TITLE 16.ECONOMIC REGULATION

Part 1. RAILROAD COMMISSION OF TEXAS

The Railroad Commission of Texas withdraws its proposal to amend §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, published in the February 24, 2006, issue of the Texas Register (31 TexReg 1138) and proposes revised new 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 tubing 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 tubing at or above 3,724 feet below the ground surface within the gas-bearing area of the storage cavern. Gas entered the brine tubing, reached the surface, and flowed into the above-ground brine piping. The emergency shutdown 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 the 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. In January 2005, staff sent a questionnaire to all operators of underground hydrocarbon storage facilities to gather additional information concerning the current status of construction, maintenance, operations, and record keeping. In addition, in May 2005, staff held a workshop to review operator responses from the questionnaire and to gather input from affected operators to evaluate the advisability, cost, and effectiveness of potential new safety regulations. The Commission also published on its website a draft of the proposed amendments for informal comment. Staff used the input from these forums to draft the original proposed amendments and incorporate new requirements for integrity management of surface piping, location of emergency shutdown valves, fire suppression capabilities, data acquisition, and record retention.

On February 24, 2006, the Commission published the original proposed amendments to §3.95 and §3.97 (Statewide Rules 95 and 97) in the Texas Register for a 30-day comment period. Two associations and seven companies submitted comments. The Commission has incorporated substantive changes as a result of the comments, and therefore republishes the proposed amendments for a second 30-day comment period. With this new proposal, the Commission provides responses to the initial comments to explain the basis for the revised proposed amendments to §§3.95 and 3.97. Because this is a new proposal, however, these responses are not the Commission's final position on these issues. The Commission invites and will fully consider comments on all matters in this proposal.

An industry association recommended changes to the definition for "storage wellhead" in §3.95(a)(16) and §3.97(a)(12) to include the statement "The storage wellhead must be designed to contain the contents of the storage well and protect against mechanical damage and transient pressure by: (1) limiting spool pieces inside the emergency shutdown valve to a length less than six feet, (2) designing all spool and piping anchors to prevent piping failure due to 'water hammer' and minimize all spool lengths, or (3) design emergency shutdown valves to prevent creating a transient pressure surge in the wellhead piping."

The Commission agrees that an additional description of storage wellhead performance standards will be helpful, but has not added this performance standard to the definition for "storage wellhead" for two reasons. First, a definition is not the preferred place to impose a performance standard. Second, the suggested standards emphasize protection only against transient pressure. Consequently, instead of changing the definition of "storage wellhead," the Commission added some of the suggested language into proposed new §3.95(h)(2)(A) which states the performance standard for a storage wellhead, and emphasizes protection against all sorts of pressure. The Commission made a parallel addition to §3.97(h)(2)(A).

An integrated oil company questioned the need to add the phrase "exclusive of tubing and casing" to the definition of surface piping at §3.95(a)(17) and §3.97(a)(13). The Commission agrees that the added language is of limited usefulness and has deleted the phrase in the new proposal.

A storage operator interpreted the definition of surface piping at §3.95(a)(17) to include all product, brine, and freshwater piping in a facility that connects to a storage well. This comment suggested clarifying and strengthening the proposed changes by individually defining the types of surface piping and crafting individualized requirements for each. The requested clarification has not been made at this time, because the various types of surface piping are already described in sufficient detail with unique sets of requirements.

A pipeline association requested clarification that fusible links would satisfy the requirement of the definition of leak or fire detectors at §3.97(a)(7). The proposal has not been changed in response to this comment due to concerns about clarity. Specifically identifying fusible links as an appropriate type of fire detector without listing any other types of fire detectors would be potentially confusing; it might lead to the erroneous conclusion that only the listed types of fire detectors meet the requirements of the rule. That might stifle technical innovation for new types of detectors.

A pipeline association stated that the definition of surface piping at §3.97(a)(13) needs additional wording to denote that the end of surface piping would be at the first point of pressure regulation downstream of the wellhead. Such wording would help to identify the boundary between the respective areas of administrative authority of the Oil and Gas Division and the Safety Division. A storage company filed a similar comment regarding language in section §3.97(h)(3)(A). The Commission agrees with the suggestion as it applies to product piping. Because the Safety Division only has administrative authority over piping that transports hazardous materials, however, such a boundary has not been applied to fresh water or brine surface piping under any operating conditions. The Commission has clarified in the new proposal for §3.95(h)(3)(A) that only some hydrocarbon storage facilities are under the administrative authority of the Safety Division.

A pipeline company and a storage company recommended that the wording in §3.97(h)(2)(B) and §3.95(h)(2)(B), respectively, allowing an operator to come into compliance with the requirements on the location of emergency shutdown valves within three years or in conjunction with the next scheduled mechanical integrity test should be reworded to require the operator to comply with the later deadline. The requested change has not been made at this time. However, the proposal has been modified to provide additional clarity. The language of the original proposal was intended to provide an operator with the flexibility to choose the most appropriate alternative. Requiring an operator to comply with the later deadline may not be the most efficient option for an operator. In many cases, an operator gains operational flexibility by choosing the earlier deadline if it coincides with a mechanical integrity test for which the cavern is emptied, because the wellhead may be in a more favorable operational status for a workover. To further increase the clarity, however, the Commission proposes to modify the wording in proposed new §3.95(h)(2)(B) and §3.97(h)(2)(B) as follows: "Either within three years of the effective date of this section, or in conjunction with the next integrity test of the storage well . . . "

A pipeline company identified an incorrect reference in §3.97(h)(2)(C) as originally proposed. The addition of a proposed new subparagraph (A) obviates the need to correct the reference.

A chemical company agreed that all surface piping should be designed for gas pressure on the gas side and maximum brine pressure on the brine side. This comment stated that the failure of one company to maintain surface piping under §3.95(h)(3) should not mean that other facilities do not. This comment also stated that the requirement to locate the emergency shutdown valve on the wellhead before surface piping is not necessary. The chemical company further stated that with proper integrity management testing, there should not be a six foot limit on spool pieces. The Commission notes that integrity management (including testing) is but one element of safe storage well operations. On the basis of systematic process re-engineering, many operators have concluded that the safest location for the emergency shutdown valves is on or immediately adjacent to the storage wellhead.

A gas company commented that the proposed language in §3.97(h)(3)(A) should be revised to eliminate potential conflict with pipeline safety rules. The Pipeline Safety Regulations, found at 16 Texas Administrative Code Chapter 8 and administered by Safety Division, currently establish the maximum allowable operating pressure of gas piping within a storage facility. The comment suggested that the rule should be modified to limit the surface piping subject to this section to that piping between the wellhead and the first downstream pressure-regulating device. The Commission agrees with the suggestion as it applies to product piping. Such a boundary would apply only to product piping that transports hazardous materials and thus is under the administrative authority of the Safety Division.

A pipeline association stated that the language proposed in §3.97(h)(3) is appropriate only if the definition for surface piping is amended to include additional wording to denote the end of surface piping would be at the first point of pressure regulation downstream of the wellhead. Such wording would help to identify the boundary between the respective administrative authorities of the Oil and Gas Division and the Safety Division. The Commission agrees with the suggestion as it applies to product piping. Such a boundary would apply only to product piping that transports hazardous materials and thus is under the administrative authority of the Safety Division. The Commission proposes language in §3.97(h)(3) to limit the requirement to product or gas surface piping that extends from the wellhead emergency shutdown valve to the first pressure regulation device.

A storage company commented that the language originally proposed in §3.95(h)(3)(B) requiring brine surface piping to be designed for maximum brine wellhead pressure and to transport gas and brine under emergency conditions to the brine system gas vapor control system is too broad. The storage company suggested adding "maximum brine operating pressure that can occur when the emergency shutdown valve actuates" for clarification. The storage company also stated that the transport section should be clarified to include the fact that different pressure standards would be applied to different portions of the brine system, depending on the service conditions to which the piping and equipment will be subjected. The suggested change has not been included in the proposal. Brine piping must be designed to function properly and transport the product and brine mixture downstream to safety devices such as a vapor knockout vessel or a flare in multiple situations, including both where the emergency shutdown valve closes properly and where the emergency shutdown valve is closing slowly or improperly. The safety devices (such as a vapor knockout vessel or flares) currently mandated by §3.95(h)(6) already address safe management of product if the surface brine piping maintains integrity in an emergency situation. However, these safety devices will not be effective if the brine piping were to fail to transport the flammable vapor to the appropriate devices.

The chemical company's proposed language for §3.95(h)(3)(B) requiring brine surface piping to be designed for maximum brine wellhead pressure and to transport gas and brine under emergency conditions to the brine system gas vapor control system would be more effective with Commission approved alternatives. The chemical company proposed additional language for the brine surface piping requirement to allow an exception for equally protective alternatives approved by the Commission. The chemical company described the dual emergency shutdown valve system in operation at its facilities in Texas and around the world as an example of an alternative that would be equally protective. The Commission agrees with the suggested language and has inserted the language in the new proposal for §3.95(h)(3)(B)(i). Installation of secondary emergency shutdown valves on the brine piping would significantly add to the safety of the brine system. Emergency shutdown valves are very reliable, and there is a low probability of the failure of such valves. If operators installed dual emergency shutdown valves on the brine line, the probability of simultaneous failure of both emergency shutdown valves becomes very remote.

