds new paragraph (4) to subsection (o), relating to Product,
freshwater, and brine surface piping. The new paragraph requires, within three
years of the effective date of this section or in conjunction with the storage
well integrity testing, that all product, freshwater, and brine surface piping
within a hydrocarbon storage facility be maintained according to a piping
integrity management plan and that within one year, the operator must submit
such a plan to the Commission for approval. This amendment aligns the requirements
for the testing and maintenance of surface piping within storage facilities
with current testing and maintenance requirements for pipelines transporting
hazardous materials.
The Commission adopts amendments to §3.97, relating to Underground
Storage of Gas in Salt Formations. The Commission adopts amendments to subsection
(a) to amend the definitions of "emergency shutdown valve," "gas storage well
or storage well," and "leak detector," and to add new definitions for the
terms "storage wellhead" and "surface piping." The Commission amends the definition
of "emergency shutdown valve" to substitute "wellhead" for "well." The Commission
amends the definition of "gas storage well or storage well" to clarify that
the term includes the storage wellhead, casing, tubing, borehole, and cavern.
The Commission amends the definition of "leak detector" to include "fire"
detectors. Leak detectors must be capable of detection by chemical or physical
means the presence of stored product or the escape of stored product or the
presence of flame or heat of a fire. References to "vapor" are deleted from
the definition; the natural gas in a storage cavern is not technically a vapor,
because there is no natural gas liquid in the system.
The Commission adds a definition of "storage wellhead" to mean the equipment
installed at the surface of the wellbore, including the casinghead and tubing
head, spools, block or wing valves, and instrument flanges. In addition, the
new language limits the length of spool pieces to less than six feet to allow
operators flexibility in aligning wellheads, emergency shutdown valves, and
surface piping. The limitation on length is necessary to prevent the installation
of unnecessarily long spool pieces, which are subject to failure by water
hammer effects during closure of the emergency shutdown valve as was the case
at the recent gas release and fire at the gas storage facility described above.
The Commission adopts a new definition for "surface piping" as any pipe within
a storage facility that is directly connected to a storage well and used to
transport gas, brine, or fresh water to or from a storage well whether such
pipe is above or below ground level. New definitions for "storage wellhead"
and "surface piping" are needed because other proposed rule amendments specify
that the emergency shutdown valve must be located between the storage wellhead
and surface piping, and these terms are not defined in the previous rule.
The Commission amends the title of §3.97(d)(1) from "Impermeable salt
formation" to "Geologic, construction, and operating performance" to more
accurately describe the subject matter of this subdivision.
The Commission amends §3.97(e)(3), relating to notice and hearing,
to correct a typographical error.
The Commission amends §3.97(h), relating to safety, to specify that
active storage wells must possess a functional emergency shutdown valve when
the well is in service, notwithstanding compliance time periods for configuring
the emergency shutdown valve on the wellhead. The Commission amends §3.97(h)(2),
relating to emergency shut down valves, to change the title of the paragraph
to "Storage wellhead." The Commission adds a new subsection (h)(2)(A), which
would require that a storage wellhead be designed, operated, and maintained
to contain the contents of the storage well and protect against the loss of
stored product. The Commission modifies subparagraph (B) (re-designated from
subparagraph (A)) to require that, within three years of the effective date
of these amendments or in conjunction with the next mechanical integrity test
of the storage cavern, the operator install, as required, emergency shutdown
valves in a position between the wellhead and the gas injection/withdrawal
surface piping of each storage well and between the wellhead and any brine
or fresh water surface piping. In addition, the Commission adds a requirement
that there may be no gas, brine, or fresh water piping between the wellhead
and the emergency shutdown valve. The new language allows an operator to request
an exception to the storage wellhead configuration or compliance date and
to propose an alternative configuration or workover schedule, provided that
the request and alternative proposal are received within one year of the effective
date of these amendments. The Commission or its designee must approve any
such request. The Commission changes the designation of §3.97(h)(2)(B)
to §3.97(h)(2)(C).
The amendment mandating the location of the emergency shutdown valve directly
between the wellhead and surface piping is intended to enhance the safety
of the emergency shutdown system. The previous rule did not address the physical
positioning of the emergency shutdown valve. Experience has shown that the
safest location for the emergency shutdown valve is flanged directly to the
wellhead. The recent gas release and wellhead failure at a gas storage facility
resulted, in part, from the location of an emergency valve on surface piping.
After the emergency shutdown valve closed as designed, a pressure transient,
believed related to water hammer, fractured the brine surface piping allowing
gas to escape and ignite.
The Commission adds a new paragraph (3) to subsection (h), relating to
gas, brine, and fresh water piping. New subsection (h)(3)(A) requires that
gas surface piping be designed for the permitted maximum allowable operating
pressure on the hydrocarbon side. The amendment also specifies that, for facilities
under the administrative authority of the Commission's Safety Division, product
surface piping extends from the wellhead emergency shutdown valve to the first
point of downstream pressure regulation. This identifies the respective responsibilities
of the Safety Division and of the Oil and Gas Division for hazardous materials
piping for those facilities under the administrative authority of both divisions.
The Oil and Gas Division is responsible for regulating all fresh water and
brine surface piping at hydrocarbon storage facilities under the jurisdiction
of the Railroad Commission of Texas. In addition, the Oil and Gas Division
has administrative authority over all product surface piping directly connected
to storage wells at those hydrocarbon storage facilities not under the administrative
authority of the Safety Division, such as underground hydrocarbon storage
facilities physically located within oil refineries. The Safety Division does
not have administrative authority over storage facilities located within facilities
that are not under Railroad Commission jurisdiction, such as oil refineries.
The Safety Division also does not have administrative authority over piping
that does not transport hazardous materials, such as fresh water or brine
piping.
New subsection (h)(3)(B) requires that brine surface piping be designed
for the maximum brine wellhead pressure unless protected by a secondary emergency
shutdown valve and unless the brine surface piping between the wellhead emergency
shutdown valve and the secondary emergency shutdown valve is designed for
the permitted maximum allowable operating pressure on the hydrocarbon side
of the well. New subsection (h)(3)(C) and (D) requires that fresh water surface
piping be protected by an emergency shutdown valve unless certain standards
or design configurations are employed. For instance, fresh water surface piping
that is disconnected from the wellhead or is connected to brine surface piping
outboard of the emergency shutdown valve need not be protected by an emergency
shutdown valve. Similarly, fresh water piping need not be protected by an
emergency shutdown valve if it has a small internal diameter (less than two
inches) and is designed for the permitted maximum allowable operating pressure
on the hydrocarbon side and is monitored by an onsite attendant when in use.
An emergency shutdown valve on small diameter (less than two inches) fresh
water piping is also exempt from the required location on the wellhead or
separated from the wellhead by no more than a six-foot spool. This language
is parallel to that adopted in §3.95(h)(3)(C) and (D) for liquid storage
wells where fresh water surface piping is more commonly installed.
The Commission adopts amendments to renumbered subsection (h)(4), relating
to cavern debrining and solution mining operations, to require that each storage
well have two or more redundant devices or methods of overfill detection during
cavern de-brining operations or solution mining operations conducted with
gas in storage in the same cavern. It has always been the intent of the Commission
that, in the event of the failure of some component, another method of overfill
detection remains functional. The Commission intends to enhance the likelihood
that the failure of a single device does not disable both methods of overfill
detection.
The Commission adopts amendments to renumbered §3.97(h)(4)(i) and
(ii) specifically to allow the use of pressure transducers in addition to
pressure switches.
The Commission amends the title of renumbered subsection (h)(5) from "Leak
detectors" to "Leak or fire detectors," and to require that, within two years
of the effective date of these amendments, a leak or fire detector be installed
and in operation at each gas storage well and each structurally enclosed compressor
site. The Commission deletes the language in this paragraph concerning distance
from a residence, commercial establishment, church, school, or small and well
defined outside area as well as the definition of "well defined outside area."
Previously, the rule required operators to install leak detectors only if
a storage well or compressor station is within 100 yards of a residence, commercial
establishment, church, school, or public area. The proposed change would require
operators to install leak or fire detectors regardless of the distance to
commercial or public facilities. A major release incident at one gas storage
facility demonstrated that the potential for significant damage and risk to
public heath and safety extends beyond 100 yards from a storage well or compressor
station. The Commission also adopts conforming amendments to subparagraph
(B).
The Commission adopts amendments to renumbered subsection (h)(6), relating
to warning systems and alarms, to require that all leak or fire detectors
or other methods that actuate the emergency shutdown valve be integrated with
warning systems within two years of the effective date of these amendments.
The Commission adopts amendments to renumbered subsection (h)(7) to remove
a reference to a deadline that has already passed.
The Commission adopts amendments to renumbered subsection (h)(8), relating
to notification of emergency or uncontrolled release, to clarify that an operator
must report to the Commission any significant loss of gas, as well as fluids.
In addition, the amended language requires that within 30 days of an incident,
the operator file with the Commission a written report on the root cause of
the incident and within 90 days of an incident, the operator file with the
Commission a written report that describes the operational changes, if any,
that will be implemented to reduce the likelihood of a recurrence of a similar
incident. For good cause, the Commission may allow a reasonable amount of
additional time for an operator to file a report on the root cause of the
incident. The provision of a "reasonable amount of additional time" replaces
the additional 30-day extension proposed on July 21, 2006. This language replaces
the requirement that the operator report a significant loss of fluids and
confirm the report in writing within five working days.
The Commission adds a new paragraph (11) to subsection (h), relating to
fire suppression capability, to require that, within three years of the effective
date of these amendments, each operator have fire suppression capability installed
at each wellhead and designed for personnel rescue and equipment protection
and cooling, unless the operator requests, within one year of the effective
date of these amendments and the Commission or its designee approves, an exception
to the schedule or fire suppression requirement. The fire suppression requirement
is intended to provide protection for rescue personnel and equipment cooling.
The absence of such fire control systems contributed to the complete wellhead
failure of a gas storage well and damage to adjacent structures associated
with the gas release and fire at Moss Bluff Hub Partners. The fire suppression
capability is not necessarily intended to be sufficient to extinguish a wellhead
fire. Extinguishing such a fire could be an imprudent course of action, unless
the source of the leak was found and repaired. Rather, the Commission intends
that the operator have capability sufficient to provide for short-term protection
of emergency personnel protection and for cooling of structures and wellheads
potentially affected by a fire from a well or surface pipe.
The Commission adds a new paragraph (12) to subsection (h), relating to
wellhead piping and related equipment, to require that all wellhead equipment,
gas, fresh water, and brine surface piping and associated valves be designed,
installed, tested, maintained, and operated in accordance with engineering
standards appropriate to the expected service conditions to which the piping
and equipment will be subjected.
The Commission further adopts a new paragraph (13) to subsection (h), relating
to barriers, which requires that, within one year of the effective date of
these amendments, operators place barriers designed to prevent unintended
impact by vehicles and equipment around above grade hydrocarbon piping, hydrocarbon
processing equipment where vehicles normally may be expected to travel, or
within 100 feet of a public road. There has been at least one incident in
which a driver lost control of a vehicle on a public road, causing the vehicle
to leave the roadway and hit above ground piping at a gas storage facility.
The Commission adopts other conforming amendments to §3.97(h) and
to update the rule to indicate that requirements for which previous versions
of the rule established deadlines are now current requirements because the
deadlines have passed.
