Part 1.
RAILROAD COMMISSION OF TEXAS
Chapter 3.
OIL AND GAS DIVISION
16 TAC §3.95, §3.97
The Railroad Commission of Texas proposes 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. Consistent with the Commission's wish to further the goals of
safety and the prevention and control of pollution, the Commission proposes
the 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.
On August 19, 2004, a gas release and fire occurred at the Moss Bluff Hub
Partners Hydrocarbon Storage facility in Liberty County, Texas. The incident
occurred during "de-brining," when brine was being extracted from the cavern
through a well string at the same time as gas was injected into the cavern
through casing. Investigation revealed that the likely initiating event at
Moss Bluff was a separation of the brine string at or above 3724-feet below
the ground surface within the gas-bearing area of the storage cavern. Gas
entered the brine string, reached the surface, and flowed into the above-ground
brine piping. The emergency shut-down valve on the above-ground brine piping
appeared to have operated properly, because investigators recovered it in
the closed state. The evidence suggests that transient mechanical forces or
"water hammer" produced by the sudden pressure surge caused the surface piping
to fracture between the wellhead and the emergency shutdown valve. The break
occurred at a location in the piping that had experienced wall loss due to
internal corrosion. This break in the above-ground brine piping initially
fueled the fire. The geometry of the surface piping directed gas and fire
downward at the base of the wellhead, weakening the assembly that attached
the wellhead to the casing. Eventually the entire wellhead assembly separated
from the casings and was ejected to the side and gas began escaping vertically
through the production casing. The fire self-extinguished for approximately
28 seconds before reigniting.
Investigation of this incident revealed unexpectedly extensive internal
corrosion of the brine piping. This piping was transferred from service on
another storage well, installed, and successfully pressure tested in 2000.
Past experience had not indicated corrosion to be a problem. Inspection and
testing of such piping is not a requirement under current provisions of §3.95
and §3.97.
Two other incidents resulted in the surface release of stored liquefied
petroleum gas (LPG) in 2000 and crude oil in 2005 at underground liquid hydrocarbon
storage facilities in Texas. These incidents were associated with the remote
location of an emergency shutdown valve from the wellhead (crude oil release)
and water hammer-induced pressure transient rupture of the surface piping
nipple (LPG release).
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. These proposed amendments incorporate new requirements for integrity
management of surface piping, location of emergency shutdown valves, fire
suppression capabilities, data acquisition, and record retention.
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 has used the input from these forums in drafting
these proposed amendments.
The Commission proposes 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 proposes to amend 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 proposes to add two new definitions. The Commission proposes
to define 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 proposed 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 proposes to add 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 emergency shutdown valve, exclusive of tubing and casing,
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" are needed
because other proposed rule amendments specify that the 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 proposes to amend §3.95(c)(4) to specify that the required
permit by that section is necessary 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 proposes to amend §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 proposes substantive amendments to §3.95(h), relating
to safety. The Commission proposes to amend §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 Commission proposes to change
the heading of §3.95(h)(2) from "Emergency shutdown valves" to "Storage
wellhead" to reflect the fact that the Commission is proposing safety requirements
for the entire storage wellhead, not just the emergency shutdown valves. The
Commission proposes to amend §3.95(h)(2)(B) to require that, within three
years of the effective date of this rule or in conjunction with the next scheduled
mechanical integrity test of the storage well, the operator shall 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 also proposes that no product, brine, or fresh
water surface piping may be installed between the storage wellhead and the
emergency shutdown valve. The proposed amendment also allows an operator to
request, within one year of the effective date of the section, an exception
to the storage wellhead configuration or compliance date of this subparagraph
and propose an alternative configuration for approval by the Commission or
its designee.
The proposed amendment mandating the location of the emergency shutdown
valve directly between the wellhead and surface piping is intended to increase
the safety of the emergency shutdown system. The current rule does not address
the physical positioning 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 surface piping at liquid
hydrocarbon storage facilities operating at Mont Belvieu.
The Commission proposes 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 the product piping and to clarify that
the requirements in the paragraph apply to surface piping. The Commission
proposes to 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 Commission proposes to amend §3.95(h)(3)(B)
(formerly subparagraph (A)) 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.
The Commission proposes to amend §3.95(h)(3)(C) (redesignated from
subparagraph (B)) to clarify that the requirements in the subparagraph pertain
to fresh water surface piping, and to clarify the requirement that such piping
must be designed to withstand the permitted maximum allowable operating pressure
of the hydrocarbon side of the well unless it is equipped with an emergency
shut down valve.
The Commission proposes to amend §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. Currently,
the rule does 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 the failure of a single device does not disable
both methods of overfill detection. The Commission proposes to amend 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 proposes to amend §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 proposes
to amend subsection (h)(7), relating to fire detection devices or methods,
to add requirements for fire control systems and to delete reference to a
deadline that has already passed. The Commission proposes to add new subparagraph
(C) to require that, within three years of the effective date of the amendment,
fire suppression capability be available at each storage wellhead in active
storage service. The proposed new subparagraph allows an operator to request
Commission approval of an exception to this schedule or 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
towards 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 proposes to amend §3.95(h)(8), relating to emergency
response plan, to delete reference to a deadline that already has passed.
The Commission proposes to amend §3.95(h)(9)(B), relating to notification
of emergency or uncontrolled release, to require that an operator file with
the Commission, within 30 days of any emergency, significant loss of fluids,
significant mechanical failure, or other problem that increases the potential
for an uncontrolled release, a written report on the root cause of the incident,
and file with the Commission, within 90 days of an incident, a written report
describing the operational changes, if any, that will be implemented to reduce
the likelihood of the recurrence of a similar incident. The current rule requires
only written confirmation of an event within five working days of the event.
The proposed 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 proposes to amend §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 proposes to amend §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 current requirement
that barriers be placed where vehicles normally may be expected to travel.
The Commission proposes this amendment because at least one incident has occurred
when a driver lost control of a vehicle on a public road, allowing the vehicle
to leave the roadway, and impact surface piping at a gas storage facility.
The Commission proposes to add new subsection (h)(16), relating to wellhead,
surface piping, and related equipment, 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 subject. In addition, the Commission proposes to require that, within
one year of the effective date of the rule amendments, the operator must report
the Commission the particular engineering standards under which the wellhead
equipment, product, fresh water, and brine surface piping, and related equipment
are designed, installed, tested, maintained and operated.
The Commission proposes to amend subsection (k)(1) to clarify that the
operating pressure of each hydrocarbon storage well may not exceed the permitted
maximum allowable operating pressure. This proposed change is intended to
conform the rule language generally accepted use of the phrase "maximum allowable
operating pressure."