An operator of a storage facility and a gas company commented that the language in §3.95(h)(3)(C) should exempt small diameter freshwater supply lines to a storage wellhead because their small diameter would prevent water hammer pressure transients from affecting the piping and emergency shutdown valve. The storage operator questioned the need to impose six foot spool length limit on small diameter piping. The Commission agrees with exempting small diameter fresh water piping from the six-foot spool length limit, but only under certain circumstances. Fresh water surface piping is already exempted from the requirement to install an emergency shutdown valve under conditions identified in §3.95(h)(3)(C). The Commission proposes to allow fresh water piping to be exempted from the six foot spool length limit if fresh water piping is designed for the permitted maximum allowable operating pressure on the hydrocarbon side of the well and has a maximum internal diameter of two inches or less, and an attendant is posted at the well site to provide manual shut-in when in use.

A chemical company agreed with the fire suppression requirement in §3.95(h)(7); the Commission appreciates the comment.

An association of oil and gas operators recommended adding language to §3.95(h)(7)(C) to identify the purpose of the fire suppression requirement. This association suggested adding to "fire suppression capability" the qualifier "designed to aid in personnel rescue and for equipment protection and cooling." The association also recommended allowing an exception when equipment and buildings that need protection and cooling are located at great distance from the wellheads, for example, approximately 1,000 ft. The Commission concurs with the suggestion to add clarifying language for the performance standard for the fire suppression capability. The association's suggested fire suppression exemption for storage wells located at large distances from other wells or control facilities, however, has not been incorporated into the proposal due to worker safety concerns. An operator may request an exemption under §3.95(h)(7)(C). A great distance between storage wells and control facilities would be taken into account as a mitigating factor in considering whether to grant such a request.

A gas company and a pipeline association commented that the language originally proposed in §3.97(h)(11) requiring fire suppression capability for wellheads and compression stations is unclear because of the lack of sufficient design criteria to allow an operator to know if it has satisfied the regulation. The proposal has not been changed in response to this comment. Adding the qualifying language "designed to aid in personnel rescue and for equipment protection and cooling" adds sufficient clarity in describing the expected performance standard.

An association of oil and gas operators commented that the fire suppression requirement in §3.97(h)(11) for natural gas storage wellheads is unrealistic because events such as the complete loss of wellhead control are beyond the ability of standard fire-fighting equipment to address. This association stated that duplication of the wellhead emergency shutdown valve is preferable to fire suppression capability. The Commission agrees that the example cited by the association--a fire characterized by the complete loss of wellhead control--is largely beyond the ability of standard fire-fighting equipment to address. However, such a fire is extremely rare. Smaller fires are more common, and the clarifying language proposed by the gas company and the association would address fire safety issues associated with the most common types of fires.

A gas company and a pipeline association commented that the new requirements originally proposed in §3.97(h)(5)(A) to require leak or fire detectors at each structurally enclosed compressor sites are unnecessary because the existing pipeline safety regulations found at 16 Texas Administrative Code Chapter 8 and administered and enforced by the Safety Division, already require gas detectors at such locations. The Commission notes that the current rule requires heat and fire detectors at each wellhead and each structurally enclosed compressor site, but only for facilities within 100 yards of public areas. It is appropriate to require heat and fire detectors at each wellhead and each structurally enclosed compressor site for all facilities based on the extensive fire damage associated with the wellhead failure of a gas storage well. It is also appropriate to retain the requirement for leak and fire detectors at the wellhead and the requirement for detectors at structurally enclosed compressor sites. Although the rules in Chapter 8 also require fire detectors at structurally enclosed compressor sites, such a requirement is not in conflict and not all storage facilities are under the administrative authority of the Safety Division.

An integrated oil company, a gas company, and a pipeline association commented that the requirement in §3.95(h)(9)(B) and §3.97(h)(8)(B) to notify the Commission of the root cause of an emergency incident within 30 days may not be achievable in every instance. The integrated oil company suggested adding wording to allow an extension of the deadline, if the situation warrants. The gas company and the pipeline association suggested a 90-day period to submit a supplemental report on the root cause and the operational changes, if any, that would be implemented. The Commission agrees that in some instances, it may not be possible to understand the root cause of an incident within 30 days. The Commission proposes to add language allowing, for good cause, a 30-day extension to the time required to file a report on the root cause of an emergency incident.

An association of oil and gas operators stated its concern that the requirement originally proposed in §3.95(h)(16) and §3.97(h)(12) to design, install, test, maintain, and operate equipment in accordance with engineering standards would be difficult to meet because such standards are too numerous to list and of limited value in a post-incident investigation. The association reported that maintenance standards often do not exist and vary depending on the well's service. The association recommended deleting the word "maintained" and adding the following language: "Within one year of the effective date of this section, the operator shall report to the Commission the particular engineering design standards for the wellhead, piping, and major equipment."

A gas company commented that it is uncertain what detail the Commission seeks in the report required by the language originally proposed in §3.95(h)(16). A gas company suggested that providing the engineering standard itself would not be burdensome, but reporting the detailed process may be very burdensome and, in some cases, could violate confidentiality requirements. A gas company suggested that the proposed change be limited to the identification of the engineering standard.

A gas company suggested separating the requirements in §3.97(h)(12) for design, installation, and testing from those for maintenance and operation because design, installation, and initial testing standards are determined at the time the facility is constructed, whereas maintenance and operating standards may change over time.

The Commission concurs with industry's desire to focus the requirement of reporting design standards to wellhead, piping, and valves. In the revised proposal, the Commission has retained the requirement in §3.95(h)(16) and §3.97(h)(12) that operators must design, install, and operate all wellhead, surface piping, and associated valves in accordance with engineering standards to the expected service conditions. The Commission has deleted the originally proposed change to require operators to report the various standards under which equipment is designed, installed, tested, and maintained.

With respect to the operating requirements in §3.95(k)(1) and §3.97(k)(1), an integrated oil company noted that DOT pipeline regulations Part 192 and 195 allow excursions to 110% of maximum allowable operating pressure. The integrated oil company asked if the Commission intends to follow DOT logic and allow pressure excursions above MAOP. The proposal has not been changed to specifically allow excursions to 110% of maximum allowable operating pressure.

A gas company stated that the retention time for records under §3.95(l)(5) is unclear. As originally proposed, the retention period for these operations records was specified in subsection (n)(1) to be three months. The Commission has clarified in subsection (n)(1) and (2) the retention times applicable to specific types of records. Subsection (m) requires the operator to report the maximum wellhead pressures and injected volumes. Currently, the Commission requires these data be reported once a year. These data and data on testing of safety devises are to be retained for five years, which is unchanged from the current rule.

A pipeline association sought to have the language in §3.95(l)(3) specifically allow multi-cavern metering. This suggestion has not been incorporated into the revised proposal because experience has shown that individual well metering provides more accurate information, and language in §3.95(l)(3)(B) specifically allows the Commission to approve alternative methods of monitoring cavern pressures and volumes. The Commission has not received any requests to allow multi-cavern metering since 1998. In reviewing the rule proposal for this comment, it was noted that the proposed provisions of §3.97(l)(3) continued to refer to multi-cavern metering, and that reference is removed so that the revised proposal for §§3.95(l)(3) and 3.97(l)(3) calls for individual well metering for volumes injected and withdrawn.

A gas company strongly supported the reduction of record retention time from five years to three months in §3.95(n)(1). A chemical company disagreed with the three-month requirement for data retention in subsection (n)(1) and stated that retaining records for 30 days is sufficient to perform an inspection after an incident. The proposal has not been changed in response to this comment.

An association of oil and gas operators commented that the proposed requirement for records retention is still too broad. The association recommended that the requirement for life-of-facility retention be limited to major equipment and emergency shutdown valves. The Commission's revised proposal would limit the requirement for life-of-facility retention to those records associated with drilling, completion, workover, repair, and testing of wellheads, surface piping, and associated valves.

A gas company and a pipeline association stated that the proposed language regarding records retention should be revised to separate the retention requirements for drilling, mining, and completion from the retention requirements for inspection, maintenance, and testing. These commenters stated that a five-year retention requirement would be appropriate for inspection, maintenance, and testing. The Commission concurs with the observation that only some records should be retained for the life of the facility and with the suggestion that drilling, mining, completion, workover, and repair data be retained for the life of the facility. However, the proposal has not been changed to reflect the association's suggestion to use an undefined phrase such as "major" equipment in this very important requirement. The Commission's revised proposal, however, does narrow the requirements for life-of-facility records retention to drilling, mining, completion, workover, repair, and testing of wells, and testing of piping and valves.

An integrated oil company commented that the requirement in §3.95(o)(3) and §3.97(o)(3) to pressure test the storage wellhead components to 125 percent of MAOP in conjunction with the hydrocarbon storage integrity test is onerous because it is too frequent. Such testing would require many caverns be completely emptied; a workover must be performed to pull tubing and wing valves. This commenter suggested a ten-year frequency for such testing and rewording to identify which spool pieces must be tested.

A chemical company agreed with the originally proposed requirement in §3.95(o)(3) and §3.97(o)(3) to inspect and test the wellhead components periodically, but suggested alternative language to the requirement to test wellhead components every five years and included a subparagraph for alternatives to be approved by the Commission. The chemical company suggested a 15-year maintenance schedule if the well is equipped with a downhole packer or dual cemented strings within the salt, as are the chemical company's wells. This company commented that the Commission should require higher testing and maintenance standards for natural gas storage caverns. The company suggested a 15-year schedule to empty natural gas storage caverns; to inspect, test, and re-certify wellhead components; to inspect cemented casings and sonar brine-filled caverns; and to conduct nitrogen/brine interface MIT.