The Commission adopts amendments to §3.97(k), relating to Operating
pressure, to insert "allowable" into the phrase "permitted maximum allowable
operating pressure" and to specify that permitted maximum allowable operating
pressure is that pressure identified on the Commission permit or order, or
on the permit application.
The Commission adopts amendments to §3.97(l)(1), relating to Gas pressure,
to make conforming amendments to clarify that pressure sensors must be integrated
electronically with the emergency shutdown valve actuation system as required
by the amendments adopted in §3.97(h). The Commission also adopts a new
paragraph (5), relating to data recording. The new paragraph requires that,
within three years of the effective date of these amendments, operators electronically
record all liquid and gas pressures, injection volumes and rates at least
once per minute, and that operators record all emergency actuations of the
emergency shutdown valve. This amendment is designed to aid in the analysis
of upset conditions by requiring operators to record operational data at relatively
frequent intervals. The lack of electronically recorded data on operational
conditions at a sufficient frequency has hindered the ability of operators
and the Commission to understand operating conditions immediately preceding
incidents at storage facilities.
The Commission adopts amendments to §3.97(n) to change the title from
"Records retention" to "Operations, construction, and maintenance records
retention," and to propose new records retention requirements. In conjunction
with a change the Commission made in response to comment, the Commission revised
paragraph (n)(1) paragraph to include subparagraphs (A) and (B). The Commission
adopts amendments to change the title of paragraph (1) from "Gas injection
and withdrawal data" to "Operations data." The Commission adopts amendments
to subparagraph (n)(1)(A) (formerly part of subparagraph (n)(1)) to require
that operators retain electronic records of well pressures, flow rates, and
gas volumes for three months instead of five years. In response to comment,
the Commission also clarifies that the electronic data must be recorded at
a frequency of at least once per minute. Because these operational data are
intended primarily to diagnose accidents and incidents, long-term retention
is unwarranted. The Commission adopts new §3.97(n)(1)(B), which requires
an operator to retain for at least five years the records reported to the
Commission under subsection (m), relating to Reporting. In response to comment,
the Commission also clarifies that these data must be recorded at a frequency
of at least once per day.
There is a new paragraph (2), which would require an operator to retain
for at least five years the records of measurement performance under §3.97(l)(4);
and testing of safety devices under §3.97(h). The records of any test
of a safety device required under subsection (h) must be available for on-site
inspection within 10 days of the date of the test. The Commission amends the
title of renumbered paragraph (3) from "Equipment data" to "Construction and
maintenance data" and to amend this subsection to require that operators maintain
documents and records on the drilling, mining, completion, major repairs,
and workovers of storage wells and the testing of storage well integrity required
under subsections (h) and (l) and that those records be retained for the life
of the facility. The extension of the retention period is prudent and necessary
to insure that critical information on well construction, repair, and workover
and the testing of storage well integrity be retained for the life of the
facility. It is often necessary to examine the results of past tests and procedures
to properly interpret current tests, particularly tests that have recurrence
intervals of five years, such as mechanical integrity tests. Obviously, in
cases where these records currently are unavailable, the Commission does not
intend that the new requirement be applied retroactively. However, the new
requirement would insure that if the records are currently available, they
will be preserved for the life of the facility and will pass for retention
purposes to future owners and/or operators of the facilities with the transfer
of ownership or operatorship.
The Commission adopts amendments to §3.97(o), relating to Testing,
to change the title to "Testing and maintenance." The Commission adds a new
paragraph (3), relating to "Storage wellhead and casing," that would require
that testing or inspection of storage wellhead components be performed in
conjunction with the integrity test schedule of the hydrocarbon storage well.
The Commission deleted the language proposed in §3.97(o)(3) regarding
pressure testing to 125 percent of the permitted maximum allowable pressure
and has clarified that each storage wellhead and cemented casing must be inspected
at least once every 15 years for corrosion, cracks, deformations, or other
conditions that may compromise integrity and that may not be detected from
the 5-year test. In addition, upon a showing of good cause, an operator may
request up to an additional five-year extension. The Commission further adds
factors that the Commission may consider in determining good cause. Such factors
include but are not limited to age, location, and configuration of the well,
well and facility history, operator compliance record, operator efforts to
comply with the section, and accuracy of inventory control. This change provides
the opportunity for an operator to plan for the inspection, and to evaluate
alternative means of confirming storage well component integrity.
The Commission adds a new §3.97(o)(4), relating to "Fresh water, brine,
and gas surface piping," to require that all gas, brine, and fresh water surface
piping be maintained according to a piping integrity management plan within
three years or in conjunction with the testing of storage well integrity.
Within one year of the effective date of this section, the operator must submit
a piping integrity management plan to the Commission for approval. This amendment
aligns the requirements for the testing and maintenance of surface piping
in a gas storage facility with current testing and maintenance requirements
for pipelines transporting hazardous materials. Gas piping and fresh water
and brine piping within storage facilities could, in emergency situations,
transport hazardous materials.
The Commission adopts the amendments to §3.95 and §3.97 under
(1) Texas Natural Resources Code, §81.051, which gives the Commission
jurisdiction over all common carrier pipelines in Texas, oil and gas wells
in Texas, persons owning or operating pipelines in Texas, and persons owning
or engaged in drilling or operating oil or gas wells in Texas; (2) Texas Natural
Resources Code, §81.052, which authorizes the Commission to adopt all
necessary rules for governing and regulating persons and their operations
under the jurisdiction of the Commission, including such rules as the Commission
may consider necessary and appropriate to implement state responsibility under
any federal law or rules governing such persons and their operations; (3)
Texas Natural Resources Code, §85.041, which prohibits the purchase,
acquisition, or sale, or the transporting, refining, processing, or handling
in any other way, of oil or gas, produced in whole or in part in violation
of any oil or gas conservation statute of this state or of any rule or order
of the Commission under such a statute, and the purchase, acquisition, or
sale, or the transporting, refining, processing, or handling in any other
way, of any product of oil or gas which is derived in whole or in part from
oil or gas or any product of either, which was in whole or part produced,
purchased, acquired, sold, transported, refined, processed, or handled in
any other way, in violation of any oil or gas conservation statute of this
state, or of any rule or order of the Commission under such a statute; (4)
Texas Natural Resources Code, §85.042, which authorizes the Commission
to promulgate and enforce rules and orders necessary to carry into effect
the provisions of §85.041, and to prevent that section's violation, and,
when necessary, to make and enforce rules either general in their nature or
applicable to particular fields for the prevention of actual waste of oil
or operations in the field dangerous to life or property; (5) Texas Natural
Resources Code, §85.201, which directs the Commission to make and enforce
rules and orders for the conservation of oil and gas and prevention of waste
of oil and gas; (6) Texas Natural Resources Code, §85.202, which authorizes
the Commission to make rules and orders to prevent waste of oil and gas in
drilling and producing operations and in the storage, piping, and distribution
of oil and gas; to require dry or abandoned wells to be plugged in a manner
that will confine oil, gas, and water in the strata in which they are found
and prevent them from escaping into other strata; for the drilling of wells
and preserving a record of the drilling of wells; to require wells to be drilled
and operated in a manner that will prevent injury to adjoining property; to
prevent oil and gas and water from escaping from the strata in which they
are found into other strata; to provide rules for shooting wells and for separating
oil from gas; to require records to be kept and reports made; and to provide
for issuance of permits, tenders, and other evidences of permission when the
issuance of the permits, tenders, or permission is necessary or incident to
the enforcement of the Commission's rules or orders for the prevention of
waste, and authorizes the Commission to do all things necessary for the conservation
of oil and gas and prevention of waste of oil and gas and to adopt other rules
and orders as may be necessary for those purposes; (7) Texas Natural Resources
Code, §86.041, which grants the Commission broad discretion in administering
the provisions of this chapter and to adopt any rule or order in the manner
provided by law that the Commission finds necessary to effectuate the provisions
and purposes of this chapter; (8) Texas Natural Resources Code, §86.042,
which directs the Commission to adopt and enforce rules and orders to conserve
and prevent the waste of gas; prevent the waste of gas in drilling and producing
operations and in the piping and distribution of gas; require dry or abandoned
wells to be plugged in a way that confines gas and water in the strata in
which they are found and prevents them from escaping into other strata; provide
for drilling wells and preserving a record of them; require wells to be drilled
and operated in a manner that prevents injury to adjoining property; prevent
gas and water from escaping from the strata in which they are found into other
strata; require records to be kept and reports made; provide for the issuance
of permits and other evidences of permission when the issuance of the permit
or permission is necessary or incident to the enforcement of its blanket grant
of authority to make any rules necessary to effectuate the law; and otherwise
accomplish the purposes of this chapter; (9) Texas Natural Resources Code, §211.011,
which gives the Commission jurisdiction over all salt dome storage of hazardous
liquids and over salt dome storage facilities used for the storage of hazardous
liquids; (10) Texas Natural Resources Code, §211.012, which directs the
Commission to adopt safety standards and practices for the salt dome storage
of hazardous liquids and the facilities used for that purpose that require
the installation and periodic testing of safety devices at a salt dome storage
facility; the establishment of emergency notification procedures for the operator
of a facility in the event of a release of a hazardous substance that poses
a substantial risk to the public; fire prevention and response procedures;
employee and third-party contractor safety training with respect to the operation
of the facility; and other requirements that the Commission finds necessary
and reasonable for the safe construction, operation, and maintenance of salt
dome storage facilities; (11) Texas Natural Resources Code, §211.013,
which requires each owner or operator of a hazardous liquid salt dome storage
facility to maintain records, make reports, and provide any information the
Commission may require with respect to the construction, operation, or maintenance
of the facility; and requires the Commission by rule to designate the records
required to be maintained and the reports required to be filed by the owner
or operator and shall provide forms for reports if necessary; (12) Texas Natural
Resources Code, §117.012, which requires the Commission to adopt rules
that include safety standards for and practices applicable to the intrastate
transportation of hazardous liquids or carbon dioxide by pipeline and intrastate
hazardous liquid or carbon dioxide pipeline facilities; and (13) Texas Utilities
Code, §§121.201 - 121.210, which authorize the Commission to adopt
safety standards and practices applicable to the transportation of gas and
to associated pipeline facilities within Texas to the maximum degree permissible
under, and to take any other requisite action in accordance with, 49 United
States Code Annotated §60101,
et seq
.
Texas Natural Resources Code, §§81.051, 81.052, 85.041, 85.042,
85.201, 85.202, 86.041, 86.042, 211.011, 211.012, 211.013, and 117.012, and
Texas Utilities Code, §§121.201 - 121.210 are affected by the adopted
amendments.
Statutory authority: Texas Natural Resources Code, §§81.051,
81.052, 85.041, 85.042, 85.201, 85.202, 86.041, 86.042, 211.011, 211.012,
211.013, and 117.012, and Texas Utilities Code, §§121.201 - 121.210.
Cross-reference to statutes: Texas Natural Resources Code, §§81.051,
81.052, 85.041, 85.042, 85.201, 85.202, 86.041, 86.042, 211.011, 211.012,
211.013, and 117.012, and Texas Utilities Code, §§121.201 - 121.210.
Issued in Austin, Texas, on January 10, 2007.