The Commission proposes to amend §3.95(l), relating to Monitoring
requirements, to add a new paragraph (5) on data recording, which would require
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 shall record emergency actuations of the emergency shutdown
valve. This increased frequency of data recording is needed to insure that
operators record sufficient information relating to physical conditions that
immediately precede an accident or incident to help diagnose root causes.
Experience with several incidents at hydrocarbon storage facilities has revealed
that operational data were not recorded at a sufficient frequency to help
diagnose the root cause of the incident.
The Commission proposes to change the heading of subsection (n) from "Records
retention" to "Operations, construction, and maintenance records retention."
The proposed amendments to this subsection would require that operators retain
electronic records of well pressures, flow rates, hydrocarbon volumes for
three months instead of five years. The proposed amendments also add to the
record keeping requirement for each well, flow rates and hydrocarbon volumes
and deletes interface levels from each well. Because these operational data
are primarily intended to diagnose accidents and incidents, long-term retention
is unwarranted. The Commission proposes to change the heading of subsection
(n)(2) 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 installation, inspection, maintenance, and testing of equipment
required under subsections (h) and (l), and to expand the record keeping requirements
to documents and records pertaining to drilling, mining, and completion of
storage wells. The extension of the retention period is prudent and necessary
to insure that critical information on well construction, well testing, and
safety equipment testing 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 test results, especially for tests that have recurrence
intervals of five years, such as mechanical integrity tests. Obviously, in
such 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 are
currently available, they will be preserved for the life of the facility,
and will pass to future owners or operators of the facilities should ownership
or operatorship of a facility be transferred.
The Commission proposes to change the heading of §3.95(o) from "Testing"
to "Testing and Maintenance." Proposed new subsection (o)(1), would require
that all hydrocarbon storage wells drilled into salt domes and having a single
casing string cemented to the surface to 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. Currently,
all operators of liquid hydrocarbon storage wells drilled into salt domes
and having 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 the permit conditions requiring such testing, the tests have detected
significant casing damage prompting the operators at four facilities to repair
the damage before a significant leak could occur. Nitrogen-brine mechanical
integrity tests are not capable of detecting most classes of casing damage.
The proposed 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 proposes to add a new paragraph (3) to subsection (o), relating
to storage wellhead, to require operators to inspect and pressure test storage
wellhead components to 125 percent of permitted maximum allowable operating
pressure in conjunction with the hydrocarbon storage well integrity test schedule.
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 proposes to add new paragraph (4) to subsection (o), relating
to product, freshwater, and brine surface piping. The new paragraph would
require, 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 or its designee for approval by
the Commission or its designee. This proposed 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 proposes amendments to §3.97, relating to Underground
Storage of Gas in Salt Formations. The Commission proposes amendments to §3.97(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 proposes to
amend the definition of "emergency shutdown valve" to substitute "wellhead"
for "well." The Commission proposes to amend 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 proposes to amend the
definition of "leak detector" to include "fire" detectors. Leak detectors
must be capable of detection by chemical or physical means the presence of
gas or the escape of gas or the presence of flame or heat of a fire. References
to "vapor" are deleted from the definition because the natural gas in a storage
cavern is not technically a vapor, because there is no natural gas liquid
in the system.
The Commission proposes to add 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 proposed language would limit 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 as was the case at the recent gas
release and fire at the gas storage facility described above. The Commission
proposes to define "surface piping" as any pipe within a storage facility
that is directly connected to a storage well, exclusive of tubing and casing,
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 such terms are not defined in the current
rule.
The Commission proposes to amend 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 proposes to amend §3.97(e)(3), relating to notice and
hearing, to correct a typographical error.
The Commission proposes to amend §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
proposes to amend §3.97(h)(2), relating to emergency shut down valves,
to change the title of the paragraph to "Storage wellhead" and to modify 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 proposes to add a requirement that there
may be no gas, brine, or fresh water piping between the wellhead and the emergency
shutdown valve. The new language would allow an operator to request an exception
to the storage wellhead configuration or compliance date and propose an alternative
configuration or workover schedule provided the request and alternative proposal
is are received within one year of the effective date of these amendments.
The Commission or its designee must approve any such request.
The proposed 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 current rule does 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 proposes to add new subsection (h)(3), relating to gas,
brine, and fresh water piping, which would require that gas surface piping
be designed for the permitted maximum allowable operating pressure on the
hydrocarbon side; that brine surface piping be designed for the maximum brine
wellhead pressure; and that fresh water and brine surface piping be either
isolated from the well or designed for the permitted maximum allowable operating
pressure on the hydrocarbon side. This language is parallel to §3.95(h)(3)(C)
for liquid storage wells where fresh water surface piping is more commonly
installed.
The Commission proposes to amend 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 debrining 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 proposes to amend renumbered §3.97(h)(4)(i) and (ii)
specifically to allow the use of pressure transducers in addition to pressure
switches.
The Commission proposes to change 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 proposes to delete 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." Currently, the rule requires 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 of the gas storage facility demonstrated the
potential for significant damage and risk to public heath and safety extends
beyond 100 yards from a well or compressor station. The Commission proposes
to make conforming amendments to subparagraph (B).
The Commission proposes to amend 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 proposes to amend renumbered subsection (h)(7) to remove
a reference to a deadline that has already passed.
The Commission proposes to amend 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 would require that the operator file with
the Commission within 30 days of an incident a written report on the root
cause of the incident and file with the Commission within 90 days of an incident
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.
This language would replace the current requirement that requires that the
operator report a significant loss of fluids and confirm the report in writing
within five working days.
The Commission proposes to add 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 to protect each wellhead and compression station, 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 directed towards 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 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 proposes to add 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 related equipment
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 subject. In addition, within one year of
the effective date of these amendments, the operator must report to the Commission
the particular engineering standards under which wellhead equipment, gas,
fresh water, and brine surface piping and related equipment are designed,
installed, tested, maintained, and operated.
The Commission further proposes to add a new paragraph (13) to subsection
(h), relating to barriers, which would require 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. The Commission proposes this
amendment because at least one incident has occurred when a driver lost control
of a vehicle on a public road, allowing the vehicle to leave the roadway,
and impact above ground piping at a gas storage facility.
The Commission proposes to make other conforming amendments to subsection
(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 proposes to amend §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 proposes to amend §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 in §3.97(h). The Commission also proposes to add a
new paragraph (5), relating to data recording, which would require 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 emergency actuations of the emergency
shutdown valve. This proposed amendment is designed to aid in the analysis
of upset conditions by requiring operators to record operational data at relatively
high frequency. 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 proposes to change the title of §3.97(n) from "Records
retention" to "Operations, construction, and maintenance records retention,"
and to propose new records retention requirements. The Commission proposes
to change the title of paragraph (1) from "Gas injection and withdrawal data"
to "Operations data," and to amend this subsection to require that operators
retain electronic records of well pressures, flow rates, gas volumes for three
months instead of five years. Because these operational data are intended
primarily to diagnose accidents and incidents, long-term retention is unwarranted.