The Commission concurs that the testing frequency originally proposed could be too onerous for some cavern operators. Gas caverns would have to be emptied of product and filled with brine. The Commission proposes to extend the frequency of testing to ten years for liquid storage wells under §3.95(o)(3) and 15 years for gas storage wells under §3.97(o)(3), with the opportunity for a five-year extension of the time period for good cause.

A chemical company proposed a new requirement in §3.97(o)(1)(E) for the operator to notify the district office at least five days prior to conducting any integrity tests. The Commission notes that in §3.97(o)(1)(D) there is already a requirement that the operator must notify the district office at least five days prior to conducting any integrity tests.

A chemical company agreed that surface piping should be maintained and tested through an integrity management program as proposed in §3.95(o)(4).

A gas company and a pipeline association commented that language in §3.97(o)(4) regarding testing requirements for surface gas piping should be deleted because §8.101 of this title, relating to Pipeline Integrity Assessment and Management Plans for Natural Gas and Hazardous Liquids Pipelines, and administered and enforced by the Safety Division, already covers such testing. The addition of a point of pressure regulation as previously recommended by the gas company and the pipeline association in §3.97(h)(3)(A) will remove possible testing redundancy.

Based on these comments, the Commission has withdrawn the originally proposed amendments to §3.95 and §3.97, and is publishing revised proposed amendments for comment.

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 wellhead emergency shutdown valve and used to transport product, brine, or fresh water to or from a storage well whether such pipe is above or below ground level."

New definitions for "storage wellhead" and "surface piping" are needed because other proposed rule amendments specify that an emergency shutdown valve must be located between the storage wellhead and surface piping and such terms are not defined in the current rule.

The Commission proposes to amend §3.95(c)(4) to specify that a permit application must be filed for storing saltwater or brine in a pit, as well as for disposing of saltwater or other oil and gas waste arising out of or incidental to the creation, operation, or maintenance of an underground hydrocarbon storage facility.

The Commission 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 re-designate subsection (h)(2)(A) as subsection (h)(2)(D) and to add a new subsection (h)(2)(A), which would require that a storage wellhead be designed, operated, and maintained to contain the contents of the storage well and protect against the loss of stored product.

The Commission proposes to amend §3.95(h)(2)(B) to require that either 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 must install, as required, emergency shutdown valves in a position between the storage wellhead and the product and brine surface piping of each of hydrocarbon storage well and, if required, between the storage wellhead and fresh water surface piping of the well. The proposed amendment also allows an operator to file a request, within one year of the effective date of the section, for an exception to the storage wellhead configuration requirement or the compliance date of this subparagraph and to propose an alternative configuration for approval by the Commission or its designee.

The proposed amendment mandates locating the wellhead emergency shutdown valve directly between the wellhead and surface piping. This change in location of the wellhead emergency shutdown valve is intended to increase the safety of the emergency shutdown system. The current rule does not address the physical position or location of the emergency shutdown valve. Experience has shown that the emergency shutdown valve is most effective when the valve is flanged directly to the wellhead. The recent gas release and wellhead failure at a gas storage facility resulted, in part, from the location of an emergency valve on surface piping approximately 35 feet from the wellhead. After the emergency shutdown valve closed as designed, a pressure transient, believed related to water hammer, fractured the brine surface piping, allowing gas to escape and ignite. A water hammer-induced pressure transient also is implicated in at least two release incidents associated with the failure of surface piping at liquid hydrocarbon storage facilities operating at Mont Belvieu.

The Commission proposes to add a new §3.95(h)(3)(B) to require that brine surface piping be designed for the maximum operating pressure on the brine side of the well and designed to transport, under emergency conditions, product to the brine system vapor control system, unless protected by a secondary emergency shutdown valve and unless the brine surface piping between the wellhead emergency shutdown valve and the secondary emergency shutdown valve is designed for the permitted maximum allowable operating pressure on the hydrocarbon side of the well.

The Commission proposes to amend §3.95(h)(3)(C) (re-designated from subparagraph (B)) and add new §3.95(h)(3)(D) to clarify that the requirements in the subparagraph pertain to fresh water surface piping, and to clarify the requirement that such piping must be protected by an emergency shutdown valve, unless certain standards or design configurations are employed. For instance, fresh water surface piping that is disconnected from the wellhead or is connected to brine surface piping outboard of the emergency shutdown valve need not be protected by an emergency shutdown valve. Similarly, fresh water piping need not be protected by an emergency shutdown valve if it has a small internal diameter (less than two inches) and is designed to withstand the permitted maximum allowable operating pressure of the hydrocarbon side of the well and is monitored by an onsite attendant when in use. An emergency shutdown valve on small diameter (less than two inches) fresh water piping also is exempt from the requirement that the valve be located on the wellhead or separated from the wellhead by no more than a six-foot spool.

The Commission 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 that 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 a 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, designed for personnel rescue and equipment protection and cooling, be available at each storage wellhead in active storage service. The proposed new subparagraph would allow an operator to request Commission approval of an exception to this schedule or to the fire suppression requirement, as long as the request includes a proposal for an alternate schedule or means of protection from wellhead fire, and provided the request is made within one year of the effective date of the amendments.

The fire suppression requirement is intended to provide protection for rescue personnel and equipment cooling. The absence of such fire control systems contributed to the complete wellhead failure of a gas storage well and damage to adjacent structures associated with the gas release and fire at Moss Bluff Hub Partners. The fire suppression capability is not necessarily directed toward capacity sufficient to extinguish a wellhead fire. Extinguishing such a fire could be an imprudent course of action, unless the source of the leak was found and repaired. Rather, the fire suppression capability should be sufficient to provide for short-term protection for emergency personnel and for cooling of structures and wellheads potentially affected by a fire at a wellhead or surface pipe.

The Commission proposes to amend §3.95(h)(8), relating to emergency response plan, to delete a 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, within 30 days of any emergency, significant loss of fluids, significant mechanical failure, or other problem that increases the potential for an uncontrolled release, an operator file with the Commission a written report on the root cause of the incident, and, within 90 days of an incident, file with the Commission a written report describing the operational changes, if any, that will be implemented to reduce the likelihood of the recurrence of a similar incident. For good cause, the Commission may extend by up to 30 days the date by which an operator must file a report on the root cause of the incident. The current rule requires only written confirmation of an event within five working days of the event. The proposed amendments would 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 there has been at least one incident in which a driver lost control of a vehicle on a public road, causing the vehicle to leave the roadway and hit surface piping at a gas storage facility.

The Commission proposes to add new §3.95(h)(16), relating to wellhead, surface piping, and associated valves, to require that such piping and equipment be designed, installed, and operated in accordance with engineering standards appropriate to the expected service conditions to which the piping and equipment will be subjected.

The Commission proposes to amend §3.95(i)(6) to make a conforming change.

The Commission proposes to amend §3.95(k)(1) to clarify that the operating pressure of each hydrocarbon storage well may not exceed the permitted maximum allowable operating pressure. This 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 call for individual well metering of volumes injected and withdrawn in paragraph (3), and to add a new paragraph (5) on data recording. The new paragraph 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 record all emergency actuations of the emergency shutdown valve. This increased frequency of data recording is needed to insure that operators record sufficient information relating to the physical conditions that immediately precede an accident or incident to help diagnose the root cause or causes of an incident. Experience with several incidents at hydrocarbon storage facilities has revealed that operators did not record operational data at a sufficient frequency to help diagnose the root cause of the incident.

The Commission proposes to change the heading of §3.95(n) from "Records retention" to "Operations, construction, and maintenance records retention." The proposed amendments to subsection (n)(1) would require that operators retain electronic records of well pressures, flow rates, and hydrocarbon volumes for three months instead of five years. The proposed amendment would also add flow rates and hydrocarbon volumes to the record keeping requirement for each well, and would delete interface levels from the recording requirement. Because these operational data are primarily intended to diagnose accidents and incidents, long-term retention is unwarranted. The proposed amendments in subsection (n)(1) also clarify that the records of maximum wellhead pressures on the hydrocarbon and brine sides of each hydrocarbon storage well and the net volumes of hydrocarbons injected into and withdrawn from each hydrocarbon storage well which the operators are required to report to the Commission under subsection (m) must be retained for five years. Proposed amendments in subsection (n)(2) clarify that records associated with testing and performance measurement, required under subsection (l)(4), and testing of safety devices, required under subsection (h), must be retained for five years. The Commission proposes to change the heading of subsection (n)(3) from "Equipment data" to "Construction and maintenance data," and to require an operator to retain for the life of the facility documents and records pertaining to drilling, mining, and completion of storage wells, testing of storage well integrity, and major repairs on and workovers of the well. The extension of the retention period is prudent and necessary to insure that critical information on well construction, workovers, repairs, and testing is retained for the life of the facility. It is often necessary to examine the results of original completion, workovers, and testing procedures to properly interpret current test results, particularly for tests that have recurrence intervals of five years, such as mechanical integrity tests. Obviously, in cases where these records are currently unavailable, the Commission does not intend for the new requirement to be applied retroactively. However, with the new requirement, the Commission intends to insure that if the records currently are available, they will be preserved for the life of the facility, and will pass to future owners or operators of the facilities with the transfer of ownership or operatorship.