§3.95.Underground Storage of Liquid or Liquefied Hydrocarbons in Salt Formations.
(a)
Definitions. The following terms, when used in this section,
shall have the following meanings, unless the context clearly indicates otherwise.
(1)
Affected person--A person who, as a result of actions proposed
in an application for a storage facility permit or for amendment or modification
of an existing storage facility permit, has suffered or may suffer actual
injury or economic damage other than as a member of the general public.
(2)
Brine string--The uncemented tubing through which highly
saline water flows into or out of a hydrocarbon storage well during hydrocarbon
withdrawal or injection operations.
(3)
Cavern--The storage space created in a salt formation by
solution mining.
(4)
Commission--The Railroad Commission of Texas.
(5)
Emergency shutdown valve--A valve that automatically closes
to isolate a hydrocarbon storage wellhead from surface piping in the event
of specified conditions that, if uncontrolled, may cause an emergency.
(6)
Fire detector--A device capable of detecting the presence
of a flame or the heat from a fire.
(7)
Fresh water--Water having bacteriological, physical, and
chemical properties that make it suitable and feasible for beneficial use
for any lawful purpose. For purposes of this section, brine associated with
the creation, operation, and maintenance of an underground hydrocarbon storage
facility is not considered fresh water.
(8)
Hydrocarbon storage well or storage well--A well, including
the storage wellhead, casing, tubing, borehole, and cavern, used for the injection
or withdrawal of liquid or liquefied hydrocarbons into or out of an underground
hydrocarbon storage facility.
(9)
Leak detector--A device capable of detecting by chemical
or physical means the presence of hydrocarbon vapor or the escape of vapor
through a small opening.
(10)
Liquid or liquefied hydrocarbons--Crude oil and products,
derivatives, or byproducts of oil or gas that are:
(A)
liquid under standard conditions of temperature and pressure;
(B)
liquefied under the temperatures and pressures at which
they are stored; or
(C)
stored under conditions that necessitate the use of displacement
fluids to withdraw them from storage.
(11)
Operator--The person recognized by the Commission as being
responsible for the physical operation of an underground hydrocarbon storage
facility, or such person's authorized representative.
(12)
Owner--The person recognized by the Commission as owning
all or part of a storage facility, or such person's authorized representative.
(13)
Person--A natural person, corporation, organization, government,
governmental subdivision or agency, business trust, estate, trust, partnership,
association, or any other legal entity.
(14)
Pollution--Alteration of the physical, chemical, or biological
quality of, or the contamination of, water that makes it harmful, detrimental,
or injurious to humans, animal life, vegetation, or property, or to public
health, safety, or welfare, or impairs the usefulness or the public enjoyment
of the water for any lawful or reasonable purpose.
(15)
Process or transfer area--Any area at an underground hydrocarbon
storage facility where hydrocarbons are physically altered by equipment, including
dehydrators, compressors, and pumps, or where hydrocarbons are transferred
to or from trucks, rail cars, or pipelines.
(16)
Storage wellhead--Equipment installed at the surface of
the wellbore, including the casinghead and tubing head, spools, block or wing
valves, and instrument flanges. Spool pieces must have a length of less than
six feet to be considered a part of the storage wellhead.
(17)
Surface piping--Any pipe within a storage facility that
is directly connected to a storage well, outboard of the wellhead emergency
shutdown valve and used to transport product, brine, or fresh water to or
from a storage well whether such pipe is above or below ground level.
(18)
Underground hydrocarbon storage facility or storage facility--A
facility used for the storage of liquid or liquefied hydrocarbons in an underground
salt formation, including surface and subsurface rights, appurtenances, and
improvements necessary for the operation of the facility.
(b)
Permit required.
(1)
General. No person may create, operate, or maintain an
underground hydrocarbon storage facility without obtaining a permit from the
Commission. A permit issued by the Commission for such activities before the
effective date of this section shall continue in effect until revoked, modified,
or suspended by the Commission, or until it expires by its terms. The provisions
of this section apply to permits for underground hydrocarbon storage facility
operations issued prior to the effective date of this section, except as specifically
provided in this section.
(2)
Conflict with other requirements. If a provision of this
section conflicts with any provision or term of a Commission order, field
rule, or permit, the provision of such order, field rule, or permit shall
control.
(c)
Application.
(1)
Information required. An application for a permit to create,
operate, or maintain an underground hydrocarbon storage facility shall be
filed with the Commission by the owner or operator, or proposed owner or operator,
on the prescribed form. The application shall contain the information necessary
to demonstrate compliance with the applicable state laws and Commission regulations.
(2)
Permit amendment. An application for amendment of an existing
underground hydrocarbon storage facility permit shall be filed with the Commission:
(A)
prior to any planned enlargement of a cavern in excess
of the permitted cavern capacity by solution mining;
(B)
when required in accordance with paragraph (3) of this
subsection;
(C)
prior to the drilling of any additional hydrocarbon storage
wells;
(D)
prior to any increase in the volume of liquid or liquefied
hydrocarbons stored in the cavern in excess of the permitted storage volume;
or
(E)
any time that conditions at the storage facility deviate
materially from conditions specified in the permit or the permit application.
(3)
Increase in capacity. The owner or operator of a storage
facility shall notify the Commission if information indicates that the capacity
of a cavern exceeds the permitted cavern capacity by 20% or more. Such notification
shall be made in writing to the Commission within 10 days of the date that
the owner or operator knows or has reason to know that the cavern capacity
exceeds the permitted capacity by 20% or more. The notification shall include
a description of the information that indicates that the permitted cavern
capacity has been exceeded, and an estimate of the current cavern capacity.
Upon receipt of such information, the Commission or its designee may take
any one or more of the following actions:
(A)
require the permittee to comply with a compliance schedule
that lists measures to be taken to ensure that conditions at the storage facility
do not pose a danger to life or property, and that no waste of hydrocarbons,
uncontrolled escape of hydrocarbons, or pollution of fresh water occurs;
(B)
require the permittee to file an application to amend the
underground hydrocarbon storage facility permit;
(C)
modify, cancel, or suspend the permit as provided in subsection
(f) of this section; or
(D)
take enforcement action.
(4)
Related activities. An application for a permit to store
saltwater or brine in a pit or to dispose of saltwater or other oil and gas
waste arising out of or incidental to the creation, operation, or maintenance
of an underground hydrocarbon storage facility shall be filed in accordance
with applicable Commission requirements.
(d)
Standards for underground storage zone.
(1)
Geologic, construction, and operating performance. An underground
hydrocarbon storage facility may be created, operated, or maintained only
in an impermeable salt formation in a manner that will prevent waste of the
stored hydrocarbons, uncontrolled escape of hydrocarbons, pollution of fresh
water, and danger to life or property. Natural gas storage operations are
not authorized under the provisions of this section. A permit under §3.97
of this title (relating to Underground Storage of Gas in Salt Formations)
is required to convert from storage of liquid or liquefied hydrocarbons to
storage of natural gas in an underground salt formation.
(2)
Fresh water strata. The applicant must submit with the
application a letter from the Texas Commission on Environmental Quality or
its successor agencies stating the depth to which fresh water strata occur
at each storage facility.
(e)
Notice and hearing.
(1)
Notice requirements. The applicant shall, no later than
the date the application is mailed to or filed with the Commission, give notice
of an application for a permit to create, operate, or maintain an underground
hydrocarbon storage facility, or to amend an existing storage facility permit,
by mailing or delivering a copy of the application form to:
(A)
the surface owner of the tract where the storage facility
is located or is proposed to be located;
(B)
the surface owner of each tract adjoining the tract where
the storage facility is located or is proposed to be located;
(C)
each oil, gas, or salt leaseholder, other than the applicant,
of the tract on which the storage facility is located or is proposed to be
located;
(D)
each oil, gas, or salt leaseholder of any tract adjoining
the tract on which the storage facility is located or is proposed to be located;
(E)
the county clerk of the county where the storage facility
is located or is proposed to be located; and
(F)
if the storage facility is located or proposed to be located
within city limits, the city clerk or other appropriate city official.
(2)
Publication of notice. Notice of the application, in a
form approved by the Commission or its designee, shall be published by the
applicant once a week for three consecutive weeks in a newspaper of general
circulation in the county or counties where the facility is or is proposed
to be located. The applicant shall file proof of publication prior to any
hearing on the application or administrative approval of the application.
(3)
Notice by publication. The applicant shall make diligent
efforts to ascertain the name and address of each person identified under
paragraph (1)(A) - (D) of this subsection. The exercise of diligent efforts
to ascertain the names and addresses of such persons shall require an examination
of the county records where the facility is located and an investigation of
any other information of which the applicant has actual knowledge. If, after
diligent efforts, the applicant has been unable to ascertain the name and
address of one or more persons required to be notified under paragraph (1)(A)
- (D) of this subsection, the notice requirements for those persons are satisfied
by the publication of the notice of application as required in paragraph (2)
of this subsection. The applicant must submit an affidavit to the Commission
specifying the efforts that were taken to identify each person whose name
and/or address could not be ascertained.
(4)
Hearing required for new permits. A permit application
for a new underground hydrocarbon storage facility will be considered for
approval only after notice and hearing. The Commission will give notice of
the hearing to all affected persons, local governments, and other persons
who express, in writing, an interest in the application. After hearing, the
examiner shall recommend a final action by the Commission.
(5)
Hearing on permit amendments.
(A)
An application for an amendment to an existing storage
facility permit may be approved administratively if the Commission receives
no protest from a person notified pursuant to the provisions of paragraph
(1) of this subsection, or from any other affected person.
(B)
If the Commission receives a protest from a person notified
pursuant to paragraph (1) of this subsection or from any other affected person
within 15 days of the date of receipt of the application by the Commission,
or of the date of the third publication, whichever is later, or if the Commission
determines that a hearing is in the public interest, then the applicant will
be notified that the application cannot be approved administratively. The
Commission will schedule a hearing on the application upon written request
of the applicant. The Commission will give notice of the hearing to all affected
persons, local governments, and other persons who express, in writing, an
interest in the application. After hearing, the examiner shall recommend a
final action by the Commission.
(C)
If the application is administratively denied, a hearing
will be scheduled upon written request of the applicant. After hearing, the
examiner shall recommend a final action by the Commission.
(f)
Modification, cancellation, or suspension of a permit.
(1)
General. Any permit may be modified, suspended, or canceled
after notice and opportunity for hearing if:
(A)
a material change in conditions has occurred in the operation,
maintenance, or construction of the storage facility, or there are material
deviations from the information originally furnished to the Commission. A
change in conditions at a facility that does not affect the safe operation
of the facility or the ability of the facility to operate without causing
waste of hydrocarbons or pollution is not considered to be material;
(B)
fresh water is likely to be polluted as a result of continued
operation of the facility;
(C)
there are material violations of the terms and provisions
of the permit or Commission regulations;
(D)
the applicant has misrepresented any material facts during
the permit issuance process; or
(E)
injected fluids are escaping or are likely to escape from
the storage facility.
(2)
Imminent dangers. Notwithstanding the provisions of paragraph
(1) of this subsection, in the event of an emergency that presents an imminent
danger to life or property, or where waste of hydrocarbons, uncontrolled escape
of hydrocarbons, or pollution of fresh water is imminent, the Commission or
its designee may immediately suspend a storage facility permit until a final
order is issued pursuant to a hearing, if any, conducted in accordance with
the provisions of paragraph (1) of this subsection. All operations at the
facility shall cease upon suspension of a permit under this paragraph.