The Commission proposes to change the title of paragraph (2) 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, and completion of storage wells and the maintenance and testing of
safety equipment 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,
well testing, and safety equipment and testing is 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, especially tests that have
recurrence intervals of five years, such as mechanical integrity tests. Obviously,
in such 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 should ownership
or operatorship of a facility be transferred.
The Commission proposes to amend §3.97(o), relating to Testing, to
change the title to "Testing and maintenance." The Commission proposes to
add a new paragraph (3), relating to "Storage wellhead," 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 proposes to add a new paragraph (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 for approval by the Commission or its designee.
This proposed 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.
Leslie Savage, Planning and Administration, Oil and Gas Division, has determined
that for each year of the first five years the proposed amendments will be
in effect, the fiscal implications as a result of enforcing or administering
amended §3.95 and §3.97 will be negligible.
There will be no fiscal implications for local governments.
Texas Government Code, §2006.002 requires a state agency considering
adoption of a rule that would have an adverse economic effect on small businesses
or micro-businesses to reduce the effect if doing so is legal and feasible
considering the purpose of the statutes under which the rule is to be adopted.
Before adopting a rule that would have an adverse economic effect on small
businesses, a state agency must prepare a statement of the effect of the rule
on small businesses, which must include an analysis of the cost of compliance
with the rule for small businesses and a comparison of that cost with the
cost of compliance for the largest businesses affected by the rule, using
cost for each employee, cost for each hour of labor, or cost for each $100
of sales.
Ms. Savage has determined that the proposed amendments would not affect
any small or micro-businesses so there would be no cost of compliance for
small businesses or micro-businesses. However, Commission staff has attempted
to calculate the anticipated average economic cost of upgrading facilities
to meet the proposed amendments to §3.95 and §3.97. Currently, there
are 54 facilities in Texas at which liquid or liquefied hydrocarbons are stored
in underground salt formations. There are approximately 497 storage wells
at these 54 facilities. Many of these facilities already have in place the
additional safety equipment that would be required under these proposed amendments.
The Commission sent a survey to the operators of these facilities to determine
the current equipment status and piping configuration at liquid hydrocarbon
storage facilities, and the responses indicate that at least 29 percent and
up to 37 percent of the liquid storage wells have emergency shutdown valves
that already are located between the wellhead and surface piping or are attached
to spool pieces. In addition, 89 percent of the wells associated with liquid
storage operations have some form of fire suppression capability. Fire or
leak detection devices already are required at wells in liquid hydrocarbon
storage service, whereas only gas storage wells near public schools, churches
or public areas are currently required to have leak or fire detection devices.
Most operators of liquid hydrocarbon storage facilities have some mechanism
in place to verify the integrity of surface piping. Responses to the Commission's
survey indicate that the operators of only 11 percent of the liquid hydrocarbon
storage wells did not have a surface piping integrity management plan or did
not know if a plan existed.
These statistics show that for the new safety proposals being contemplated
in this rulemaking, a significant number of operators of liquid hydrocarbon
storage wells already have met the proposed new requirements in this rulemaking.
The total anticipated average economic cost of complying with amendments
regarding reinstalling emergency shutdown valves, installing fire monitors,
and fire detectors during the first three years the section is in effect is
estimated to exceed $4,000,000 for all of the 40 existing liquid hydrocarbon
storage facilities and is estimated to exceed $1,000,000 for all of the 14
existing natural gas storage facilities. The Commission determined this anticipated
average economic cost based upon information submitted to the Commission in
response to the 2005 survey, and upon assumptions regarding costs of safety
equipment and devices required under proposed amendments to §3.95. The
Commission was unable to estimate the cost of complying with new requirements
regarding data recording and retention.
In comparison to the estimated anticipated costs of complying with the
proposed new requirement, the failure of a single gas storage well at a gas
storage facility resulted in the loss of five billion cubic feet of gas at
an estimated cost of $30,000,000. Damage to the surrounding facility is estimated
to be in the millions of dollars.
Based on the response of operators of facilities storing natural gas in
salt caverns to the Commission's survey, at least 58 percent and up to 75
percent of gas storage wells currently have emergency shutdown valves that
already are located between the wellhead and surface piping or are attached
to spool pieces. In addition, 36 percent of the gas storage wells have some
form of fire suppression capability. Fire or leak detection devices already
are required at wells in liquid storage service, whereas only gas storage
wells near public schools, churches or public areas are required to have leak
or fire detection devices. Currently, although no gas storage wells are located
near public schools, churches or public areas, approximately 30 percent of
the wells are protected by such devices.
Operator responses to the survey indicate that for all the major new safety
proposals being contemplated, a significant number of operators of gas storage
wells already have implemented many of the proposed amendments.
Ms. Savage has determined that for each year of the first five years that
the amendments will be in effect the primary public benefit will be an increase
in the safety of persons living and working in areas where liquid or liquefied
hydrocarbons or natural gas or other gases are stored in underground formations.
In addition, these amendments will increase safety of personal or public property
located in such areas.
Comments on the proposal may be submitted to Rules Coordinator, Office
of General Counsel, Railroad Commission of Texas, P.O. Box 12967, Austin,
Texas 78711-2967; online at www.rrc.state.tx.us/rules/commentform.html; or
by electronic mail to rulescoordinator@rrc.state.tx.us. The Commission specifically
solicits comments regarding the estimated anticipated costs of the proposed
amendments. The Commission will accept comments for 30 days after publication
in the
Texas Register
. Comments should refer
to Oil and Gas Docket No. 20-0245837. The Commission encourages all interested
persons to submit comments no later than the deadline. The Commission cannot
guarantee that comments submitted after the deadline will be considered. For
further information, call Dr. Steve Seni at (512) 475-4439. The status of
Commission rulemakings in progress is available at www.rrc.state.tx.us/rules/proposed.html.
The Commission proposes 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 proposed
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 February 7, 2006.
§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) - (4)
(No change.)
(5)
Emergency shutdown valve--A valve that automatically closes
to isolate a hydrocarbon storage
wellhead
[
(6) - (7)
(No change.)
(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) - (15)
(No change.)
(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 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 emergency
shutdown valve, and exclusive of tubing and casing, 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)
[
(b)
(No change.)
(c)
Application.
(1) - (3)
(No change.)
(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
[
(d)
Standards for underground storage zone.
(1)
Geologic, construction, and operating performance
[
(2)
(No change.)
(e) - (g)
(No change.)