The Commission proposes to change the heading of §3.95(o) from "Testing" to "Testing and Maintenance." Proposed new paragraph (1) would require that all hydrocarbon storage wells drilled into salt domes with a single casing string cemented to the surface have the casing inspected by mechanical, ultrasonic, or magnetic methods at least once every five years and after each workover that involves physical changes to the cemented casing string. Currently, all operators of liquid hydrocarbon storage wells drilled into salt domes with a single casing string cemented to the surface are required by permit to have the casing inspected by mechanical, ultrasonic, or magnetic methods at least once every five years. Since the Commission and operators agreed to implement the permit conditions requiring such testing, the tests have detected significant casing damage, allowing the operators at four facilities to repair the damage ore remove the wells from service before a significant leak could occur. Nitrogen-brine mechanical integrity tests are not capable of detecting most classes of casing damage. The 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 at least every ten years. In addition, upon a showing of good cause, an operator may request an additional five-year extension. 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 for approval. 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 subsection (a) to amend the definitions of "emergency shutdown valve," "gas storage well or storage well," and "leak detector," and to add new definitions for the terms "storage wellhead" and "surface piping." The Commission 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; 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 during closure of the emergency shutdown valve as was the case at the recent gas release and fire at the gas storage facility described above. The Commission proposes to define "surface piping" as any pipe within a storage facility that is directly connected to a storage well and used to transport gas, brine, or fresh water to or from a storage well whether such pipe is above or below ground level. New definitions for "storage wellhead" and "surface piping" are needed because other proposed rule amendments specify that the emergency shutdown valve must be located between the storage wellhead and surface piping, and these terms are not defined in the 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." The Commission proposes to add a new subsection (h)(2)(A), which would require that a storage wellhead be designed, operated, and maintained to contain the contents of the storage well and protect against the loss of stored product. The Commission proposes to modify subparagraph (B) (re-designated from subparagraph (A)) to require that, within three years of the effective date of these amendments or in conjunction with the next mechanical integrity test of the storage cavern, the operator install, as required, emergency shutdown valves in a position between the wellhead and the gas injection/withdrawal surface piping of each storage well and between the wellhead and any brine or fresh water surface piping. In addition, the Commission 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 to propose an alternative configuration or workover schedule, provided that the request and alternative proposal are received within one year of the effective date of these amendments. The Commission or its designee must approve any such request. The Commission proposes to change the designation of §3.97(h)(2)(B) to §3.97(h)(2)(C).

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 paragraph (3) to subsection (h), relating to gas, brine, and fresh water piping. New subsection (h)(3)(A) would require that gas surface piping be designed for the permitted maximum allowable operating pressure on the hydrocarbon side. The Commission also proposes to specify that, for facilities under the administrative authority of the Commission's Safety Division, product surface piping extends from the wellhead emergency shutdown valve to the first point of downstream pressure regulation. This identifies the respective responsibilities of the Safety Division and of the Oil and Gas Division for hazardous materials piping for those facilities under the administrative authority of both divisions. The Oil and Gas Division is responsible for regulating all fresh water and brine surface piping at hydrocarbon storage facilities under the jurisdiction of the Railroad Commission of Texas. In addition, the Oil and Gas Division has administrative authority over all product surface piping directly connected to storage wells at those hydrocarbon storage facilities not under the administrative authority of the Safety Division, such as underground hydrocarbon storage facilities physically located within oil refineries. The Safety Division does not have administrative authority over storage facilities located within facilities that are not under Railroad Commission jurisdiction, such as oil refineries. The Safety Division also does not have administrative authority over piping that does not transport hazardous materials, such as fresh water or brine piping.

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 de-brining operations or solution mining operations conducted with gas in storage in the same cavern. It has always been the intent of the Commission that, in the event of the failure of some component, another method of overfill detection remains functional. The Commission intends to enhance the likelihood that the failure of a single device does not disable both methods of overfill detection.

The Commission 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 gas storage facility demonstrated that the potential for significant damage and risk to public heath and safety extends beyond 100 yards from a storage well or compressor station. The Commission 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 within 30 days of an incident, the operator file with the Commission a written report on the root cause of the incident and within 90 days of an incident, the operator file with the Commission a written report that describes the operational changes, if any, that will be implemented to reduce the likelihood of a recurrence of a similar incident. For good cause, the Commission may extend by up to 30 days the date by which an operator must file a report on the root cause of the 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 installed at each wellhead and designed for personnel rescue and equipment protection and cooling, unless the operator requests, within one year of the effective date of these amendments and the Commission or its designee approves, an exception to the schedule or fire suppression requirement. The fire suppression requirement is intended to provide protection for rescue personnel and equipment cooling. The absence of such fire control systems contributed to the complete wellhead failure of a gas storage well and damage to adjacent structures associated with the gas release and fire at Moss Bluff Hub Partners. The fire suppression capability is not necessarily intended to be sufficient to extinguish a wellhead fire. Extinguishing such a fire could be an imprudent course of action, unless the source of the leak was found and repaired. Rather, the Commission intends that the operator have capability sufficient to provide for short-term protection of emergency personnel protection and for cooling of structures and wellheads potentially affected by a fire from a well or surface pipe.

The Commission 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 associated valves be designed, installed, tested, maintained, and operated in accordance with engineering standards appropriate to the expected service conditions to which the piping and equipment will be subjected.

The Commission further 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 there has been at least one incident in which a driver lost control of a vehicle on a public road, causing the vehicle to leave the roadway and hit above ground piping at a gas storage facility.

The Commission 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 proposed in §3.97(h). The Commission also proposes to amend paragraph (3) to call for individual well metering of volumes injected and withdrawn, and to add a new paragraph (5), relating to data recording. The new paragraph 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 all 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 frequent intervals. The lack of electronically recorded data on operational conditions at a sufficient frequency has hindered the ability of operators and the Commission to understand operating conditions immediately preceding incidents at storage facilities.

The Commission 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. There is a new paragraph (2), which would require an operator to retain for at least five years the records of measurement performance under subsection (l)(4); and testing of safety devices under subsection (h). The records of any test of a safety device required under subsection (h) must be available for on-site inspection within 10 days of the date of the test. The Commission proposes to change the title of renumbered paragraph (3) from "Equipment data" to "Construction and maintenance data" and to amend this subsection to require that operators maintain documents and records on the drilling, mining, completion, major repairs, and workovers of storage wells and the testing of storage well integrity required under subsections (h) and (l) and that those records be retained for the life of the facility. The extension of the retention period is prudent and necessary to insure that critical information on well construction, repair, and workover and the testing of storage well integrity be retained for the life of the facility. It is often necessary to examine the results of past tests and procedures to properly interpret current tests, particularly tests that have recurrence intervals of five years, such as mechanical integrity tests. Obviously, in cases where these records currently are unavailable, the Commission does not intend that the new requirement be applied retroactively. However, the new requirement would insure that if the records are currently available, they will be preserved for the life of the facility and will pass for retention purposes to future owners and/or operators of the facilities with the transfer of ownership or operatorship.

The Commission 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 to the Commission for approval. 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 individuals, 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 individuals, 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 & 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 Leslie Savage at (512) 463-7308. The status of Commission rulemakings in progress is available at www.rrc.state.tx.us/rules/proposed.html.

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 July 6, 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 [ ~~well~~ ] from surface piping in the event of specified conditions that, if uncontrolled, may cause an emergency.

(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) - (10) (No change.)

(11) Operator--The person recognized by the Commission [ ~~commission~~ ] as being responsible for the physical operation of an underground hydrocarbon storage facility, or such person's authorized representative.

(12) Owner--The person recognized by the Commission [ ~~commission~~ ] as owning all or part of a storage facility, or such person's authorized representative.

(13) - (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 of less than six feet to be considered a part of the storage wellhead.

(17) Surface piping--Any pipe within a storage facility that is directly connected to a storage well, outboard of the wellhead emergency shutdown valve and used to transport product, brine, or fresh water to or from a storage well whether such pipe is above or below ground level.

(18) [ ~~(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.

(b) Permit required.

(1) General. No person may create, operate, or maintain an underground hydrocarbon storage facility without obtaining a permit from the Commission [ ~~commission~~ ]. A permit issued by the Commission [ ~~commission~~ ] for such activities before the effective date of this section shall continue in effect until revoked, modified, or suspended by the Commission [ ~~commission~~ ], or until it expires by its terms. The provisions of this section apply to permits for underground hydrocarbon storage facility operations issued prior to the effective date of this section, except as specifically provided in this section.

(2) Conflict with other requirements. If a provision of this section conflicts with any provision or term of a Commission [ ~~commission~~ ] order, field rule, or permit, the provision of such order, field rule, or permit shall control.

(1) Information required. An application for a permit to create, operate, or maintain an underground hydrocarbon storage facility shall be filed with the Commission [ ~~commission~~ ] by the owner or operator, or proposed owner or operator, on the prescribed form. The application shall contain the information necessary to demonstrate compliance with the applicable state laws and Commission [ ~~commission~~ ] regulations.

(2) Permit amendment. An application for amendment of an existing underground hydrocarbon storage facility permit shall be filed with the Commission [ ~~commission~~ ]:

(A) - (E) (No change.)

(3) Increase in capacity. The owner or operator of a storage facility shall notify the Commission [ ~~commission~~ ] if information indicates that the capacity of a cavern exceeds the permitted cavern capacity by 20% or more. Such notification shall be made in writing to the Commission [ ~~commission~~ ] within 10 days of the date that the owner or operator knows or has reason to know that the cavern capacity exceeds the permitted capacity by 20% or more. The notification shall include a description of the information that indicates that the permitted cavern capacity has been exceeded, and an estimate of the current cavern capacity. Upon receipt of such information, the Commission [ ~~commission~~ ] or its designee may take any one or more of the following actions:

(A) - (D) (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 [ ~~commission~~ ] requirements.

(d) Standards for underground storage zone.

(1) Geologic, construction, and operating performance [ ~~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.

(2) (No change.)

(e) Notice and hearing.