(g)
Transfer of permit. A storage facility permit may not be
transferred without the prior approval of the Commission or its designee.
Until such transfer is approved by the Commission or its designee, the proposed
transferee may not conduct any activities otherwise authorized by the permit.
The following procedure shall be followed when requesting approval for transfer
of a permit.
(1)
Request. Prior to transferring either ownership or operation
of a storage facility, the permittee shall file a request for transfer of
the permit with the Commission. Such request may not be filed unless a completed
Form P-4, signed by both the permittee and the proposed transferee, has been
filed with the Commission.
(2)
Approval. The Commission, or its designee, shall approve
the transfer of a storage facility permit, provided:
(A)
the proposed transferee is not the subject of any unsatisfied
Commission enforcement order at the time of the request for permit transfer;
and
(B)
there are no existing violations of any Commission regulation,
order, or permit at the storage facility at the time of the request for permit
transfer that have been documented by the Commission, or its employees, unless
the proposed transferee agrees to correct the violations according to a compliance
schedule approved by the Commission, or its designee.
(3)
Good cause. Notwithstanding paragraph (2) of this subsection,
for good cause shown the Commission or its designee may require public notice
and opportunity for hearing prior to taking action on a request for transfer
of a permit. Such request may be denied after notice and opportunity for hearing
if the Commission or its designee finds that transfer of the permit would
not be in the public interest.
(h)
Safety. The following safety requirements shall apply to
all underground hydrocarbon storage facilities, except as specifically provided
otherwise, provided, however, that the provisions of this subsection shall
not apply to any hydrocarbon storage well that is out of service and disconnected
from all surface piping. Notwithstanding the compliance time periods specified
in this subsection, a new storage facility permitted under this section must
have all required safety measures and equipment in place before commencement
of storage operations at the facility. All storage facilities that are permitted
on the effective date of this section must have such safety measures and equipment
in place within the period of time specified. Further, until such a facility
has all the safety measures and devices required by paragraphs (2) - (7) and
(13) - (16) of this subsection in place, the facility must have an attendant
on site at all times. Notwithstanding the compliance time periods specified
in paragraph (2)(B) of this subsection, no storage well in active service
may be operated without a fully functional emergency shutdown valve unless
in compliance with specified conditions of paragraph (2)(C) of this subsection.
(1)
Monitoring of injection and withdrawal operations. All
hydrocarbon injection and withdrawal activities shall be continuously monitored
by an individual who is trained and experienced in such activities. Any facility
that is unattended during injection and withdrawal activities shall have company
personnel on call at all times. On-call personnel must be able to reach the
facility within 30 minutes from the time a potential problem at the storage
facility is noted by the individual monitoring the injection or withdrawal
activities.
(2)
Storage wellhead.
(A)
The storage wellhead shall be designed, operated, and maintained
to contain the contents of the storage well and protect against loss of stored
product.
(B)
Within five years of the effective date of this section,
the operator shall have installed emergency shutdown valves between the storage
wellhead and the product and brine surface piping of each hydrocarbon storage
well and, if required under paragraph (3) of this subsection, between the
storage wellhead and fresh water surface piping of the well. Within one year
of the effective date of the section, an operator may request an exception
to the storage wellhead configuration or compliance date of this subparagraph
and propose an alternative configuration or workover schedule for approval
by the Commission or its designee. A storage well that is out of service and
is disconnected from surface piping shall be exempt from this requirement
until reactivated for active hydrocarbon storage. Emergency shutdown valves
shall meet the following requirements.
(i)
Each emergency shutdown valve shall be capable of activation
at each storage well, at the on-site control center if one exists, at the
remote control center if one exists, and at a location that is reasonably
anticipated to be accessible to emergency response personnel at any facility
that does not have an on-site control center that is attended 24 hours per
day.
(ii)
Each emergency shutdown valve shall be an automatic fail-closed
valve that automatically closes when there is a loss of pneumatic pressure,
hydraulic pressure, or power to the valve.
(iii)
Each emergency shutdown valve shall be closed and opened
at least monthly.
(iv)
Each emergency shutdown valve system shall be tested at
least twice each calendar year at intervals not to exceed 7 1/2 months. The
test shall consist of activating the actuation devices, checking the warning
system, and observing the valve closure.
(C)
If an emergency shutdown valve system fails to operate
as required, the storage well shall be immediately shut in until repairs are
completed, unless:
(i)
a backup emergency shutdown valve is in operation on the
same piping; or
(ii)
an attendant is posted at the well site to provide immediate
manual shut-in.
(D)
The requirements of this paragraph do not apply to underground
hydrocarbon storage facilities storing only crude oil.
(3)
Product, brine, and fresh water surface piping.
(A)
Product surface piping shall be designed for the permitted
maximum allowable operating pressure on the hydrocarbon side of the well.
For facilities with hazardous materials surface piping under the administrative
authority of the Safety Division of the Railroad Commission of Texas, for
the purposes of this section, product surface piping extends from the wellhead
emergency shutdown valve to the first pressure regulation device, including
a manual, motor-operated, or emergency shutdown valve
(B)
Brine surface piping shall be designed for the maximum
brine wellhead pressure and to transport, under emergency conditions, product
to the brine system gas vapor control system described in paragraph (6) of
this subsection unless:
(i)
a secondary emergency shutdown valve is in operation on
the brine surface piping; and
(ii)
the brine surface piping between the wellhead emergency
shutdown valve and the secondary emergency shutdown valve is designed for
the permitted maximum allowable operating pressure on the hydrocarbon side
of the well.
(C)
Fresh water surface piping, if any, must be equipped with
a wellhead emergency shutdown valve unless it is:
(i)
disconnected from the wellhead; or
(ii)
connected to brine surface piping outboard of the wellhead
emergency shutdown valve; or
(iii)
designed for the permitted maximum allowable operating
pressure on the hydrocarbon side of the well; and has an internal diameter
of less than or equal to two inches; and an attendant is posted at the well
site to provide immediate manual shut-in when in use.
(D)
Fresh water piping designed for the permitted maximum allowable
operating pressure on the hydrocarbon side of the well and with an internal
diameter of less than or equal to two inches is exempt from the requirement
that an emergency shutdown valve be located on the wellhead or separated from
the wellhead by a spool no longer than six feet.
(4)
Overfill detection and automatic shut-in methods.
(A)
The requirements of this paragraph shall not apply to an
underground hydrocarbon storage facility storing only crude oil.
(B)
The requirements of this paragraph shall not apply to a
storage well that is out of service and disconnected from surface piping until
the well is reconnected for hydrocarbon storage.
(C)
Within one year of the effective date of this section,
each storage cavern shall have at least two of the following redundant devices
or methods in operation:
(i)
a safety casing or annular tubing string filled with a
non-volatile fluid and equipped with a pressure sensor switch set to automatically
close all emergency shutdown valves in response to a preset pressure;
(ii)
a preset pressure sensor switch or transducer on the brine
piping that is set to automatically close all emergency shutdown valves in
response to a preset pressure. This pressure sensor or transducer may be used
in conjunction with weep hole(s) on a safety string that is concentric with
the brine string, or in conjunction with weep hole(s) on the brine string;
(iii)
a device on the brine string or brine piping that detects
hydrocarbon in the brine by physical or chemical characteristics and that
is set to automatically close all emergency shutdown valves in response to
hydrocarbon detection;
(iv)
an instrument that detects a rapid increase in the brine
flow rate indicative of hydrocarbon in the brine and that is set to automatically
close all emergency shutdown valves in response to a preset flow rate or differential
flow rate; or
(v)
an alternate device or method approved by the Commission
or its designee.
(5)
Leak detectors.
(A)
The provisions of subparagraphs (B) - (D) of this paragraph
shall not apply to underground hydrocarbon storage facilities storing only
crude oil.
(B)
A leak detector shall be installed and in operation at
the wellhead of each hydrocarbon storage well and at each process and transfer
area and each surface vessel area that contains liquid or liquefied hydrocarbons.
These leak detectors shall be integrated with the warning system required
in paragraph (13)(A) of this subsection.
(C)
Leak detectors shall be installed and in operation at four
locations that are evenly spaced around the perimeter of the brine pit(s).
(D)
Leak detectors shall be tested twice each calendar year
at intervals not to exceed 7 1/2 months and, when defective, repaired or replaced
within 10 days.
(6)
Brine system gas vapor control.
(A)
The provisions of this paragraph shall not apply to underground
hydrocarbon storage facilities storing only crude oil.
(B)
Gas vapor control devices shall be installed and in operation
at each brine pit system to ignite or capture hydrocarbon vapors that are
heavier than air. Control devices shall consist of at least one of the following:
(i)
a flare on the brine system upstream from the brine discharge
point;
(ii)
a hydrocarbon liquid knockout vessel and degasifier;
(iii)
pilot lights on the berm of each brine pit; or
(iv)
an alternative method designed to provide a reliable,
localized point of ignition to prevent the formation of a vapor cloud.
(C)
Brine system gas vapor control systems shall be inspected
twice each calendar year at intervals not to exceed 7 1/2 months.
(7)
Fire detection devices or methods and fire control systems.
(A)
Fire detection devices or methods shall be installed and
in operation at all process and transfer areas. Fire detection devices or
methods specified in this paragraph shall be integrated with the warning system
required in paragraph (13)(A) of this subsection. Fire detection shall consist
of at least one of the following:
(i)
fire detectors;
(ii)
heat sensors, including meltdown and fused devices; or
(iii)
camera surveillance at facilities that are attended at
an on-site control room 24 hours per day.
(B)
Fire detectors shall be tested twice each calendar year
at intervals not to exceed 7 1/2 months and, when defective, repaired or replaced
within 10 days.
(C)
Within three years of the effective date of this section,
each storage wellhead in active storage service shall have fire suppression
capability designed to aid in personnel rescue and for equipment protection
and cooling. Within one year of the effective date of this section, the operator
may request an exception to the schedule or fire suppression requirement of
this subparagraph and propose an alternative schedule or means of protection
from wellhead fire for approval of the Commission or its designee.
(8)
Emergency response plan. Each storage facility shall submit
to the Commission a written emergency response plan. The plan shall address
spills and releases, fires, fire suppression capability, explosions, loss
of electricity, and loss of telecommunication services. The plan shall describe
the storage facility's emergency response communication system, procedures
for coordination of emergency communication and response activities with local
emergency planning committees and other local authorities, use of warning
systems, procedures for citizen and employee emergency notification and evacuation,
and employee training. The initial plan must be designed based upon the existing
safety measures at the facility. The plan shall be updated as changes in safety
features at the facility occur, or as the Commission or its designee requires.
The plan shall include a plat of the facility that shows the location of wells,
processing areas, loading racks, brine pits, and other significant features
at the site. A copy of the plan shall be provided to the local emergency response
planning committee and to any other local governmental entity that submits
a written request for a copy of the plan to the operator. Copies of the plan
shall also be available at the storage facility and at the company headquarters.
(9)
Notification of emergency or uncontrolled release.