(h)
Safety. The following safety requirements shall apply to
all underground hydrocarbon storage facilities, except as specifically provided
otherwise. Provided, however, 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 [
(1)
(No change.)
(2)
Storage wellhead
[
(A)
The requirements of this paragraph do not apply to underground
hydrocarbon storage facilities storing only crude oil.
(B)
Within
three
[
(i) - (iv)
(No change.)
(C)
(No change.)
(3)
Product, brine,
[
(A)
Product surface piping shall be designed
for the permitted maximum allowable operating pressure on the hydrocarbon
side of the well.
(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.
[(A)
Brine piping from the wellhead to the
emergency shutdown valve shall be designed for the maximum wellhead pressure
on the hydrocarbon side of the well.]
(C)
[
(i)
isolated from the wellhead when fresh water is not being
injected into the well; or
(ii)
designed for the
permitted
maximum
allowable
operating
[
(4)
Overfill detection and automatic shut-in methods.
(A) - (B)
(No change.)
(C)
Within one year of the effective date of this section,
each storage cavern shall have at least
two
[
(i)
(No change.)
(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) - (v)
(No change.)
(5)
Leak detectors.
(A)
(No change.)
(B)
A
[
(C)
Leak
[
(D)
(No change.)
(6)
Brine system gas vapor control.
(A)
(No change.)
(B)
Gas
[
(i) - (iv)
(No change.)
(C)
(No change.)
(7)
Fire detection devices or methods
and fire control
systems
.
(A)
Fire
[
(i) - (iii)
(No change.)
(B)
(No change.)
(C)
Within three years of the effective date
of this section, each storage wellhead in active storage service shall have
fire suppression capability. 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
[
(9)
Notification of emergency or uncontrolled release.
(A)
(No change.)
(B)
Commission. The operator shall report to the appropriate
Commission
[
(10)
Public education.
Each
[
(11)
(No change.)
(12)
Employee safety training.
(A)
Each
[
(B)
(No change.)
(13)
Warning systems and alarms.
(A)
All
[
(B)
A manually operated alarm shall be installed at each attended
storage facility [
(14)
Wind socks.
At
[
(15)
Barriers.
Barriers
[
(16)
Wellhead, surface piping, and related
equipment. All wellhead equipment, product, fresh water, and brine surface
piping, and related equipment shall be designed, installed, and operated in
accordance with engineering standards to the expected service conditions to
which the piping and equipment will be subject. Within one year of the effective
date of this section, the operator shall report to the Commission the particular
engineering standards under which wellhead equipment, product, fresh water,
and brine surface piping, and related equipment are designed, installed, tested,
maintained, and operated.
(i) - (j)
(No change.)
(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
[
(2)
(No change.)
(l)
Monitoring requirements.
(1) - (4)
(No change.)
(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)
(No change.)
(n)
Operations, construction, and maintenance records
[
(1)
Hydrocarbon injection and withdrawal data. The operator
shall retain for
three months all electronic
[
(2)
Construction and maintenance
[
(3)
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
[
(o)
Testing
and Maintenance
.
(1)
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)
[
(A)
A hydrocarbon storage well shall be tested for integrity
by the nitrogen-brine interface method or an alternative approved by the
Commission
[
(B)
A test procedure shall be filed with the
Commission
[
(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. Storage wellhead components,
including spool pieces, shall be inspected and pressure tested to 125 percent
of the permitted maximum allowable operating pressure in conjunction with
hydrocarbon storage well integrity test schedule.
(4)
Product, fresh water, and brine surface
piping. 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. 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.
(5)
[
(p) - (r)
(No change.)
§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) - (3)
(No change.)
(4)
Emergency shutdown valve--A valve that automatically closes
to isolate a gas storage
wellhead
[
(5)
(No change.)
(6)
Gas storage well or storage well--A well used for the injection
or withdrawal of natural gas or any other gaseous substance into or out of
an underground gas storage facility
, including the storage wellhead,
casing, tubing, borehole, and cavern
.
(7)
Leak
or fire
detector--A device capable of detecting
by chemical or physical means the presence of
gas
[
(8) - (11)
(No change.)
(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 emergency
shutdown valve, and exclusive of tubing and casing, 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)
[
(b) - (c)
(No change.)
(d)
Standards for underground storage zone.
(1)
Geologic, construction, and operating performance
[
(2)
(No change.)
(e)
Notice and hearing.
(1) - (2)
(No change.)
(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
[
(4) - (5)
(No change.)
(f) - (g)
(No change.)
(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)
(No change.)
(2)
Storage wellhead
[
(A)
Within
three
[
(i) - (iv)
(No change.)
(B)
(No change.)
(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.
(B)
Brine piping shall be designed for the maximum brine wellhead
pressure.
(C)
Fresh water and brine surface piping, if any, must either
be:
(i)
isolated from the wellhead when fresh water or brine is
not being injected into the well; or
(ii)
designed for the maximum allowable operating pressure
on the hydrocarbon side of the well unless equipped with an emergency shutdown
valve.
(4)
[
(A)
Within one year of the effective date of this section,
each storage well shall have
two
[
(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)
[
(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)
[
(6)
[
(A)
Within two years of the effective date of this section,
all leak
or fire
detectors and [
(B)
A manually operated audible alarm shall be installed at
each attended storage facility [
(7)
[
(8)
[
(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
[
(9)
[
(10)
[
(A)
Each
[
(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 to protect each wellhead
and compression station.
(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 subparagraph and propose an alternative schedule or means
of protection from wellhead fire for approval of the Commission or its designee.
(12)
Wellhead, piping, and related equipment.
(A)
All wellhead equipment, gas, fresh water, and brine surface
piping, and related equipment shall be designed, installed, tested, maintained,
and operated in accordance with engineering standards to the expected service
conditions to which the piping and equipment will be subject.
(B)
Within one year of the effective date of this section,
the operator shall report to the Commission the particular engineering standards
under which wellhead equipment, gas, fresh water, and brine surface piping,
and related equipment are designed, installed, tested, maintained, and operated.
(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) - (j)
(No change.)
(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
[
(2)
(No change.)
(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
,
[
(2) - (4)
(No change.)
(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)
(No change.)
(n)
Operations, construction, and maintenance records
[
(1)
Operations
[
(2)
Construction and maintenance
[
(3)
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) - (2)
(No change.)
(3)
Storage Wellhead. Storage wellhead components,
including spool pieces, shall be tested or inspected for integrity in conjunction
with hydrocarbon storage well integrity test schedule.
(4)
Fresh water, brine, and gas surface piping.
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. 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.
(p)
(No change.)
(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
[
(2)
(No change.)
(r)
(No change.)
This agency hereby certifies that the proposal has been reviewed
by legal counsel and found to be within the agency's legal authority to adopt.
Filed with the Office of
the Secretary of State on February 7, 2006.