(1) Notice requirements. [ ~~Such notice shall be given no later than the date the application is mailed to or filed with the commission.~~ ] The applicant shall , no later than the date the application is mailed to or filed with the Commission, give notice of an application for a permit to create, operate, or maintain an underground hydrocarbon storage facility, or to amend an existing storage facility permit, by mailing or delivering a copy of the application form to:

(A) - (F) (No change.)

(2) Publication of notice. Notice of the application, in a form approved by the Commission [ ~~commission~~ ] or its designee, shall be published by the applicant once a week for three consecutive weeks in a newspaper of general circulation in the county or counties where the facility is or is proposed to be located. The applicant shall file proof of publication prior to any hearing on the application or administrative approval of the application.

(3) Notice by publication. The applicant shall make diligent efforts to ascertain the name and address of each person identified under paragraph (1)(A) - (D) of this subsection. The exercise of diligent efforts to ascertain the names and addresses of such persons shall require an examination of the county records where the facility is located and an investigation of any other information of which the applicant has actual knowledge. If, after diligent efforts, the applicant has been unable to ascertain the name and address of one or more persons required to be notified under paragraph (1)(A) - (D) of this subsection, the notice requirements for those persons are satisfied by the publication of the notice of application as required in paragraph (2) of this subsection. The applicant must submit an affidavit to the Commission [ ~~commission~~ ] specifying the efforts that were taken to identify each person whose name and/or address could not be ascertained.

(4) Hearing required for new permits. A permit application for a new underground hydrocarbon storage facility will be considered for approval only after notice and hearing. The Commission [ ~~commission~~ ] will give notice of the hearing to all affected persons, local governments, and other persons who express, in writing, an interest in the application. After hearing, the examiner shall recommend a final action by the Commission [ ~~commission~~ ].

(5) Hearing on permit amendments.

(A) An application for an amendment to an existing storage facility permit may be approved administratively if the Commission [ ~~commission~~ ] receives no protest from a person notified pursuant to the provisions of paragraph (1) of this subsection, or from any other affected person.

(B) If the Commission [ ~~commission~~ ] receives a protest from a person notified pursuant to paragraph (1) of this subsection or from any other affected person within 15 days of the date of receipt of the application by the Commission [ ~~commission~~ ], or of the date of the third publication, whichever is later, or if the Commission [ ~~commission~~ ] determines that a hearing is in the public interest, then the applicant will be notified that the application cannot be approved administratively. The Commission [ ~~commission~~ ] will schedule a hearing on the application upon written request of the applicant. The Commission [ ~~commission~~ ] will give notice of the hearing to all affected persons, local governments, and other persons who express, in writing, an interest in the application. After hearing, the examiner shall recommend a final action by the Commission [ ~~commission~~ ].

(C) If the application is administratively denied, a hearing will be scheduled upon written request of the applicant. After hearing, the examiner shall recommend a final action by the Commission [ ~~commission~~ ].

(f) Modification, cancellation, or suspension of a permit.

(1) General. Any permit may be modified, suspended, or canceled after notice and opportunity for hearing if:

(A) a material change in conditions has occurred in the operation, maintenance, or construction of the storage facility, or there are material deviations from the information originally furnished to the Commission [ ~~commission~~ ]. A change in conditions at a facility that does not affect the safe operation of the facility or the ability of the facility to operate without causing waste of hydrocarbons or pollution is not considered to be material;

(B) (No change.)

(C) there are material violations of the terms and provisions of the permit or Commission [ ~~commission~~ ] regulations;

(D) - (E) (No change.)

(2) Imminent dangers. Notwithstanding the provisions of paragraph (1) of this subsection, in the event of an emergency that presents an imminent danger to life or property, or where waste of hydrocarbons, uncontrolled escape of hydrocarbons, or pollution of fresh water is imminent, the Commission [ ~~commission~~ ] or its designee may immediately suspend a storage facility permit until a final order is issued pursuant to a hearing, if any, conducted in accordance with the provisions of paragraph (1) of this subsection. All operations at the facility shall cease upon suspension of a permit under this paragraph.

(g) Transfer of permit. A storage facility permit may not be transferred without the prior approval of the Commission [ ~~commission~~ ] or its designee. Until such transfer is approved by the Commission [ ~~commission~~ ] or its designee, the proposed transferee may not conduct any activities otherwise authorized by the permit. The following procedure shall be followed when requesting approval for transfer of a permit.

(1) Request. Prior to transferring either ownership or operation of a storage facility, the permittee shall file a request for transfer of the permit with the Commission [ ~~commission~~ ]. Such request may not be filed unless a completed Form P-4, signed by both the permittee and the proposed transferee, has been filed with the Commission [ ~~commission~~ ].

(2) Approval. The Commission [ ~~commission~~ ], or its designee, shall approve the transfer of a storage facility permit, provided:

(A) the proposed transferee is not the subject of any unsatisfied Commission [ ~~commission~~ ] enforcement order at the time of the request for permit transfer; and

(B) there are no existing violations of any Commission [ ~~commission~~ ] regulation, order, or permit at the storage facility at the time of the request for permit transfer that have been documented by the Commission [ ~~commission~~ ], or its employees, unless the proposed transferee agrees to correct the violations according to a compliance schedule approved by the Commission [ ~~commission~~ ], or its designee.

(3) Good cause. Notwithstanding paragraph (2) of this subsection, for good cause shown the Commission [ ~~commission~~ ] or its designee may require public notice and opportunity for hearing prior to taking action on a request for transfer of a permit. Such request may be denied after notice and opportunity for hearing if the Commission [ ~~commission~~ ] or its designee finds that transfer of the permit would not be in the public interest.

(h) Safety. The following safety requirements shall apply to all underground hydrocarbon storage facilities, except as specifically provided otherwise , provided [ ~~. Provided~~ ], however, that the provisions of this subsection shall not apply to any hydrocarbon storage well that is out of service and disconnected from all surface piping. Notwithstanding the compliance time periods specified in [ ~~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.

(1) (No change.)

(2) Storage wellhead [ ~~Emergency shutdown valves~~ ].

(A) The storage wellhead shall be designed, operated, and maintained to contain the contents of the storage well and protect against loss of stored product.

[ ~~(A)~~ ~~The requirements of this paragraph do not apply to underground hydrocarbon storage facilities storing only crude oil.~~ ]

(B) Either within three 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 the product and brine surface piping of each hydrocarbon storage well and, if required under paragraph (3) of this subsection, between the storage wellhead and fresh water surface piping of the well. Within one year of the effective date of the section, an operator may request an exception to the storage wellhead configuration or compliance date of this subparagraph and propose an alternative configuration or workover schedule for approval by the Commission or its designee. A storage well that is out of service and is disconnected from surface piping shall be exempt from this requirement until reactivated for active hydrocarbon storage. Emergency shutdown valves shall meet the following requirements.

[ ~~(B)~~ Within two years of the effective date of this section, emergency shutdown valves shall be installed on the product and brine sides of each hydrocarbon storage well and, if required under paragraph (3) of this subsection, on fresh water piping to the well. An operator may request an exception to the compliance date of this subparagraph and propose an alternative workover schedule for approval by the commission or its designee. A storage well that is out of service and is disconnected from surface piping shall be exempt from this requirement until reactivated for hydrocarbon storage. Emergency shutdown valves shall meet the following requirements. ]

(i) Each emergency shutdown valve shall be capable of activation at each storage well, at the on-site control center if one exists, at the remote control center if one exists, and at a location that is reasonably anticipated to be accessible to emergency response personnel at any facility that does not have an on-site control center that is attended 24 hours per day.

(ii) Each emergency shutdown valve shall be an automatic fail-closed valve that automatically closes when there is a loss of pneumatic pressure, hydraulic pressure, or power to the valve.

(iii) Each emergency shutdown valve shall be closed and opened at least monthly.

(iv) Each emergency shutdown valve system shall be tested at least twice each calendar year at intervals not to exceed 7 1/2 months. The test shall consist of activating the actuation devices, checking the warning system, and observing the valve closure.

(D) The requirements of this paragraph do not apply to underground hydrocarbon storage facilities storing only crude oil.

(3) Product, brine, [ ~~Brine~~ ] and fresh water surface piping.

(A) Product surface piping shall be designed for the permitted maximum allowable operating pressure on the hydrocarbon side of the well. For facilities with hazardous materials surface piping under the administrative authority of the Safety Division of the Railroad Commission of Texas, for the purposes of this section, product surface piping extends from the wellhead emergency shutdown valve to the first pressure regulation device, including a manual, motor-operated, or emergency shutdown valve.

[ ~~(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.~~ ]

(B) Brine surface piping shall be designed for the maximum brine wellhead pressure and to transport, under emergency conditions, product to the brine system gas vapor control system described in paragraph (6) of this subsection unless:

(i) a secondary emergency shutdown valve is in operation on the brine surface piping; and

(ii) the brine surface piping between the wellhead emergency shutdown valve and the secondary emergency shutdown valve is designed for the permitted maximum allowable operating pressure on the hydrocarbon side of the well.

(C) [ ~~(B)~~ ] Fresh water surface piping, if any, must [ ~~either~~ ] be equipped with a wellhead emergency shutdown valve unless it is :

(i) disconnected [ ~~isolated~~ ] from the wellhead [ ~~when fresh water is not being injected into the well~~ ]; or

(ii) connected to brine surface piping outboard of the wellhead emergency shutdown valve; or

(iii) [ ~~(ii)~~ ] designed for the permitted maximum allowable operating [ ~~wellhead~~ ] pressure on the hydrocarbon side of the well ; and has an internal diameter of less than or equal to two inches; and an attendant is posted at the well site to provide immediate manual shut-in when in use [ ~~and equipped with an emergency shutdown valve~~ ].