(A)
Emergency response personnel. Each operator shall notify
the county sheriff's office, the county emergency management coordinator,
and any other appropriate public officials, which are identified in the emergency
response plan, of any emergency that could endanger nearby residents or property.
Such emergencies include, but are not limited to, an uncontrolled release
of hydrocarbons from a storage well, or a leak or fire at any area of the
storage facility. The operator shall give notice as soon as practicable following
the discovery of the emergency. At the time of the notice, the operator shall
report an assessment of the potential threat to the public.
(B)
Commission. The operator shall report to the appropriate
Commission district office as soon as practicable any emergency, significant
loss of fluids, significant mechanical failure, or other problem that increases
the potential for an uncontrolled release. The operator shall file with the
Commission within 30 days of the incident a written report on the root cause
of the incident. The operator shall file with the Commission within 90 days
of the incident a written report that describes the operational changes, if
any, that have been or will be implemented to reduce the likelihood of a recurrence
of a similar incident. An operator may request that the Commission grant,
for good cause, a reasonable amount of additional time to file a written report
on the root cause of the incident.
(10)
Public education. Each facility operator shall establish
a continuing educational program to inform residents within a one-mile radius
of a hydrocarbon storage facility of emergency notification and evacuation
procedures.
(11)
Annual emergency drill. Annually, each operator shall
conduct a drill that tests response to a simulated emergency. Written notice
of the drill shall be provided to the appropriate Commission district office,
the county emergency management coordinator, and the county sheriff's office
at least seven days prior to the drill. Local emergency response authorities
shall be invited to participate in all such drills. The operator shall file
a written evaluation of the drill and plans for improvements with the appropriate
district office and the county emergency management coordinator within 30
days after the date of the drill.
(12)
Employee safety training.
(A)
Each operator shall prepare and implement a plan to train
and test each employee at each underground hydrocarbon storage facility on
operational safety to the extent applicable to the employee's duties and responsibilities.
The facility's emergency response plan shall be included in the training program.
(B)
Each operator shall hold a safety meeting with each contractor
prior to the commencement of any new contract work at an underground hydrocarbon
storage facility. Emergency measures, including safety and evacuation measures
specific to the contractor's work, shall be explained in the contractor safety
meeting.
(13)
Warning systems and alarms.
(A)
All leak detectors, fire detectors, heat sensors, pressure
sensors, and emergency shutdown instrumentation shall be integrated with warning
systems that are audible and visible in the local control room and at any
remote control center. The circuitry shall be designed so that failure of
a detector or heat sensor, excluding meltdown and fused devices, to function
will activate the warning.
(B)
A manually operated alarm shall be installed at each attended
storage facility. The alarm shall be audible in areas of the facility where
personnel are normally located.
(14)
Wind socks. At least one wind sock that is visible at
any time from any normal work location within the storage facility shall be
installed at the facility.
(15)
Barriers. Barriers designed to prevent unintended impact
by vehicles and equipment shall be placed around above-grade hydrocarbon piping,
hydrocarbon process equipment, and surface hydrocarbon storage vessels in
areas where vehicles may normally be expected to travel or within 100 feet
of a public road.
(16)
Wellhead, surface piping, and associated valves. All wellhead
equipment, product, fresh water, and brine surface piping, and associated
valves shall be designed, installed, and operated in accordance with engineering
standards to the expected service conditions to which the piping and equipment
will be subjected.
(i)
Cavern capacity and configuration.
(1)
Crude oil storage. The provisions of this subsection shall
not apply to underground hydrocarbon storage facilities where only crude oil
is stored.
(2)
Before storage operations begin. The capacity and configuration
of each hydrocarbon storage cavern (both salt domes and bedded salt) shall
be determined by sonar survey before storage operations begin in a newly completed
cavern.
(3)
Salt domes. The capacity and configuration of each salt
dome hydrocarbon storage cavern shall be determined by sonar survey at least
once every 10 years.
(4)
Bedded salt. The configuration of the roof of each hydrocarbon
storage cavern in bedded salt shall be determined by downhole log or an alternate
method approved by the Commission or its designee at least once every five
years.
(5)
Filing results. Sonar and roof monitoring survey results
shall be filed with the Commission within 30 days after the survey.
(6)
Out-of-service caverns. A sonar or roof monitoring survey
is not required for a cavern that is out of service. A sonar or roof monitoring
survey shall be performed before any cavern that has been out of service is
returned to service, unless the provisions of paragraph (2) of this subsection
apply.
(j)
Well completion, casing, and cementing. Hydrocarbon storage
wells shall be cased and the casing strings cemented to prevent fluids from
escaping to the surface or into fresh water strata, or otherwise escaping
and causing waste or endangering public safety or the environment.
(1)
New wells.
(A)
All hydrocarbon storage wells drilled in salt domes after
the effective date of this section shall have at least two casing strings
cemented into the salt formation. Sufficient cement shall be used to fill
the annular space outside the casing from the casing shoe to the ground surface,
or from the casing shoe to a point at least 200 feet above the shoe of the
previous casing string.
(B)
All hydrocarbon storage wells in bedded salt drilled after
the effective date of this section shall have all casing strings cemented
with sufficient cement to fill the annular space outside each casing string
from the casing shoe to the ground surface.
(2)
Well completion report. A well completion report shall
be filed in accordance with the instructions on the form prescribed by the
Commission within 30 days after a storage well is completed and before solution
mining to create the cavern begins.
(k)
Operating requirements.
(1)
Operating pressure. The operating pressure of each hydrocarbon
storage well shall not exceed the permitted maximum allowable operating pressure
for that well. The permitted maximum allowable operating pressure is that
pressure specified in the Commission permit or order, or, if not specified
in the permit or order, that pressure stated in the application or the application
for amendment to a permit or order. The maximum operating pressure at the
shoe of the lowermost cemented casing shall not exceed 0.8 pounds per square
inch per foot of depth.
(2)
Volume of hydrocarbons stored. The quantity of hydrocarbons
stored in a cavern shall not exceed the permitted maximum storage volume for
that cavern. The permitted maximum hydrocarbon storage volume is that volume
specified in the Commission permit or order, or, if not specified in the permit
or order, that volume stated in the application or the application for amendment
to a permit or order.
(l)
Monitoring requirements.
(1)
Pressures. Each hydrocarbon storage well shall be equipped
with pressure sensors that continuously monitor and display wellhead pressures
on both the product and brine sides of the wellhead at the control room. Each
hydrocarbon storage well with a safety string shall be equipped with a pressure
sensor and the sensor shall continuously monitor the pressure on the safety
string at the wellhead.
(2)
Pressure gauges. Each hydrocarbon storage well shall be
equipped with gauges on both the brine and hydrocarbon sides of the wellhead.
(3)
Volumes injected and withdrawn. The volume of hydrocarbons
injected into and withdrawn from each hydrocarbon storage well shall be measured
by:
(A)
flow meter for each well; or
(B)
an alternate method approved by the Commission or its designee.
(4)
Measurement performance. The accuracy of hydrocarbon volume
measurement devices or methods required under paragraph (3) of this subsection
shall be verified at least once each year by a person who is not an officer
or employee of the owner or operator, or any affiliate of the owner or operator.
For purposes of this section, an affiliate is any person or entity that owns,
is owned by, or is under common ownership with the owner or the operator.
In the case of meters, verification includes witnessing meter calibration
or proving conducted by the owner or operator or an affiliate of the owner
or operator.
(5)
Data recording. Within three years of the effective date
of this section, operators shall have installed and have functioning equipment
to electronically record all liquid and gas pressures, volumes, and flow rates
at a frequency of at least once per minute, and all actuations of the emergency
shutdown valve.
(m)
Reporting. The operator shall report maximum wellhead pressures
on the hydrocarbon and brine sides of each hydrocarbon storage well and the
net volumes of hydrocarbons injected into and withdrawn from each hydrocarbon
storage well in accordance with the instructions on the annual report form
prescribed by the Commission.
(n)
Operations, construction, and maintenance records retention.
(1)
Hydrocarbon injection and withdrawal data.
(A)
The operator shall retain for at least three months all
electronic records of hydrocarbon storage well pressures, flow rates, and
hydrocarbon volumes injected into and withdrawn from each well, and the hydrocarbon
inventory of each cavern. These electronic data shall be recorded at a frequency
of at least once per minute.
(B)
The operator shall retain for at least five years the records,
reported to the Commission under subsection (m) of this section, of maximum
monthly wellhead pressures on the hydrocarbon and brine sides of each hydrocarbon
storage well and the monthly net volumes of hydrocarbons injected into and
withdrawn from each hydrocarbon storage well. These electronic data shall
be recorded at a frequency of at least once per day.
(2)
Records retention. The operator shall retain for at least
five years the records of measurement performance under subsection (l)(4)
of this section; and testing of safety devices under subsection (h) of this
section. Records of any test of a safety device required under subsection
(h) of this section shall be available for on-site inspection within 10 days
of the date of the test.
(3)
Construction and maintenance data. The operator shall retain
for the life of the facility documents and records pertaining to the drilling,
mining, completion, major repairs, and workovers of storage wells and testing
of storage well integrity, and shall transfer all such documents and records
to any new owner and/or new operator of the facility.
(4)
Extension during investigation. Any documents or records
that contain information pertinent to the resolution of any pending regulatory
enforcement proceeding shall be retained beyond the prescribed retention until
the resolution of such proceeding.
(o)
Testing and maintenance.
(1)
Integrity tests for wells in salt domes with a single casing
string. Each hydrocarbon storage well drilled into a salt dome and having
a single casing string cemented to the surface shall have the casing inspected
by mechanical, ultrasonic, or magnetic methods at least once every five years
and after each workover that involves physical changes to the cemented casing
string.
(2)
Integrity tests for wells other than those in salt domes
with a single casing string. Each hydrocarbon storage well shall be tested
for integrity prior to being placed into service, at least once every five
years, and after each workover that involves physical changes to any cemented
casing string. The following requirements apply to all such integrity tests.
(A)
A hydrocarbon storage well shall be tested for integrity
by the nitrogen-brine interface method or an alternative approved by the Commission,
or its designee.
(B)
A test procedure shall be filed with the Commission for
approval at least 10 days before the test date.
(C)
The operator shall notify the district office at least
five days prior to conducting any integrity test.
(D)
A complete record of each integrity test shall be filed
in duplicate with the district office within 30 days after testing is completed.
The record shall include a chronology of the test, copies of all downhole
logs, storage well completion information, pressure readings, volume measurements,
temperature logs and readings, and an explanation of the test results that
addresses the precision of the test in terms of a calculated leak rate.
(E)
Storage well pressures shall be allowed to stabilize to
a rate of change of less than 10 psi in 24 hours before the testing period
begins.
(3)
Storage wellhead and casing. Storage wellhead components
and casing shall be inspected at least once every 10 years for corrosion,
cracks, deformations or other conditions that may compromise integrity and
that may not be detected by the five-year test. The operator may request an
extension of up to five years from the Commission for good cause. Factors
the Commission may consider in determining good cause pursuant to this paragraph
include by are not limited to the age, location, and configuration of the
well; well and facility history; operator compliance record; operator efforts
to comply with this subsection; and accuracy of inventory control.
(4)
Product, fresh water, and brine surface piping. Within
one year of the effective date of this section, the operator shall submit
a piping integrity management plan for approval by the Commission or its designee.