TRD-200600634
Mary Ross McDonald
Managing Director
Railroad Commission of Texas
Earliest possible date of adoption: March 26, 2006
For further information, please call: (512) 475-1295
Subchapter A. GENERAL REQUIREMENTS
16 TAC §9.2, §9.52
The Railroad Commission of Texas proposes amendments to §9.2
and §9.52, relating to Definitions, and Training and Continuing Education
Courses. The Commission proposes these amendments to clarify some wording
and procedures for the training and continuing education requirements, and
to add a procedure by which certificate holders may receive continuing education
credit for completing certain Certified Employee Training Program (CETP) courses.
In §9.2, the Commission proposes to amend the definition of "CETP"
to add a reference to the National Propane Gas Association (NPGA), or the
authorized agents or successors to NPGA or to the Propane Education and Research
Council (PERC). The amendment is necessary because PERC has authorized NPGA
to provide CETP training, and because such training may be offered by these
organizations' authorized agents rather than by the organizations themselves.
In §9.52, the Commission proposes most of the amendments to clarify
the rule requirements. In subsection (a), and in paragraph (1) of subsection
(a), the Commission proposes to delete some repetitive wording and to add
a reference to the tables in subsection (h) of the rule. The Commission proposes
the deletion of the repetitive wording so that the tables, which list all
the training and continuing education courses offered or approved by the Commission
and the categories to which they apply, will be the definitive list of the
courses that may be presented for Commission credit by certified individuals
in each covered category. The Commission proposes to delete subsections (a)(1)
and (2), and to redesignate existing paragraphs (3) and (4) as paragraphs
(1) and (2).
In subsection (b), the Commission proposes to add wording to refer to the
tables in subsection (h), and to delete the repetitive list of categories
in paragraph (1)(A). The Commission proposes to redesignate subsection (b)(1)(B)
and (C) as (A) and (B). In newly-designated subsection (b)(1)(A), the Commission
has added a May 31, 2007, deadline by which public employees who are certified
as of June 1, 2006, shall complete their continuing education requirement.
This is consistent with amendments the Commission made to §9.51, relating
to General Requirements for Training and Continuing Education, adopted on
January 24, 2006, published in the February 10, 2006, issue of the
Texas Register
(31 TexReg 843), and effective March 1, 2006.
In subsection (b)(3), the Commission proposes to delete the sentence referring
to any employee of a state agency, county, municipality, school district,
or other government subdivision not being required to pay the annual certificate
renewal fee, to make this rule consistent with the Commission's recent amendments
to §9.51 of this title, referenced in the previous paragraph.
The Commission proposes new subsection (c) to address a situation in which
a current certificate holder passes a Commission examination for an additional
certification that requires completion of a training course. In this situation,
the Commission would assign the certificate holder a training deadline pursuant
to the requirements of §9.52(a)(1) regarding the new certification. Upon
completion of that training, the Commission would then assign the certificate
holder a new continuing-education deadline pursuant to §9.52(b).
The Commission proposes to redesignate current subsections (c) through
(g) as subsections (d) through (h). The Commission does not propose any changes
to the four tables listing the training and continuing education requirements;
however, they are included in this rulemaking because the Commission proposes
to change the subsection designation from subsection (g) to subsection (h).
The Commission proposes new subsection (i) to specify the procedure by
which current certificate holders may obtain continuing-education credit for
completion of an approved CETP course. Tables 3 and 4 of subsection (h) specify
the CETP courses approved by the Commission and the categories to which they
apply. Under the proposed procedure, a certificate holder who has successfully
completed a CETP class, including any applicable knowledge and skills assessments,
as determined by the issuance of a National Propane Gas Association class
certificate, must submit to the Commission, either through regular mail or
electronic mail, the individual's name, address, telephone number, and Social
Security number; the LP-gas certification currently held; the CETP class date;
and a readable copy of the CETP class certificate. AFRED must review the material
submitted within 30 business days of receipt and must notify the certificate
holder if the request to award Railroad Commission continuing-education credit
is approved, denied, or incomplete. The certificate holder will have 30 calendar
days from the date of a notice of deficiency to supply the additional required
information. Certificate holders requesting credit for CETP class attendance
must submit such requests to allow processing time so that a request is finally
approved by May 31 in order for the certificate holder to receive credit toward
that deadline.
Dan Kelly, Director, Alternative Fuels Research and Education Division,
has determined that for each year of the first five years the proposed amendments
are in effect there will be no fiscal implications for state or local government
as a result of enforcing or administering the amendments.
Mr. Kelly has also determined that the public benefit anticipated as a
result of the amendments will be clarification of Commission requirements
regarding training and continuing education generally, and in particular clarification
of the procedures for certificate holders to add a new certification or to
obtain credit for completion of approved CETP courses.
Texas Government Code, §2006.002 requires a state agency considering
adoption of a rule that would have an adverse economic effect on small businesses
or micro-businesses to reduce the effect if doing so is legal and feasible
considering the purpose of the statutes under which the rule is to be adopted.
Before adopting a rule that would have an adverse economic effect on small
businesses, a state agency must prepare a statement of the effect of the rule
on small businesses, which must include an analysis of the cost of compliance
with the rule for small businesses and a comparison of that cost with the
cost of compliance for the largest businesses affected by the rule, using
cost for each employee, cost for each hour of labor, or cost for each $100
of sales.
Pursuant to Texas Government Code, §2006.002(c), the Commission cannot
determine the cost of compliance for individual, small business, or micro-business
LP-gas businesses, because under the proposed amendments, attending and requesting
credit for attendance at a CETP course is voluntary, not mandatory. The Commission
assumes that there are LP-gas businesses that meet the definitions of "micro-business"
and "small business" set forth in Texas Government Code, §2006.001(1)
and (2), respectively; however, the Commission does not have data showing
the expense for each employee, the expense for each hour of labor, or the
total sales revenue for any LP-gas business. In addition, the costs for any
particular LP-gas business will vary based on that business' situation. Therefore,
the Commission is not able to determine the exact cost of compliance based
on the cost for each employee, the cost for each hour of labor, or the cost
for each $100 of sales pursuant to Texas Government Code, §2006.002(c).
Further, pursuant to Texas Government Code, §2006.002, the Commission
finds that, considering that the purpose of Texas Natural Resources Code,
Chapter 113, is to ensure the safe use of LP-gas, it is not feasible to reduce
any adverse effect the proposed amendments could have on individuals, small
businesses, or micro-businesses based on the size of the business.