(D) Fresh water piping designed for the permitted maximum allowable operating pressure on the hydrocarbon side of the well and with an internal diameter of less than or equal to two inches is exempt from the requirement that an emergency shutdown valve be located on the wellhead or separated from the wellhead by a spool no longer than six feet.

(4) Overfill detection and automatic shut-in methods.

(A) - (B) (No change.)

(C) Within one year of the effective date of this section, each storage cavern shall have at least two [ ~~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~~ ]:

(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) - (iv) (No change.)

(v) an alternate device or method approved by the Commission [ ~~commission~~ ] or its designee.

(5) Leak detectors.

(A) (No change.)

(B) A [ ~~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.

(C) Leak [ ~~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).

(D) (No change.)

(6) Brine system gas vapor control.

(A) (No change.)

(B) Gas [ ~~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:

(i) - (iv) (No change.)

(7) Fire detection devices or methods and fire control systems .

(A) Fire [ ~~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:

(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 designed to aid in personnel rescue and for equipment protection and cooling. Within one year of the effective date of this section, the operator may request an exception to the schedule or fire suppression requirement of this subparagraph and propose an alternative schedule or means of protection from wellhead fire for approval of the Commission or its designee.

(8) Emergency response plan. Each [ ~~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.

(9) Notification of emergency or uncontrolled release.

(A) (No change.)

(B) Commission. The operator shall report to the appropriate Commission [ ~~commission~~ ] district office as soon as practicable any emergency, significant loss of fluids, significant mechanical failure, or other problem that increases the potential for an uncontrolled release. The operator shall file with the Commission within 30 days of the incident a written report on the root cause of the incident. The operator shall file with the Commission within 90 days of the incident a written report that describes the operational changes, if any, that have been or will be implemented to reduce the likelihood of a recurrence of a similar incident. An operator may request that the Commission grant, for good cause, an additional 30 days to file a written report on the root cause of the incident [ ~~confirm the report in writing within five working days~~ ].

(10) Public education. Each [ ~~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.

(11) Annual emergency drill. Annually, each operator shall conduct a drill that tests response to a simulated emergency. Written notice of the drill shall be provided to the appropriate Commission [ ~~commission~~ ] district office, the county emergency management coordinator, and the county sheriff's office at least seven days prior to the drill. Local emergency response authorities shall be invited to participate in all such drills. The operator shall file a written evaluation of the drill and plans for improvements with the appropriate district office and the county emergency management coordinator within 30 days after the date of the drill.

(12) Employee safety training.

(A) Each [ ~~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.

(B) (No change.)

(13) Warning systems and alarms.

(A) All [ ~~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.

(B) A manually operated alarm shall be installed at each attended storage facility [ ~~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.

(14) Wind socks. At [ ~~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.

(15) Barriers. 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, and surface hydrocarbon storage vessels in areas where vehicles may normally be expected to travel or within 100 feet of a public road .

(16) Wellhead, surface piping, and associated valves. All wellhead equipment, product, fresh water, and brine surface piping, and associated valves shall be designed, installed, and operated in accordance with engineering standards to the expected service conditions to which the piping and equipment will be subjected.

(i) Cavern capacity and configuration.

(1) - (3) (No change.)

(4) Bedded salt. The configuration of the roof of each hydrocarbon storage cavern in bedded salt shall be determined by downhole log or an alternate method approved by the Commission [ ~~commission~~ ] or its designee at least once every five years.

(5) Filing results. Sonar and roof monitoring survey results shall be filed with the Commission [ ~~commission~~ ] within 30 days after the survey.

(6) Out-of-service caverns. A sonar or roof monitoring survey is not required for a cavern that is out of service. A sonar or roof monitoring survey shall be performed before any cavern that has been out of service is returned to service , unless the provisions of paragraph (2) of this subsection apply .

(j) Well completion, casing, and cementing. Hydrocarbon storage wells shall be cased and the casing strings cemented to prevent fluids from escaping to the surface or into fresh water strata, or otherwise escaping and causing waste or endangering public safety or the environment.

(1) (No change.)

(2) Well completion report. A well completion report shall be filed in accordance with the instructions on the form prescribed by the Commission [ ~~commission~~ ] within 30 days after a storage well is completed and before solution mining to create the cavern begins.

(k) Operating requirements.

(1) Operating pressure. The operating pressure of each hydrocarbon storage well shall not exceed the permitted maximum allowable operating pressure for that well. The permitted maximum allowable operating pressure is that pressure specified in the Commission [ ~~commission~~ ] permit or order, or, if not specified in the permit or order, that pressure stated in the application or the application for amendment to a permit or order. The maximum operating pressure at the shoe of the lowermost cemented casing shall not exceed 0.8 pounds per square inch per foot of depth.

(2) Volume of hydrocarbons stored. The quantity of hydrocarbons stored in a cavern shall not exceed the permitted maximum storage volume for that cavern. The permitted maximum hydrocarbon storage volume is that volume specified in the Commission [ ~~commission~~ ] permit or order, or, if not specified in the permit or order, that volume stated in the application or the application for amendment to a permit or order.

(l) Monitoring requirements.

(1) - (2) (No change.)

(3) Volumes injected and withdrawn. The volume of hydrocarbons injected into and withdrawn from each hydrocarbon storage well shall be measured by:

(A) flow meter for each well ; or

(B) an alternate method approved by the Commission [ ~~commission~~ ] or its designee.

(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, volumes, and flow rates at a frequency of at least once per minute, and all actuations of the emergency shutdown valve.

(m) Reporting. The operator shall report maximum wellhead pressures on the hydrocarbon and brine sides of each hydrocarbon storage well and the net volumes of hydrocarbons injected into and withdrawn from each hydrocarbon storage well in accordance with the instructions on the annual report form prescribed by the Commission [ ~~commission~~ ].

(n) Operations, construction, and maintenance records [ ~~Records~~ ] retention.

(1) Hydrocarbon injection and withdrawal data. The operator shall retain for at least three months all electronic [ ~~five years~~ ] records of hydrocarbon storage well pressures, flow rates, and hydrocarbon volumes [ ~~interface levels (if any), hydrocarbons~~ ] injected into and withdrawn from each well, and the hydrocarbon inventory of each cavern. The operator shall retain for at least five years the records, reported to the Commission under subsection (m) of this section, of maximum monthly wellhead pressures on the hydrocarbon and brine sides of each hydrocarbon storage well and the monthly net volumes of hydrocarbons injected into and withdrawn from each hydrocarbon storage well.

(2) Records retention. The operator shall retain for at least five years the records of measurement performance under subsection (l)(4) of this section; and testing of safety devices under subsection (h) of this section. Records of any test of a safety device required under subsection (h) of this section shall be available for on-site inspection within 10 days of the date of the test.

(3) [ ~~(2)~~ ] Construction and maintenance [ ~~Equipment~~ ] data. The operator shall retain for the life of the facility [ ~~five years~~ ] documents and records pertaining to the drilling, mining, completion, major repairs, and workovers of storage wells and testing of storage well integrity, and shall transfer all such documents and records to any new owner and/or new operator of the facility. [ installation, inspection, maintenance, and testing of equipment required under subsections (h) and (l) of this section. Records of any test of a safety device required under subsection (h) of this section shall be available for on-site inspection within 10 days of the date of the test. ]

(4) [ ~~(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 [ ~~five-year~~ ] period until the resolution of such proceeding.

(o) Testing and maintenance .

(1) Integrity tests for wells in salt domes with a single casing string. Each hydrocarbon storage well drilled into a salt dome and having a single casing string cemented to the surface shall have the casing inspected by mechanical, ultrasonic, or magnetic methods at least once every five years and after each workover that involves physical changes to the cemented casing string.

(2) [ ~~(1)~~ ] Integrity tests for wells other than those in salt domes with a single casing string . Each hydrocarbon storage well shall be tested for integrity prior to being placed into service, at least once every five years, and after each workover that involves physical changes to any cemented casing string. The following requirements apply to all such integrity tests.

(A) A hydrocarbon storage well shall be tested for integrity by the nitrogen-brine interface method or an alternative approved by the Commission [ ~~commission~~ ], or its designee.

(B) A test procedure shall be filed with the Commission [ ~~commission~~ ] for approval at least 10 days before the test date.

(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 at least once every 10 years. The operator may request a five-year extension from the Commission for good cause.

(4) Product, fresh water, and brine surface piping. Within one year of the effective date of this section, the operator shall submit a piping integrity management plan for approval by the Commission or its designee. Within three years of the effective date of this section, or in conjunction with the storage well integrity testing, all product, freshwater, and brine surface piping shall be maintained according to the facility's piping integrity management plan.

(5) [ ~~(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.

(p) Plugging.

(1) Plug on abandonment. A hydrocarbon storage well shall be plugged upon permanent abandonment in a manner approved by the Commission [ ~~commission~~ ] or its designee. A proposal for plugging shall be submitted to the Commission [ ~~commission~~ ] in Austin for approval or modification prior to plugging. Following approval of a plugging plan, the operator shall file a notification of intent to plug at least five days prior to commencement of plugging operations. A plugging report shall be filed with the Commission [ ~~commission~~ ] in Austin within 30 days after plugging.

(2) Alternative monitoring. As an alternative to plugging a hydrocarbon storage well that has been permanently deactivated, an operator may request approval by the Commission [ ~~commission~~ ] or its designee of a plan to convert the storage well to a monitor well. A pressure monitoring plan must be submitted to the Commission [ ~~commission~~ ] along with the request to convert the storage well to a monitoring well.