Within three years of the effective date of this section, or in conjunction
with the storage well integrity testing, all product, freshwater, and brine
surface piping shall be maintained according to the facility's piping integrity
management plan.
(5)
Alternative monitoring. An operator may request the Commission
or its designee to approve storage well pressure monitoring as an alternative
to integrity testing for hydrocarbon storage wells that are out of storage
service. An out-of-service storage well must be tested for integrity according
to the procedures specified in paragraph (2) of this subsection before it
may be returned to storage service.
(p)
Plugging.
(1)
Plug on abandonment. A hydrocarbon storage well shall be
plugged upon permanent abandonment in a manner approved by the Commission
or its designee. A proposal for plugging shall be submitted to the Commission
in Austin for approval or modification prior to plugging. Following approval
of a plugging plan, the operator shall file a notification of intent to plug
at least five days prior to commencement of plugging operations. A plugging
report shall be filed with the Commission in Austin within 30 days after plugging.
(2)
Alternative monitoring. As an alternative to plugging a
hydrocarbon storage well that has been permanently deactivated, an operator
may request approval by the Commission or its designee of a plan to convert
the storage well to a monitor well. A pressure monitoring plan must be submitted
to the Commission along with the request to convert the storage well to a
monitoring well.
(q)
Penalties.
(1)
Penalties. Violations of this section may subject the operator
to penalties and remedies specified in the Texas Natural Resources Code, Titles
3 and 11, and other statutes administered by the Commission.
(2)
Certificate of compliance. The certificate of compliance
for any underground hydrocarbon storage facility may be revoked in the manner
provided in §3.73 of this title (relating to Pipeline Connection; Cancellation
of Certificate of Compliance; Severance).
(r)
Applicability of other Commission rules and orders. The
owner or operator of an underground hydrocarbon storage facility is not relieved
by this section of compliance with any other requirement of Chapters 3, 4,
7, or 8 of this title (relating to Oil and Gas Division; Environmental Protection;
Gas Services Division; or Pipeline Safety Regulations).
§3.97.Underground Storage of Gas in Salt Formations.
(a)
Definitions. The following terms, when used in this section,
shall have the following meanings, unless the context clearly indicates otherwise.
(1)
Affected person--A person who, as a result of actions proposed
in an application for a storage facility permit or amendment or modification
of an existing storage facility permit, has suffered or may suffer actual
injury or economic damage other than as a member of the general public.
(2)
Cavern--The storage space created in a salt formation by
solution mining.
(3)
Commission--The Railroad Commission of Texas.
(4)
Emergency shutdown valve--A valve that automatically closes
to isolate a gas storage wellhead from surface piping in the event of specified
conditions that, if uncontrolled, may cause an emergency.
(5)
Fresh water--Water having bacteriological, physical, and
chemical properties that make it suitable and feasible for beneficial use
for any lawful purpose. For purposes of this section, brine associated with
the creation, operation, and maintenance of an underground gas storage facility
is not considered fresh water.
(6)
Gas storage well or storage well--A well, including the
storage wellhead, casing, tubing, borehole, and cavern used for the injection
or withdrawal of natural gas or any other gaseous substance into or out of
an underground gas storage facility.
(7)
Leak or fire detector--A device capable of detecting by
chemical or physical means the presence of stored product gas or the escape
of stored product gas or the presence of flame or heat of a fire.
(8)
Operator--The person recognized by the Commission as being
responsible for the physical operation of an underground gas storage facility,
or such person's authorized representative.
(9)
Owner--The person recognized by the Commission as owning
all or part of an underground gas storage facility, or such person's authorized
representative.
(10)
Person--A natural person, corporation, organization, government,
governmental subdivision or agency, business trust, estate, trust, partnership,
association, or any other legal entity.
(11)
Pollution--Alteration of the physical, chemical, or biological
quality of, or the contamination of, water that makes it harmful, detrimental,
or injurious to humans, animal life, vegetation, or property, or to public
health, safety, or welfare, or impairs the usefulness or the public enjoyment
of the water for any lawful or reasonable purpose.
(12)
Storage wellhead--Equipment installed at the surface of
the wellbore, including the casinghead and tubing head, spools, block or wing
valves, and instrument flanges. Spool pieces must have a length less than
six feet to be considered a part of the storage wellhead.
(13)
Surface piping--Any pipe within a storage facility that
is directly connected to a storage well, outboard of the wellhead emergency
shutdown valve and used to transport gas, brine, or fresh water to or from
a storage well whether such pipe is above or below ground level.
(14)
Underground gas storage facility or storage facility--A
facility used for the storage of natural gas or any other gaseous substance
in an underground salt formation, including surface and subsurface rights,
appurtenances, and improvements necessary for the operation of the facility.
(b)
Permit required.
(1)
General. No person may create, operate, or maintain an
underground gas storage facility without obtaining a permit from the Commission.
A permit issued by the Commission for such activities before the effective
date of this section shall continue in effect until revoked, modified, or
suspended by the Commission, or until it expires according to its terms. The
provisions of this section apply to permits to conduct gas storage operations
issued prior to the effective date of this section, except as otherwise specifically
provided.
(2)
Conflict with other requirements. If a provision of this
section conflicts with any provision or term of a Commission order, field
rule, or permit, the provision of such order, field rule, or permit shall
control.
(c)
Application.
(1)
Information required. An application for a permit to create,
operate, or maintain an underground gas storage facility shall be filed with
the Commission by the owner or operator, or the proposed owner or operator,
on the prescribed form. The application shall contain the information necessary
to demonstrate compliance with applicable state laws and Commission regulations.
(2)
Permit amendment. An application for amendment of an existing
underground gas storage facility permit shall be filed with the Commission:
(A)
prior to any planned enlargement of a cavern in excess
of the permitted cavern capacity by solution mining;
(B)
when required in accordance with paragraph (3) of this
subsection;
(C)
prior to the drilling of any additional storage wells;
(D)
prior to an increase in the maximum operating pressure
above the permitted pressure; or
(E)
any time that conditions at the storage facility deviate
materially from the conditions specified in the permit or permit application.
(3)
Increase in capacity. The owner or operator of a storage
facility shall notify the Commission if information indicates that the capacity
of a cavern exceeds the permitted cavern capacity by 20% or more. Such notification
shall be made in writing to the Commission within 10 days of the date that
the owner or operator of the storage facility knows or has reason to know
that the cavern capacity exceeds the permitted capacity by 20% or more. The
notification shall include a description of the information that indicates
that the permitted cavern capacity has been exceeded, and an estimate of the
current cavern capacity. Upon receipt of such information, the Commission
or its designee may take any one or more of the following actions:
(A)
require the permittee to comply with a compliance schedule
that lists measures to be taken to ensure that conditions at the storage facility
do not pose a danger to life or property, and that no waste of gas, uncontrolled
escape of gas, or pollution of fresh water occurs;
(B)
require the permittee to file an application to amend the
underground gas storage facility permit;
(C)
modify, cancel, or suspend the permit as provided in subsection
(f) of this section; or
(D)
take enforcement action.
(d)
Standards for underground storage zone.
(1)
Geologic, construction, and operating performance. An underground
gas storage facility may be created, operated, or maintained only in an impermeable
salt formation in a manner that will prevent waste of the stored gases, uncontrolled
escape of gases, pollution of fresh water, and danger to life or property.
This section does not authorize storage of liquid or liquefied hydrocarbons
in an underground salt formation. A permit under §3.95 of this title
(relating to Underground Storage of Liquid or Liquefied Hydrocarbons in Salt
Formations) is required to convert from storage of natural gas to storage
of liquid or liquefied hydrocarbons in an underground salt formation.
(2)
Fresh water strata. The applicant must submit with the
application a letter from the Texas Commission on Environmental Quality or
its successor agencies stating the depth to which fresh water strata occur
at each storage facility.
(e)
Notice and hearing.
(1)
Notice requirements. The applicant shall, no later than
the date the application is mailed to or filed with the Commission, give notice
of an application for a permit to create, operate, or maintain an underground
hydrocarbon storage facility, or to amend an existing storage facility permit,
by mailing or delivering a copy of the application form to:
(A)
the surface owner of the tract where the storage facility
is located or is proposed to be located;
(B)
the surface owner of each tract adjoining the tract where
the storage facility is located or is proposed to be located;
(C)
each oil, gas, or salt leaseholder, other than the applicant,
of the tract on which the storage facility is located or is proposed to be
located;
(D)
each oil, gas, or salt leaseholder of any tract adjoining
the tract on which the storage facility is located or is proposed to be located;
(E)
the county clerk of the county or counties where the storage
facility is located or is proposed to be located; and
(F)
if the storage facility is located or is proposed to be
located within city limits, the city clerk or other appropriate city official.
(2)
Publication of notice. Notice of the application, in a
form approved by the Commission or its designee, shall be published by the
applicant once a week for three consecutive weeks in a newspaper of general
circulation in the county where the storage facility is or is proposed to
be located. The applicant shall file proof of publication prior to any hearing
on the application or administrative approval of the application.
(3)
Notice by publication. The applicant shall make diligent
efforts to ascertain the name and address of each person identified under
paragraph (1)(A) - (D) of this subsection. The exercise of diligent efforts
to ascertain names and addresses of such persons shall require an examination
of the county records where the facility is located and an investigation of
any other information of which the applicant has actual knowledge. If, after
diligent efforts, the applicant has been unable to ascertain the name and
address of one or more persons required to be notified under paragraph (1)(A)
- (D) of this subsection, the notice requirements for those persons are satisfied
by the publication of the notice of application as required in paragraph (2)
of this subsection. The applicant must submit an affidavit to the Commission
specifying the efforts that were taken to identify each person whose name
and/or address could not be ascertained.
(4)
Hearing required for new permits. A permit application
for a new underground gas storage facility will be considered for approval
only after notice and hearing. The Commission will give notice of the hearing
to all affected persons, local governments, and other persons who express,
in writing, an interest in the application. After hearing, the examiner shall
recommend a final action by the Commission.
(5)
Hearing on permit amendments.
(A)
An application for an amendment to an existing storage
facility permit may be approved administratively if the Commission receives
no protest from a person notified pursuant to paragraph (1) of this subsection
or from any other affected person.
(B)
If the Commission receives a protest from a person notified
pursuant to paragraph (1) of this subsection or from any other affected person
within 15 days of the date of receipt of the application by the Commission,
or of the date of the third publication, whichever is later, or if the Commission
determines that a hearing is in the public interest, then the applicant will
be notified that the application cannot be approved administratively. The
Commission will schedule a hearing on the application upon written request
of the applicant. The Commission will give notice of the hearing to all affected
persons, local governments, and other persons who express, in writing, an
interest in the application. After hearing, the examiner shall recommend a
final action by the Commission.
(C)
If the application is administratively denied, a hearing
will be scheduled upon written request of the applicant. After hearing, the
examiner shall recommend a final action by the Commission.
(f)
Modification, cancellation, or suspension of a permit.