Comments on the proposal may be submitted to Rules Coordinator, Office
of General Counsel, Railroad Commission of Texas, P.O. Box 12967, Austin,
Texas 78711-2967; online at www.rrc.state.tx.us/rules/commentform.html; or
by electronic mail to rulescoordinator@rrc.state.tx.us. The Commission will
accept comments for 30 days after publication in the
Texas Register
. The Commission encourages all interested persons to
submit comments no later than the deadline. The Commission cannot guarantee
that comments submitted after the deadline will be considered. For further
information, call Mr. Thomas Petru at (512) 463-6930. The status of Commission
rulemakings in progress is available at www.rrc.state.tx.us/rules/proposed.html.
The Commission proposes the amendments pursuant to Texas Natural Resources
Code, §113.051, which authorizes the Commission to adopt rules relating
to any and all aspects or phases of the LP-gas industry that will protect
or tend to protect the health, welfare, and safety of the general public,
and §113.052, which authorizes the Commission to adopt by reference,
in whole or in part the published codes of the National Fire Protection Association
as standards to be met in the design, construction, fabrication, assembly,
installation, use, and maintenance of containers, tanks, appliances, systems,
and equipment for the transportation, storage, delivery, use, and consumption
of LP-gas or any one or more of these purposes.
Statutory authority: Texas Natural Resources Code, §§113.051
and 113.052.
Cross-reference to statute: Texas Natural Resources Code, Chapter 113.
Issued in Austin, Texas on February 7, 2006.
§9.2.Definitions.
In addition to the definitions in any adopted NFPA pamphlets, the following
words and terms, when used in this chapter, shall have the following meanings,
unless the context clearly indicates otherwise.
(1) - (10)
(No change.)
(11)
CETP--The [
(12) - (52)
(No change.)
§9.52.Training and Continuing Education Courses.
(a)
Training. Applicants for a new certification
and applicants
who have passed a certification examination but have not completed an applicable
training course
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
(1)
[
(2)
[
(b)
Continuing education. A certificate holder shall complete
at least eight hours of continuing education every four years
as specified
in the tables in subsection (h) of this section
. Upon fulfillment of
this requirement, the certificate holder's next continuing education deadline
shall be four years after the May 31 following the date of the most recent
class the certificate holder has completed, unless the class was completed
on May 31, in which case the deadline shall be four years from that date.
A certificate holder's continuing education deadline shall not be extended
if an examination for a current category and level of certification is retaken
and passed; a continuing education deadline shall be extended only after a
certificate holder successfully completes an applicable continuing education
class. An individual who completes a continuing education class after the
assigned deadline shall have four years from the original deadline to complete
the next class.
(1)
Continuing education requirements
for certain categories.
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
(A)
[
(B)
[
(2)
Certificate holders who attend a class offered by an outside
instructor shall not be entitled to a refund of the annual renewal fee or
any other fees or penalties required by the Commission.
(3)
Individuals who have not paid the annual certificate renewal
fee, including general installers and repairman exemption holders or members
of the general public, shall not attend training or continuing education classes
free of charge, but may request from the AFRED training section to attend
classes at the charge specified in §9.51 of this title (relating to General
Requirements for Training and Continuing Education). Such requests shall be
in writing and handled at AFRED's discretion on an individual basis and if
space is available in the requested class. [
(4)
Any certificate holder who has timely paid the annual certificate
renewal fee but is not otherwise required to attend a Commission continuing
education class may voluntarily attend a class, if space is available, by
registering with the AFRED training section as specified in §9.51 of
this title (relating to General Requirements for Training and Continuing Education).
(c)
Adding a new certification.
A current certificate holder who successfully completes an examination for
an additional certification that requires completion of a training course
shall be assigned a training deadline pursuant to subsection (a)(1) of this
section. Upon completion of the required training, the certificate holder
shall be assigned a continuing education date pursuant to subsection (b) of
this section.
(d)
[
(e)
[
(f)
[
(g)
[
(1)
The responsibility of certifying AFT activities shall not
be delegated to an unauthorized individual. AFT qualification tasks shall
be witnessed by an authorized individual, verified as being successfully completed,
and the AFT form signed as follows:
(A)
For licensees with only one company representative, that
company representative shall self-certify the AFT.
(B)
For licensees with more than one company representative,
one company representative may certify the AFT of another company representative,
but shall not self-certify.
(C)
Company representatives shall certify operations supervisors'
AFT.
(D)
The company representative or an operations supervisor
authorized by the licensee and in current good standing with the Commission
shall certify the employees' AFT.
(E)
If authorized, a Commission-approved outside instructor
may certify any AFT.
(2)
Other AFT situations shall be handled as follows:
(A)
For a certified individual employed by a licensee, the
licensee shall retain the most recently completed AFT material for each applicable
category of the individual's certification in the individual's employment
records.
(B)
For an individual who ceases employment with a licensee,
the licensee shall retain the latest required AFT material for at least two
years from the date the individual is no longer employed by the licensee.
The two-year period shall be based on the renewal period for the examination
renewal fee penalty. The licensee shall provide a copy of the AFT material
to the individual.
(C)
For an individual who begins employment with a different
licensee, the new licensee shall obtain a copy of the individual's AFT material
from the individual and shall place the copy in the individual's employment
records.
(D)
An individual who is never employed by a licensee shall
retain the most recently completed AFT material for each applicable category
of the individual's certification in a safe location for at least two years
from the date the class that required the AFT was attended.
(E)
For an individual who is employed by a licensee when a
class requiring AFT is attended, but who prior to the AFT's being certified
becomes employed by a new licensee, the new licensee shall certify the individual's
AFT.
(F)
For an individual who is employed by a licensee when a
class requiring AFT is attended, but who prior to the AFT's being certified
ceases employment with the licensee and wishes to continue performing LP-gas
activities, the individual shall contact a company representative or operations
supervisor of another applicable licensee or an AFRED-approved outside instructor
to complete the AFT and maintain the LP-gas certification.
(3)
Individuals who attend the 80-hour Category E management-
level class or the 16-hour Category F, G, I, or J management- level class
shall perform any required AFT activities during the class.
(4)
If AFT is required for a class, the AFT checklist outlining
the specific activities to be performed shall be included in the class materials.
(h)
[
[
(i)
Credit for attendance at CETP
courses. A certificate holder who has successfully completed a CETP class,
including any applicable knowledge and skills assessments, may receive credit
toward the continuing education requirements specified in this section as
follows:
(1)
The CETP class shall be approved for the category
of certificate held as indicated on Tables 3 and 4 in subsection (h) of this
section.
(2)
The successful completion of a CETP class is
determined by a National Propane Gas Association class certificate, which
is issued only after an individual has completed the prescribed course of
study, including any related knowledge and skills assessments, for the applicable
CETP job classification.
(3)
To receive credit toward the Commission's continuing
education requirements, the certificate holder shall submit the following
information, clearly readable, by regular mail to AFRED, Railroad Commission
of Texas, P.O. Box 12967, Austin, Texas 78711-2967, or by electronic mail
to the following address: CETP-credit@rrc.state.tx.us.