(q) Penalties.

(1) Penalties. Violations of this section may subject the operator to penalties and remedies specified in the Texas Natural Resources Code, Titles 3 and 11, and other statutes administered by the Commission [ ~~commission~~ ].

(2) (No change.)

(r) Applicability of other Commission [ ~~commission~~ ] rules and orders. The owner or operator of an underground hydrocarbon storage facility is not relieved by this section of compliance with any other requirement of Chapters 3, 4, 7, or 8 of this title (relating to Oil and Gas Division; Environmental Protection; Gas Services Division; or Pipeline Safety Regulations).

§3.97.Underground Storage of Gas in Salt Formations.

(a) Definitions. The following terms, when used in this section, shall have the following meanings, unless the context clearly indicates otherwise.

(1) - (3) (No change.)

(4) Emergency shutdown valve--A valve that automatically closes to isolate a gas storage wellhead [ ~~well~~ ] from surface piping in the event of specified conditions that, if uncontrolled, may cause an emergency.

(5) (No change.)

(6) Gas storage well or storage well--A well , including the storage wellhead, casing, tubing, borehole, and cavern used for the injection or withdrawal of natural gas or any other gaseous substance into or out of an underground gas storage facility.

(7) Leak or fire detector--A device capable of detecting by chemical or physical means the presence of gas [ ~~hydrocarbon vapor~~ ] or the escape of gas or the presence of flame or heat of a fire [ ~~vapor through a small opening~~ ].

(8) Operator--The person recognized by the Commission [ ~~commission~~ ] as being responsible for the physical operation of an underground gas storage facility, or such person's authorized representative.

(9) Owner--The person recognized by the Commission [ ~~commission~~ ] as owning all or part of an underground gas storage facility, or such person's authorized representative.

(10) - (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 wellhead emergency shutdown valve and used to transport gas, brine, or fresh water to or from a storage well whether such pipe is above or below ground level.

(14) [ ~~(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.

(b) Permit required.

(1) General. No person may create, operate, or maintain an underground gas storage facility without obtaining a permit from the Commission [ ~~commission~~ ]. A permit issued by the Commission [ ~~commission~~ ] for such activities before the effective date of this section shall continue in effect until revoked, modified, or suspended by the Commission [ ~~commission~~ ], or until it expires according to its terms. The provisions of this section apply to permits to conduct gas storage operations issued prior to the effective date of this section, except as otherwise specifically provided.

(1) Information required. An application for a permit to create, operate, or maintain an underground gas storage facility shall be filed with the Commission [ ~~commission~~ ] by the owner or operator, or the proposed owner or operator, on the prescribed form. The application shall contain the information necessary to demonstrate compliance with applicable state laws and Commission [ ~~commission~~ ] regulations.

(2) Permit amendment. An application for amendment of an existing underground gas storage facility permit shall be filed with the Commission [ ~~commission~~ ]:

(A) - (E) (No change.)

(3) Increase in capacity. The owner or operator of a storage facility shall notify the Commission [ ~~commission~~ ] if information indicates that the capacity of a cavern exceeds the permitted cavern capacity by 20% or more. Such notification shall be made in writing to the Commission [ ~~commission~~ ] within 10 days of the date that the owner or operator of the storage facility knows or has reason to know that the cavern capacity exceeds the permitted capacity by 20% or more. The notification shall include a description of the information that indicates that the permitted cavern capacity has been exceeded, and an estimate of the current cavern capacity. Upon receipt of such information, the Commission [ ~~commission~~ ] or its designee may take any one or more of the following actions:

(A) - (D) (No change.)

(d) Standards for underground storage zone.

(1) Geologic, construction, and operating performance [ ~~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.

(2) (No change.)

(e) Notice and hearing.

(A) - (F) (No change.)

(2) Publication of notice. Notice of the application, in a form approved by the Commission [ ~~commission~~ ] or its designee, shall be published by the applicant once a week for three consecutive weeks in a newspaper of general circulation in the county where the storage facility is or is proposed to be located. The applicant shall file proof of publication prior to any hearing on the application or administrative approval of the application.

(3) Notice by publication. The applicant shall make diligent efforts to ascertain the name and address of each person identified under paragraph (1)(A) - (D) of this subsection. The exercise of diligent efforts to ascertain names and addresses of such persons shall require an examination of the county records where [ ~~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 [ ~~commission~~ ] specifying the efforts that were taken to identify each person whose name and/or address could not be ascertained.

(4) Hearing required for new permits. A permit application for a new underground gas storage facility will be considered for approval only after notice and hearing. The Commission [ ~~commission~~ ] will give notice of the hearing to all affected persons, local governments, and other persons who express, in writing, an interest in the application. After hearing, the examiner shall recommend a final action by the Commission [ ~~commission~~ ].

(5) Hearing on permit amendments.

(A) An application for an amendment to an existing storage facility permit may be approved administratively if the Commission [ ~~commission~~ ] receives no protest from a person notified pursuant to paragraph (1) of this subsection or from any other affected person.

(f) Modification, cancellation, or suspension of a permit.

(1) General. Any permit may be modified, suspended, or canceled after notice and opportunity for hearing if:

(B) (No change.)

(C) there are material violations of the terms and provisions of the permit or Commission [ ~~commission~~ ] regulations;

(D) - (E) (No change.)

(2) Imminent danger. Notwithstanding the provisions of paragraph (1) of this subsection, in the event of an emergency that presents an imminent danger to life or property, or where waste of hydrocarbons, uncontrolled escape of hydrocarbons, or pollution of fresh water is imminent, the Commission [ ~~commission~~ ] or its designee may immediately suspend a storage facility permit until a final order is issued pursuant to a hearing, if any, conducted in accordance with the provisions of paragraph (1) of this subsection. All operations at the facility shall cease upon suspension of a permit under this paragraph.

(g) Transfer of permit. A storage facility permit may not be transferred without the prior approval of the Commission [ ~~commission~~ ], or its designee. Until such transfer is approved by the Commission [ ~~commission~~ ] or its designee, the proposed transferee may not conduct any activities authorized by the permit. The following procedure shall be followed when requesting approval for transfer of a permit.

(1) Request. Prior to transferring either ownership or operation of a storage facility, the permittee shall file with the Commission [ ~~commission~~ ] a request for transfer of the permit. Such a request may not be filed unless a completed Form P-4, signed by both the permittee and the proposed transferee, has been filed with the Commission [ ~~commission~~ ].

(2) Approval. The Commission [ ~~commission~~ ], or its designee, shall approve the transfer of a storage facility permit, provided:

(A) the proposed transferee is not the subject of any unsatisfied Commission [ ~~commission~~ ] enforcement order at the time of the request for permit transfer; and

(3) Good cause. Notwithstanding paragraph (2) of this subsection, for good cause shown the Commission [ ~~commission~~ ], or its designee, may require public notice and opportunity for hearing prior to taking action on a request for transfer of a permit. Such request may be denied after notice and opportunity for hearing if the Commission [ ~~commission~~ ] or its designee finds that transfer of the permit would not be in the public interest.

(h) Safety. The following safety requirements shall apply to all underground gas storage facilities , provided [ ~~. 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 [ ~~Emergency shutdown valves~~ ].

(A) The storage wellhead must be designed, operated, and maintained to contain the contents of the storage well and protect against loss of stored product.

(B) [ ~~(A)~~ ] Either within three [ ~~Within 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~~ ]. 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 : [ . ]

(ii) Each emergency shutdown valve shall be an automatic fail-closed valve that automatically closes when there is a loss of pneumatic or hydraulic pressure on, or power to, the valve or when the maximum operating pressure under subsection (k) of this section is exceeded.

(iii) Each emergency shutdown valve shall be closed and opened at least monthly.

(C) [ ~~(B)~~ ] If an emergency shutdown valve system fails to operate as required, the well shall be immediately shut in until repairs are completed, unless:

(i) a backup emergency shutdown valve is in operation on the same piping; or

(ii) an attendant is posted at the well site to provide immediate manual shut-in.

(3) Gas, brine, and fresh water surface piping.

(A) Gas surface piping shall be designed for the permitted maximum allowable operating pressure on the hydrocarbon side of the well. For facilities with hazardous materials surface piping under the administrative authority of the Safety Division of the Railroad Commission of Texas, for the purposes of this section, gas surface piping extends from the wellhead emergency shutdown valve to the first pressure regulation device, including a manual, motor-operated, or emergency shutdown valve.

(B) Brine piping, if any, shall be designed for the maximum brine wellhead pressure and to transport, under emergency conditions, gas to a gas control system if the operator is solution mining while the gas storage well is in active storage service, unless:

(i) a secondary emergency shutdown valve is in operation on the brine surface piping; and

(i) disconnected from the wellhead; or

(ii) connected to the brine surface piping outboard of the wellhead emergency shutdown valve; or

(iii) designed for the maximum allowable operating pressure on the hydrocarbon side of the well; and has an internal diameter of less than or equal to two inches; and an attendant is posted at the well site to provide immediate manual shut-in when in use.

(D) Fresh water piping designed for the permitted maximum allowable operating pressure on the hydrocarbon side of the well and with an internal diameter of less than or equal to two inches, is exempt from the requirement that an emergency shutdown valve be separated from the wellhead by a spool no longer than six feet.

(4) [ ~~(3)~~ ] Cavern debrining and solution mining operations.