(1)
General. Any permit may be modified, suspended, or canceled
after notice and opportunity for hearing if:
(A)
a material change in conditions has occurred in the operation,
maintenance, or construction of the storage facility, or there are material
deviations from the information originally furnished to the Commission. A
change in conditions at a facility that does not affect the safe operation
of the facility or the ability of the facility to operate without causing
waste of hydrocarbons or pollution is not considered to be material;
(B)
pollution of fresh water is likely as a result of continued
operation of the storage facility;
(C)
there are material violations of the terms and provisions
of the permit or Commission regulations;
(D)
the applicant has misrepresented any material facts during
the permit issuance process; or
(E)
injected fluids are escaping or are likely to escape from
the storage facility.
(2)
Imminent danger. Notwithstanding the provisions of paragraph
(1) of this subsection, in the event of an emergency that presents an imminent
danger to life or property, or where waste of hydrocarbons, uncontrolled escape
of hydrocarbons, or pollution of fresh water is imminent, the Commission or
its designee may immediately suspend a storage facility permit until a final
order is issued pursuant to a hearing, if any, conducted in accordance with
the provisions of paragraph (1) of this subsection. All operations at the
facility shall cease upon suspension of a permit under this paragraph.
(g)
Transfer of permit. A storage facility permit may not be
transferred without the prior approval of the Commission, or its designee.
Until such transfer is approved by the Commission or its designee, the proposed
transferee may not conduct any activities authorized by the permit. The following
procedure shall be followed when requesting approval for transfer of a permit.
(1)
Request. Prior to transferring either ownership or operation
of a storage facility, the permittee shall file with the Commission a request
for transfer of the permit. Such a request may not be filed unless a completed
Form P-4, signed by both the permittee and the proposed transferee, has been
filed with the Commission.
(2)
Approval. The Commission, or its designee, shall approve
the transfer of a storage facility permit, provided:
(A)
the proposed transferee is not the subject of any unsatisfied
Commission enforcement order at the time of the request for permit transfer;
and
(B)
there are no existing violations of any Commission regulation,
order, or permit at the storage facility at the time of the request for permit
transfer that have been documented by the Commission, or its employees, unless
the proposed transferee agrees to correct the violations according to a compliance
schedule approved by the Commission, or its designee.
(3)
Good cause. Notwithstanding paragraph (2) of this subsection,
for good cause shown the Commission, or its designee, may require public notice
and opportunity for hearing prior to taking action on a request for transfer
of a permit. Such request may be denied after notice and opportunity for hearing
if the Commission or its designee finds that transfer of the permit would
not be in the public interest.
(h)
Safety. The following safety requirements shall apply to
all underground gas storage facilities, provided, however, that the provisions
of this subsection shall not apply to any natural gas storage well that is
out of service and disconnected from surface piping. Notwithstanding the compliance
time periods specified in this subsection, a new underground gas storage facility
permitted under this section must have all required safety measures and equipment
in place before commencement of storage operations at the facility. All existing
storage facilities must have such safety measures and equipment in place within
the period of time specified. Notwithstanding the compliance time periods
specified in paragraph (2)(B) of this subsection, no storage well in active
service may be operated without a fully functional emergency shutdown valve
unless in compliance with specified conditions of paragraph (2)(C) of this
subsection.
(1)
Monitoring of injection and withdrawal operations. All
gas injection and withdrawal activities shall be continuously monitored by
an individual who is experienced and trained in such activities. Any facility
that is unattended during injection and withdrawal activities shall have company
personnel on call at all times. On-call personnel must be able to reach the
facility within 30 minutes from the time a potential problem is noted by the
individual monitoring the injection or withdrawal activities.
(2)
Storage wellhead.
(A)
The storage wellhead must be designed, operated, and maintained
to contain the contents of the storage well and protect against loss of stored
product.
(B)
Within five years of the effective date of this section,
the operator shall have installed emergency shutdown valves between the wellhead
and the gas injection/withdrawal surface piping of each storage well and between
the wellhead and any brine or fresh water surface piping. Within one year
of the effective date of this section, the operator may request an exception
to the storage wellhead configuration or compliance date of this subparagraph
and propose an alternative configuration or workover schedule for approval
by the Commission or its designee. A storage well that is out of service and
is disconnected from surface piping shall be exempt from this requirement
until reactivated for active gas storage. Emergency shutdown valves shall
meet the following requirements:
(i)
Each emergency shutdown valve shall be capable of activation
at each storage well, at the on-site control center if one exists, at the
remote control center if one exists, and at a location that is reasonably
anticipated to be accessible to emergency response personnel at any facility
that does not have an on-site control center that is attended 24 hours per
day.
(ii)
Each emergency shutdown valve shall be an automatic fail-closed
valve that automatically closes when there is a loss of pneumatic or hydraulic
pressure on, or power to, the valve or when the maximum operating pressure
under subsection (k) of this section is exceeded.
(iii)
Each emergency shutdown valve shall be closed and opened
at least monthly.
(iv)
Each emergency shutdown valve system shall be tested at
least twice each calendar year at intervals not to exceed 7 1/2 months. The
test shall consist of activating the actuation devices, checking the warning
system, and observing the valve closure.
(C)
If an emergency shutdown valve system fails to operate
as required, the well shall be immediately shut in until repairs are completed,
unless:
(i)
a backup emergency shutdown valve is in operation on the
same piping; or
(ii)
an attendant is posted at the well site to provide immediate
manual shut-in.
(3)
Gas, brine, and fresh water surface piping.
(A)
Gas surface piping shall be designed for the permitted
maximum allowable operating pressure on the hydrocarbon side of the well.
For facilities with hazardous materials surface piping under the administrative
authority of the Safety Division of the Railroad Commission of Texas, for
the purposes of this section, gas surface piping extends from the wellhead
emergency shutdown valve to the first pressure regulation device, including
a manual, motor-operated, or emergency shutdown valve.
(B)
Brine piping, if any, shall be designed for the maximum
brine wellhead pressure and to transport, under emergency conditions, gas
to a gas control system if the operator is solution mining while the gas storage
well is in active storage service, unless:
(i)
a secondary emergency shutdown valve is in operation on
the brine surface piping; and
(ii)
the brine surface piping between the wellhead emergency
shutdown valve and the secondary emergency shutdown valve is designed for
the permitted maximum allowable operating pressure on the hydrocarbon side
of the well.
(C)
Fresh water surface piping, if any, must be equipped with
an emergency shutdown valve unless it is:
(i)
disconnected from the wellhead; or
(ii)
connected to the brine surface piping outboard of the
wellhead emergency shutdown valve; or
(iii)
designed for the maximum allowable operating pressure
on the hydrocarbon side of the well; and has an internal diameter of less
than or equal to two inches; and an attendant is posted at the well site to
provide immediate manual shut-in when in use.
(D)
Fresh water piping designed for the permitted maximum allowable
operating pressure on the hydrocarbon side of the well and with an internal
diameter of less than or equal to two inches, is exempt from the requirement
that an emergency shutdown valve be separated from the wellhead by a spool
no longer than six feet.
(4)
Cavern debrining and solution mining operations.
(A)
Within one year of the effective date of this section,
each storage well shall have two or more of the following redundant devices
or methods in operation during cavern debrining operations or during solution
mining operations that are conducted with gas in storage in the same cavern.
These devices are designed to prevent the release of gas into the brine and
fresh water systems connected to the well during cavern debrining operations
or during solution mining operations that are conducted with gas in storage
in the same cavern. Gas release prevention shall consist of at least two of
the following redundant devices or methods:
(i)
emergency shutdown valves equipped with pressure sensor
switches or transducers set to automatically close emergency shutdown valves
on the brine side of the wellhead and on the fresh water piping, if any, in
response to preset pressures on the brine and fresh water piping of the well;
(ii)
weep hole(s) on the brine return string in conjunction
with a preset pressure sensor switch or transducer on the brine piping that
is set to automatically close emergency shutdown valves on the brine side
of the wellhead and on the fresh water piping, if any, in response to a preset
pressure;
(iii)
a device on the brine return string or brine piping that
detects hydrocarbon in the brine by physical or chemical characteristics and
that is set to automatically close emergency shutdown valves on the brine
side of the wellhead and on the fresh water piping, if any, in response to
hydrocarbon detection;
(iv)
an instrument that detects a rapid increase in the brine
flow rate indicative of hydrocarbon in the brine and that is set to automatically
close emergency shutdown valves on the brine side of the wellhead and on the
fresh water piping, if any, in response to a preset flow rate or differential
flow rate; or
(v)
an alternative device or method approved by the Commission.
(B)
Solution mining of a cavern may occur while gas is in storage,
provided that the injection of fresh water and the injection of gas do not
occur simultaneously within the same cavern.
(5)
Leak or fire detectors.
(A)
Within two years of the effective date of this section,
a leak or fire detector shall be installed and in operation at each gas storage
well and each structurally enclosed compressor site.
(B)
Leak or fire detectors shall be tested twice each calendar
year at intervals not to exceed 7 1/2 months, and, when defective, repaired
or replaced within 10 days. Leak or fire detectors shall be integrated with
warning systems required in paragraph (6)(A) of this subsection.
(6)
Warning systems and alarms.
(A)
Within two years of the effective date of this section,
all leak or fire detectors and sensors or methods that actuate the emergency
shutdown valve shall be integrated with warning systems that are audible and
visible in the control room and at any remote control center. The circuitry
shall be designed so that failure of a leak or fire detector to function will
activate the warning.
(B)
A manually operated audible alarm shall be installed at
each attended storage facility. The alarm shall be audible in areas of the
facility where personnel are normally located.
(7)
Emergency response plan. Each storage facility shall submit
to the Commission a written emergency response plan. The plan shall address
gas releases, fires, fire suppression capability, explosions, loss of electricity,
and loss of telecommunication services. The plan shall describe the facility's
emergency response communication system, procedures for coordination of emergency
communication and response activities with local authorities, use of warning
systems, procedures for citizen and employee emergency notification and evacuation,
and employee training. The plan shall also include a plat of the facility
showing the locations of wells, processing areas, and other significant features
at the facility. The initial plan must be designed based upon the existing
safety measures at the facility. The plan shall be updated as changes in safety
features at the facility occur, or as the Commission or its designee requires.
A copy of the plan shall be provided to the local emergency response committee
and to any other local governmental entity that submits a written request
for a copy of the plan to the operator. Copies of the plan shall also be available
at the storage facility and at the company headquarters.
(8)
Notification of emergency or uncontrolled release.
(A)
Emergency response personnel. Each operator shall notify
the county sheriff's office, the county emergency management coordinator,
and any other appropriate public officials which are identified in the emergency
response plan of any emergency that could endanger nearby residents or property.
Such emergencies include, but are not limited to, an uncontrolled release
of hydrocarbons from a storage well or a leak or fire at any area of the storage
facility. The operator shall give notice as soon as practicable following
the discovery of the emergency. At the time of the notice, the operator shall
also report an assessment of the potential threat to the public.
(B)
Commission. The operator shall report to the appropriate
Commission district office as soon as practicable any emergency, significant
loss of gas or fluids, significant mechanical failure, or other problem that
increases the potential for an uncontrolled release. The operator shall file
with the Commission within 30 days of the incident a written report on the
root cause of the incident. Within 90 days of the incident, the operator shall
file with the Commission a written report that describes the operational changes,
if any, that have been or will be implemented to reduce the likelihood of
a recurrence of a similar incident. An operator may request that the Commission
grant, for good cause, a reasonable amount of additional time to file a written
report on the root cause of the incident.