(A)
the individual's full name, address, telephone
number, Social Security number;
(B)
the LP-gas certification(s) currently held;
and
(C)
the CETP class date and a readable copy of the
CETP class certificate for an approved CETP class as specified in Tables 3
and 4 of subsection (h) of this section. The CETP class attendance date shall
be within one year of the certificate holder's continuing education deadline.
(4)
AFRED shall review the submitted material within
30 business days of receipt and shall notify the certificate holder in writing
that the request is approved, denied, or incomplete. If the material is incomplete,
AFRED shall identify the necessary additional information required. The certificate
holder shall file the additional information within 30 calendar days of the
date of a notice of deficiency in order to receive credit for the CETP course
attendance. Certificate holders requesting credit for CETP class attendance
shall submit such requests to allow processing time so that a request is finally
approved by May 31 in order for the certificate holder to receive credit toward
that deadline.
This agency hereby certifies that the proposal has been
reviewed by legal counsel and found to be within the agency's legal authority
to adopt.
Filed with the Office of
the Secretary of State on February 7, 2006.
TRD-200600633
Mary Ross McDonald
Managing Director
Railroad Commission of Texas
Earliest possible date of adoption: March 26, 2006
For further information, please call: (512) 475-1295
well
] from
surface piping in the event of specified conditions that, if uncontrolled,
may cause an emergency.
(16)
] 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.
commission
]
requirements.
Impermeable salt formation
]. 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.
paragraphs (1) - (15) of
] 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)
[
(13) - (15)
]
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.
Emergency shutdown valves
].
two
] years of the effective
date of this section,
or in conjunction with the next scheduled integrity
test of the storage well, the operator shall have installed
emergency
shutdown valves
between the storage wellhead and
[
shall be
installed on
] the product and brine
surface piping
[
sides
] of each hydrocarbon storage well and, if required under paragraph
(3) of this subsection,
between the storage wellhead and
[
on
] fresh water
surface
piping
of
[
to
]
the well.
The operator shall not install any product, brine, or fresh
water surface piping between the storage wellhead and the emergency shutdown
valve. Within one year of the effective date of the section, an
[
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
[
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.
Brine
] and fresh
water
surface
piping.
(B)
] Fresh water
surface
piping,
if any, must either be:
wellhead
] pressure on the hydrocarbon side of
the well
unless
[
and
] equipped with an emergency shutdown
valve.
one
] of
the following
redundant
devices or methods in operation[
.
Within two years of the effective date of this section, each storage cavern
shall have at least two of the following devices or methods in operation
]:
Within two years of the effective date
of this section, 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.
Within two years of the effective
date of this section, leak
] detectors shall be installed and in operation
at four locations that are evenly spaced around the perimeter of the brine
pit(s).
Within two years of the effective
date of this section, 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:
Within two years of the effective
date of this section, 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:
Within six
months of the effective date of this section, each
] storage facility
shall submit to the
Commission
[
commission
] a written
emergency response plan. The plan shall address spills and releases, fires,
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
[
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.
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
[
confirm
the report in writing within five working days
].
Within six months
of the effective date of this section, 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.
Within six months of the effective
date of this section, 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.
Within two years of the effective
date of this section, 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.
within two years of the effective date of this section
]. The alarm shall be audible in areas of the facility where personnel
are normally located.
Within one year of the
effective date of this section, 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.
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, and surface hydrocarbon storage vessels
in areas where vehicles may normally be expected to travel
or within
100 feet of a public road
.
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.
Records
] retention.
five years
]
records of hydrocarbon storage well pressures,
flow rates, hydrocarbon
volumes
[
interface levels (if any), hydrocarbons
] injected
into and withdrawn from each well, and the hydrocarbon inventory of each cavern.
Equipment
] data. The operator shall retain for
the life of the facility
[
five years
] documents and records pertaining to the
drilling, mining, and completion of storage wells and
[
installation,
] inspection, maintenance, and testing of equipment required under subsections
(h) and (l) of this section
, and shall transfer all such documents and
records to any new owner and/or new operator of the facility
. 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.
five-year
] period until the resolution of such proceeding.
(1)
] Integrity tests. 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.
commission
], or its designee.
commission
] for approval at least 10 days before the test
date.
(2)
] Alternative monitoring. An
operator may request the
Commission
[
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)
[
(1)
] of
this subsection before it may be returned to storage service.
well
] from surface
piping in the event of specified conditions that, if uncontrolled, may cause
an emergency.
hydrocarbon
vapor
] or the escape of
gas or the presence of flame or heat of
a fire
[
vapor through a small opening
].
(12)
] 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.
Impermeable salt formation
]. 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.
here
] 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.
Emergency shutdown valves
].
two
] years of the effective
date of this section,
or in conjunction with the next integrity test
of the storage well, the operator shall have installed
emergency shutdown
valves
between the wellhead and
[
shall be installed on
]
the gas injection/withdrawal
surface
piping of each storage well
and
between the wellhead and
[
on
] any brine or fresh
water
surface
piping [
that is connected at the wellhead
].
The operator shall not install any gas, brine, or fresh water surface piping
between the wellhead and the emergency shutdown valve. Within one year of
the effective date of this section, the
[
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
[
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
:
[
.
]
(3)
] Cavern debrining and solution
mining operations.
one
] 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. [
Within two years from the effective
date of this section, each storage well shall have two or more of the following
devices or methods in operation during cavern debrining operations or during
solution mining operations that are conducted in a cavern 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:
commission
].
(4)
] Leak
or fire
detectors.
that is 100 yards or less from a residence, commercial establishment,
church, school, or small, well-defined outside area, and at each structurally
enclosed compressor site. For purposes of this section, the term "small, well-defined
outside area" means an area such as a playground, recreation area, outdoor
theater, or other place of public assembly that is occupied by 20 or more
persons on at least five days a week for 10 weeks in any 12-month period.
The days and weeks need not be consecutive
].
(5)(A)
] of this subsection.
(5)
] Warning systems and alarms.
pressure
] 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.
within 180 days of the effective date
of this section
]. The alarm shall be audible in areas of the facility
where personnel are normally located.
(6)
] Emergency response plan.
Each
[
Within six months of the effective date of this section,
each
] storage facility shall submit to the
Commission
[
commission
] a written emergency response plan. The plan shall address
gas releases, fires, 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
[
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.
(7)
] Notification of emergency or
uncontrolled release.
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 Commissioner 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
[
confirm the report in writing within five working days
].
(8)
] 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.
(9)
] Employee safety training.
Within six months of the effective
date of this section, 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.