(A) Within one year of the effective date of this section, each storage well shall have two [ ~~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:

(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 [ ~~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) [ ~~(4)~~ ] Leak or fire detectors.

(A) Within two years of the effective date of this section, a leak or fire detector shall be installed and in operation at each gas storage well and each structurally enclosed compressor site [ 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 ].

(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) [ ~~(5)(A)~~ ] of this subsection.

(6) [ ~~(5)~~ ] Warning systems and alarms.

(A) Within two years of the effective date of this section, all leak or fire detectors and [ ~~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.

(B) A manually operated audible alarm shall be installed at each attended storage facility [ ~~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.

(7) [ ~~(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.

(8) [ ~~(7)~~ ] Notification of emergency or uncontrolled release.

(A) Emergency response personnel. Each operator shall notify the county sheriff's office, the county emergency management coordinator, and any other appropriate public officials which are identified in the emergency response plan of any emergency that could endanger nearby residents or property. Such emergencies include, but are not limited to, an uncontrolled release of hydrocarbons from a storage well or a leak or fire at any area of the storage facility. The operator shall give notice as soon as practicable following the discovery of the emergency. At the time of the notice, the operator shall also report an assessment of the potential threat to the public.

(B) Commission. The operator shall report to the appropriate Commission [ ~~commission~~ ] district office as soon as practicable any emergency, significant loss of gas or fluids, significant mechanical failure, or other problem that increases the potential for an uncontrolled release. The operator shall file with the Commission within 30 days of the incident a written report on the root cause of the incident. Within 90 days of the incident, the operator shall file with the Commission a written report that describes the operational changes, if any, that have been or will be implemented to reduce the likelihood of a recurrence of a similar incident. An operator may request that the Commission grant, for good cause, an additional 30 days to file a written report on the root cause of the incident [ ~~confirm the report in writing within five working days~~ ].

(9) [ ~~(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 [ ~~commission~~ ] district office, the county emergency management coordinator, and the county sheriff's office at least seven days prior to the drill. Local emergency response authorities shall be invited to participate in all such drills. The operator shall file a written evaluation of the drill and plans for improvements with the appropriate district office and the county emergency management coordinator within 30 days after the date of the drill.

(10) [ ~~(9)~~ ] Employee safety training.

(A) Each [ ~~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.

(B) Each operator shall hold a safety meeting with each contractor prior to the commencement of any new contract work at an underground gas storage facility. Emergency measures, including safety and evacuation measures specific to the contractor's work, shall be explained in the contractor safety meeting.

(11) Fire suppression capability.

(A) Within three years of the effective date of this section, each operator shall have fire suppression capability designed to aid in personnel rescue and equipment protection and cooling.

(B) Within one year of the effective date of this section, the operator may request an exception to the schedule or fire suppression requirement of this paragraph and propose an alternative schedule or means of protection from wellhead fire for approval of the Commission or its designee.

(12) Wellhead, piping, and associated valves. All wellhead surface piping and associated valves shall be designed, installed, and operated in accordance with engineering standards to the expected service conditions to which the piping and equipment will be subjected.

(13) Barriers. Within one year of the effective date of this section, barriers designed to prevent unintended impact by vehicles and equipment shall be placed around above grade hydrocarbon piping, hydrocarbon process equipment where vehicles may normally be expected to travel, or within 100 feet of a public road.

(i) Cavern capacity and configuration.

(1) (No change.)

(2) Salt domes. The capacity and configuration of each salt dome gas storage cavern shall be determined by sonar survey before a cavern that has been out of service is returned to service , provided [ ~~. Provided~~ ], however, that a sonar survey shall not be required on a cavern that is being returned to service if a sonar survey of that cavern has been run at any time during the previous 10 years.

(3) Bedded salt. The configuration of the roof of each gas storage cavern in bedded salt shall be determined by downhole log or an alternate method approved by the Commission [ ~~commission~~ ], or its designee, at least once every five years.

(4) Filing of results. Sonar and roof monitoring survey results shall be filed with the Commission [ ~~commission~~ ] within 30 days after the survey.

(5) Out-of-service caverns. A sonar or roof monitoring survey is not required for a cavern that is out of service. A sonar or roof monitoring survey shall be performed before any such cavern that has been out of service is returned to service , unless the provisions of paragraph (2) of this subsection apply .

(6) (No change.)

(j) Well completion, casing, and cementing. Gas storage wells shall be cased and the casing strings cemented to prevent gases from escaping to the surface or into fresh water strata, or otherwise escaping and causing waste or endangering public safety or the environment.

(1) (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 [ ~~commission~~ ] permit or order, or, if not specified in the permit or order, that pressure stated in the application or the application for amendment to a permit or order.

(2) (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 , [ ~~and~~ ] alarms , and emergency shutdown valve actuation system as required in subsection (h)(2)(B) and (h)(6)(A) [ ~~(h)(5)(A)~~ ] of this section.

(2) (No change.)

(3) Volumes injected and withdrawn. The volume of gas injected into and withdrawn from each storage well shall be determined:

(A) by flow meter [ ~~volume data from the master meter and records of pressure change~~ ] for each well; or

(B) by an alternate method approved by the Commission [ ~~commission~~ ].

(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) Reporting.

(1) Monthly reports. On or before the last day of each month, the operator of each facility that stores gas to supply a public utility shall file with the Commission [ ~~commission~~ ] a report showing the volume of gas placed into storage and the volume of gas removed from storage at the storage facility, during the preceding month. The report shall also state the total volume of gas in storage on the first and last days of the preceding month. This report shall be filed in a format acceptable to the Commission [ ~~commission~~ ] or its designee.

(2) Annual reports. The operator shall file annually a status report for each storage well in accordance with the instructions on the form prescribed by the Commission [ ~~commission~~ ].

(n) Operations, construction, and maintenance records [ ~~Records~~ ] retention.

(1) Operations [ ~~Gas injection and withdrawal~~ ] data. The operator shall retain for at least three months all electronic [ ~~five years~~ ] records of storage well pressures, volumes of gases injected and withdrawn, and the inventory of gas in storage. The operator shall retain for at least five years the records reported to the Commission under subsection (m).

(3) [ ~~(2)~~ ] Construction and maintenance [ ~~Equipment~~ ] data. The operator shall retain for the life of the facility [ ~~five years~~ ] documents and records pertaining to the drilling, mining, completion, repair and workover of storage wells and the testing of storage well integrity, and shall transfer all such documents and records to any new owner and/or new operator of the facility [ ~~installation, inspection, maintenance, and testing of equipment relating to the safe operation of the storage facility~~ ].

(4) [ ~~(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. [ 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. ]

(o) Testing and maintenance .

(1) Integrity tests. Each gas storage well shall be tested for integrity prior to being placed into service, at least once every five years, and after each workover that involves physical changes to any cemented casing string. The following requirements apply to such integrity tests.

(A) A test procedure shall be filed with the Commission [ ~~commission~~ ] for approval at least 10 days before the test date.

(B) The initial test conducted on a well prior to placing it into service shall be performed using the nitrogen-interface test method or an alternative method approved by the Commission [ ~~commission,~~ ] or its designee.

(2) Alternative monitoring. An operator may request the Commission [ ~~commission~~ ] or its designee to approve well pressure monitoring as an alternative to integrity testing for storage wells that are out of gas storage service. An out-of-service well shall be tested for integrity by the nitrogen-interface method before it may be returned to storage service.

(3) Storage wellhead. Storage wellhead components, including spool pieces, shall be inspected and pressure tested to 125 percent of the permitted maximum allowable operating pressure at least once every 15 years. The operator may request a five-year extension from the Commission for good cause.

(4) Fresh water, brine, and gas surface piping. Within one year of the effective date of this section, the operator shall submit a piping integrity management plan for approval by the Commission or its designee. Within three years of the effective date of this section, or in conjunction with the storage well integrity testing, all gas, freshwater, and brine surface piping shall be maintained according to the facility's piping integrity management plan.

(p) Plugging.

(1) Plug on abandonment. A gas storage well shall be plugged upon permanent abandonment in a manner approved by the Commission [ ~~commission~~ ] or its designee. A proposal for plugging shall be submitted to the Commission [ ~~commission~~ ] in Austin for approval or modification prior to plugging. Following approval of a plugging plan, the operator shall file notification of intent to plug at least five days prior to commencement of plugging operations. A plugging report shall be filed with the Commission [ ~~commission~~ ] within 30 days after plugging.

(2) Alternative monitoring. As an alternative to plugging a gas storage well that has been permanently deactivated, an operator may request approval by the Commission [ ~~commission~~ ] or its designee of a plan to convert the well to a monitor well. A pressure monitoring plan must be submitted to the Commission [ ~~commission~~ ] along with the request to convert the well to a monitoring well.

(q) Penalties.

(1) Penalties. Violations of this section may subject the operator to penalties and remedies specified in Texas Natural Resources Code, Title 3; Texas Utilities Code, Chapter 121 [ ~~Texas Civil Statutes, Article 6053-3~~ ]; and other statutes administered by the Commission [ ~~commission~~ ].

(2) (No change.)

(r) Applicability of other Commission [ ~~commission~~ ] rules and orders. The owner or operator of an underground gas storage facility is not relieved by this section of compliance with any other requirement of Chapters 3, 4, 7, or 8 of this title (relating to Oil and Gas Division; Environmental Protection; Gas Services Division; or Pipeline Safety Regulations).

This agency hereby certifies that the 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 July 6, 2006.

TRD-200603627

Mary Ross McDonald

Managing Director

Railroad Commission of Texas

Earliest possible date of adoption: August 20, 2006

For further information, please call: (512) 475-1295