(9)
Annual emergency drill. Annually, each operator shall conduct
a drill that tests response to a simulated emergency. Written notice of the
drill shall be provided to the appropriate Commission district office, the
county emergency management coordinator, and the county sheriff's office at
least seven days prior to the drill. Local emergency response authorities
shall be invited to participate in all such drills. The operator shall file
a written evaluation of the drill and plans for improvements with the appropriate
district office and the county emergency management coordinator within 30
days after the date of the drill.
(10)
Employee safety training.
(A)
Each operator shall prepare and implement a plan to train
and test each employee at each underground gas storage facility on operational
safety to the extent applicable to the employee's duties and responsibilities.
The facility's emergency response plan shall be included in the training program.
(B)
Each operator shall hold a safety meeting with each contractor
prior to the commencement of any new contract work at an underground gas storage
facility. Emergency measures, including safety and evacuation measures specific
to the contractor's work, shall be explained in the contractor safety meeting.
(11)
Fire suppression capability.
(A)
Within three years of the effective date of this section,
each operator shall have fire suppression capability designed to aid in personnel
rescue and equipment protection and cooling.
(B)
Within one year of the effective date of this section,
the operator may request an exception to the schedule or fire suppression
requirement of this paragraph and propose an alternative schedule or means
of protection from wellhead fire for approval of the Commission or its designee.
(12)
Wellhead, piping, and associated valves. All wellhead
surface piping and associated valves shall be designed, installed, and operated
in accordance with engineering standards to the expected service conditions
to which the piping and equipment will be subjected.
(13)
Barriers. Within one year of the effective date of this
section, barriers designed to prevent unintended impact by vehicles and equipment
shall be placed around above grade hydrocarbon piping, hydrocarbon process
equipment where vehicles may normally be expected to travel, or within 100
feet of a public road.
(i)
Cavern capacity and configuration.
(1)
Before storage operations begin. The capacity and configuration
of each gas storage cavern (both salt domes and bedded salt) shall be determined
by sonar survey before storage operations begin in a newly completed cavern.
(2)
Salt domes. The capacity and configuration of each salt
dome gas storage cavern shall be determined by sonar survey before a cavern
that has been out of service is returned to service, provided, however, that
a sonar survey shall not be required on a cavern that is being returned to
service if a sonar survey of that cavern has been run at any time during the
previous 10 years.
(3)
Bedded salt. The configuration of the roof of each gas
storage cavern in bedded salt shall be determined by downhole log or an alternate
method approved by the Commission, or its designee, at least once every five
years.
(4)
Filing of results. Sonar and roof monitoring survey results
shall be filed with the Commission within 30 days after the survey.
(5)
Out-of-service caverns. A sonar or roof monitoring survey
is not required for a cavern that is out of service. A sonar or roof monitoring
survey shall be performed before any such cavern that has been out of service
is returned to service, unless the provisions of paragraph (2) of this subsection
apply.
(6)
Verification. Sonar surveys performed before debrining
shall be verified by metering the volume of the displaced brine.
(j)
Well completion, casing, and cementing. Gas storage wells
shall be cased and the casing strings cemented to prevent gases from escaping
to the surface or into fresh water strata, or otherwise escaping and causing
waste or endangering public safety or the environment.
(1)
New wells.
(A)
All gas storage wells drilled in salt domes after the effective
date of this section shall have at least two casing strings cemented into
the salt formation. Sufficient cement shall be used to fill the annular space
outside the casing from the casing shoe to the ground surface, or from the
casing shoe to a point at least 200 feet above the shoe of the previous casing
string.
(B)
All gas storage wells drilled in bedded salt after the
effective date of this section shall have all casing strings cemented with
sufficient cement to fill the annular space outside each casing string from
the casing shoe to the ground surface.
(2)
Well completion report. A well completion report shall
be filed in accordance with the instructions on the form prescribed by the
Commission within 30 days after a storage well is completed and before solution
mining to create the cavern begins.
(k)
Operating pressure.
(1)
Not to exceed maximum. The operating pressure of each gas
storage well shall not exceed the permitted maximum allowable operating pressure
for that well. The permitted maximum allowable operating pressure is that
pressure specified in the Commission permit or order, or, if not specified
in the permit or order, that pressure stated in the application or the application
for amendment to a permit or order.
(2)
At casing seat. The maximum operating pressure at the casing
seat shall not exceed 0.85 pounds per square inch per foot of depth.
(l)
Monitoring requirements.
(1)
Gas pressure. Gas pressure on the injection/withdrawal
casing or tubing or piping connected thereto shall be equipped with a pressure
sensor to continuously monitor the wellhead pressure. Pressure sensors shall
be integrated electronically with the warning systems, alarms, and emergency
shutdown valve actuation system as required in subsection (h)(2)(B) and (h)(6)(A)
of this section.
(2)
Pressure observation valves. The injection/withdrawal casing
or tubing shall be equipped with a pressure observation valve and gauge. The
wellhead shall be equipped with a pressure observation valve on each casing
annulus so that a gauge may be installed for pressure monitoring.
(3)
Volumes injected and withdrawn. The volume of gas injected
into and withdrawn from each storage well shall be measured by:
(A)
flow meter for each well; or
(B)
an alternate method approved by the Commission.
(4)
Meter calibration. Meters that measure the volume of gas
into storage and out of storage shall be recalibrated at least once each year.
(5)
Data recording. Within three years of the effective date
of this section, operators shall have installed and have functioning equipment
to electronically record all liquid and gas pressures and injection volumes
and rates at a frequency of at least once per minute, and all actuations of
the emergency shutdown valve.
(m)
Reporting.
(1)
Monthly reports. On or before the last day of each month,
the operator of each facility that stores gas to supply a public utility shall
file with the Commission a report showing the volume of gas placed into storage
and the volume of gas removed from storage at the storage facility, during
the preceding month. The report shall also state the total volume of gas in
storage on the first and last days of the preceding month. This report shall
be filed in a format acceptable to the Commission or its designee.
(2)
Annual reports. The operator shall file annually a status
report for each storage well in accordance with the instructions on the form
prescribed by the Commission.
(n)
Operations, construction, and maintenance records retention.
(1)
Operations data.
(A)
The operator shall retain for at least three months all
electronic records of storage well pressures, volumes of gases injected and
withdrawn, and the inventory of gas in storage. These electronic data shall
be recorded at a frequency of at least once per minute.
(B)
The operator shall retain for at least five years the records
reported to the Commission under subsection (m). These electronic data shall
be recorded at a frequency of at least once per day.
(2)
Records retention. The operator shall retain for at least
five years the records of measurement performance under subsection (l)(4)
of this section; and testing of safety devices under subsection (h) of this
section. Records of any test of a safety device required under subsection
(h) of this section shall be available for on-site inspection within 10 days
of the date of the test.
(3)
Construction and maintenance data. The operator shall retain
for the life of the facility documents and records pertaining to the drilling,
mining, completion, repair and workover of storage wells and the testing of
storage well integrity, and shall transfer all such documents and records
to any new owner and/or new operator of the facility.
(4)
Extension during investigation. The operator shall retain
beyond the prescribed retention period any documents or records that contain
operational data pertaining to the resolution of any pending regulatory enforcement
proceedings until the resolution of such proceedings.
(o)
Testing and maintenance.
(1)
Integrity tests. Each gas storage well shall be tested
for integrity prior to being placed into service, at least once every five
years, and after each workover that involves physical changes to any cemented
casing string. The following requirements apply to such integrity tests.
(A)
A test procedure shall be filed with the Commission for
approval at least 10 days before the test date.
(B)
The initial test conducted on a well prior to placing it
into service shall be performed using the nitrogen-interface test method or
an alternative method approved by the Commission or its designee.
(C)
The integrity test required to be conducted at least once
every five years on a well that has gas in storage may be performed using
pressure monitoring, provided:
(i)
the wellhead pressure is stabilized such that the effects
of ambient temperature on pressure have overtaken the effects of the last
injection or withdrawal on pressure;
(ii)
a downhole temperature log is run at the beginning and
at the end of the test period;
(iii)
the test period is a minimum of 72 hours; and
(iv)
the net gas volume change for the test period is calculated.
(D)
The operator shall notify the district office at least
five days prior to conducting any integrity test.
(E)
A complete record of each integrity test shall be filed
in duplicate with the district office within 30 days after testing is completed.
The record shall include a chronology of the test, copies of all downhole
logs, storage well completion information, pressure readings, volume measurements,
temperature logs and readings, and an explanation of the test results that
addresses the precision of the test in terms of a calculated leak rate.
(2)
Alternative monitoring. An operator may request the Commission
or its designee to approve well pressure monitoring as an alternative to integrity
testing for storage wells that are out of gas storage service. An out-of-service
well shall be tested for integrity by the nitrogen-interface method before
it may be returned to storage service.
(3)
Storage wellhead and casing. Storage wellhead components
and casing shall be inspected at least once every 15 years for corrosion,
cracks, deformations, or other conditions that may compromise integrity and
that may not be detected by the five-year test. The operator may request an
extension of up to five years from the Commission for good cause. Factors
the Commission may consider in determining good cause pursuant to this paragraph
include by are not limited to the age, location, and configuration of the
well; well and facility history; operator compliance record; operator efforts
to comply with this subsection; and accuracy of inventory control.
(4)
Fresh water, brine, and gas surface piping. Within one
year of the effective date of this section, the operator shall submit a piping
integrity management plan for approval by the Commission or its designee.
Within three years of the effective date of this section, or in conjunction
with the storage well integrity testing, all gas, freshwater, and brine surface
piping shall be maintained according to the facility's piping integrity management
plan.
(p)
Plugging.
(1)
Plug on abandonment. A gas storage well shall be plugged
upon permanent abandonment in a manner approved by the Commission or its designee.
A proposal for plugging shall be submitted to the Commission in Austin for
approval or modification prior to plugging. Following approval of a plugging
plan, the operator shall file notification of intent to plug at least five
days prior to commencement of plugging operations. A plugging report shall
be filed with the Commission within 30 days after plugging.
(2)
Alternative monitoring. As an alternative to plugging a
gas storage well that has been permanently deactivated, an operator may request
approval by the Commission or its designee of a plan to convert the well to
a monitor well. A pressure monitoring plan must be submitted to the Commission
along with the request to convert the well to a monitoring well.
(q)
Penalties.
(1)
Penalties. Violations of this section may subject the operator
to penalties and remedies specified in Texas Natural Resources Code, Title
3; Texas Utilities Code, Chapter 121; and other statutes administered by the
Commission.
(2)
Certificate of compliance. The certificate of compliance
for any underground gas storage facility may be revoked in the manner provided
in §3.73 of this title (relating to Pipeline Connection; Cancellation
of Certificate of Compliance; Severance) for violation of this section.
(r)
Applicability of other Commission rules and orders. The
owner or operator of an underground gas storage facility is not relieved by
this section of compliance with any other requirement of Chapters 3, 4, 7,
or 8 of this title (relating to Oil and Gas Division; Environmental Protection;
Gas Services Division; or Pipeline Safety Regulations).
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of
the Secretary of State on January 10, 2007.
TRD-200700086
Mary Ross McDonald
Managing Director
Railroad Commission of Texas
Effective date: January 30, 2007
Proposal publication date: July 21, 2006
For further information, please call: (512) 475-1295