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.
and
] alarms
, and emergency shutdown valve actuation system
as
required in subsection
(h)(2)(A) and (6)(A)
[
(h)(5)(A)
]
of this section.
Records
] retention.
Gas injection and withdrawal
] data. The operator shall retain for
three months the electronic
[
five years
] records of storage well pressures, volumes
of gases injected and withdrawn, and the inventory of gas in storage.
Equipment
] data. The operator shall retain for
the life of the facility
[
five years
] documents and records pertaining to the
drilling, mining, and completion of storage wells, and the
[
installation,
] inspection, maintenance, and testing of equipment relating to the
safe operation of the storage facility
required under subsections (h)
and (l) of this section, and shall transfer all such documents and records
to any new owner and/or new operator of the facility
.
Any documents or records that contain information pertinent to the resolution
of any pending regulatory enforcement proceeding shall be retained beyond
the five-year period until the resolution of such proceeding.
]
Texas Civil Statutes,
Article 6053-3
]; and other statutes administered by the
Commission
[
commission
].
Chapter 9.
LP-GAS SAFETY RULES
Propane Education and Research Council's
] Certified Employee Training Program
offered by the Propane Education
and Research Council (PERC), the National Propane Gas Association (NPGA),
or their authorized agents or successors
.
listed in this subsection, other than Category
E, F, G, I, or J management-level individuals and except as stated in paragraph
(4) of this subsection,
] shall
complete
[
attend at least
eight hours of
] training
as specified in the tables in subsection
(h) of this section
prior to their first certificate renewal deadline
[
of May 31 of the appropriate year. Applicants for Category D, E, F,
G, I, J, K, or M management-level certification shall attend the course or
courses specified for the category
]. Category E
management-level
applicants shall attend the 80-hour class; Category F, G, I, and J
management-level
applicants shall attend the 16-hour class; and
Category D, K and M management-level applicants and
all [
other
] applicants
for employee-level certifications that are subject
to training requirements
shall attend an eight-hour class. A certificate
holder's training deadline shall not be extended if that individual retakes
and passes an examination for the current category and level of certification.
A training deadline shall be extended only after a certificate holder successfully
completes an applicable training class.
(1)
The following management-
or employee-level applicants shall complete the training requirements:]
(A)
Category D management-level;]
(B)
Category E management-level;]
(C)
Category F management-level;]
(D)
Category G management-level;]
(E)
Category I management-level;]
(F)
Category J management-level;]
(G)
Category K management-level;]
(H)
Category M management-level;]
(I)
Bobtail employee-level;]
(J)
DOT portable cylinder filler employee-level;]
(K)
Service and Installation employee-level;]
(L)
Appliance service and installation employee-level;]
(M)
Motor/mobile fuel dispensing employee-level;
and]
(N)
Recreational vehicle (RV) technician employee-level.]
(2)
Training requirements for
an applicant for license shall be fulfilled by all prospective company representatives
and operations supervisors.]
(3)
] Individuals who pass an employee-level
rules examination between March 1 and May 31 of any year shall have until
May 31 of the next year to complete any required training. Individuals who
pass an employee-level rules examination at other times shall have until the
next May 31 to complete any required training. Completion of AFT shall be
in accordance with subsection
(g)
[
(f)
] of this section.
(4)
] Applicants for company representative
or operations supervisor [
who do not comply with the conditional qualification
in §9.17(g) of this title (relating to Designation and Responsibilities
of Company Representatives and Operations Supervisors)
] shall comply
with the training requirements in this section prior to the Commission issuing
a certificate.
(1)
Individuals completing their continuing
education requirements shall then have four years to complete the next eight-hour
continuing education requirement (unless a new certification is added that
requires training as specified in subparagraph (B) of this paragraph).
]
(A)
Certificate holders with one of the following
certificates shall complete the continuing education classroom instruction
and any required AFT for that class:
]
(i)
Category D management-level;
]
(ii)
Category E management-level;
]
(iii)
Category F management-level;
]
(iv)
Category G management-level;
]
(v)
Category I management-level;
]
(vi)
Category J management-level;
]
(vii)
Category K management-level;
]
(viii)
Category M management-level;
]
(ix)
Bobtail employee-level;
]
(x)
DOT portable cylinder filler employee-level;
]
(xi)
Service and Installation employee-level;
]
(xii)
Appliance service and installation employee-level;
]
(xiii)
Motor/mobile fuel dispensing employee-level;
and
]
(xiv)
Recreational vehicle (RV) technician
employee-level.
]
(B)
] Certificate holders who hold
only a Category D, F, G, J, or K certificate as of the effective date of this
section shall complete their initial continuing education requirement by May
31, 2005. Beginning September 1, 2005, Category M and recreational vehicle
technician certificate holders shall have until May 31, 2006, to complete
their initial continuing education requirement. Certificate holders who hold
a Category D, F, G, J, K, or M certificate or a recreational vehicle technician
certificate and who have more than one certification as of February 1, 2001,
shall complete their continuing education requirement by the continuing education
deadline assigned for the initial certificate.
Public employees who are
certified as of June 1, 2006, shall complete their continuing education requirement
by May 31, 2007.
(C)
] Certificate holders who are
certified to perform LP-gas activities covered by different certifications
shall complete the continuing education requirements for any one of the certifications
held in order to maintain active status. For each subsequent continuing education
requirement, such individuals shall be responsible for attending a different
continuing education class relevant to one of the other certifications held.
Any employee of a state agency,
county, municipality, school district, or other governmental subdivision is
not required to pay the fee.
]
(c)
] Train-the-Trainer classes.
The Train-the-Trainer classes shall not count as credit towards the training
or continuing education requirements.
(d)
] Class materials. Individuals
who attend AFRED-taught classes shall receive a copy of the class materials
at no charge. Additional copies may be purchased from AFRED at the established
price.
(e)
] Certificates of completion.
The AFRED training section shall issue a certificate of completion to each
individual who completes an AFRED-taught class. Individuals shall retain the
certificates as proof of completion of the class.
(f)
] Advanced field training (AFT).
Some classes may include AFT in addition to the classroom hours, during which
class attendees shall perform LP-gas activities. AFT shall be properly completed
within 30 calendar days of attending the class. All qualification tasks included
in the AFT shall be completed. The AFT materials, including the qualification
checklist and the certification page, shall be readily available at the licensee's
Texas business location for review by an authorized Commission representative
during normal business hours.
(g)
] Available courses. Training
and continuing education courses and other information are shown in Tables
1 through 4 of this subsection. Items on the tables marked with an "x" indicate
courses that meet training or continuing education requirements for management-level
or employee-level certificate holders in that category.
Figure: 16 TAC §9.52(g)
]
Part 2.
PUBLIC UTILITY COMMISSION OF TEXAS