Part 1.
RAILROAD COMMISSION OF TEXAS
Chapter 3.
OIL AND GAS DIVISION
The Railroad Commission of Texas (Commission) adopts amendments to §§3.12,
3.13, and 3.30, relating to Directional Survey Company Report; Casing, Cementing,
Drilling, and Completion Requirements; and Memorandum of Understanding between
the Railroad Commission of Texas (RRC) and the Texas Commission on Environmental
Quality (TCEQ); the repeal of §§3.65, 3.66, 3.67, and 3.69, relating
to Pipeline Permits Required; Pipeline Tariffs; Obtaining Pipeline Connections;
and Definitions; new §§3.70 and 3.71, relating to Pipeline Permits
Required; and Pipeline Tariffs; the repeal of §3.72, relating to Manifest
To Accompany Each Transport of Liquid Hydrocarbons by Vehicle; new §3.72,
relating to Obtaining Pipeline Connections; the repeal of §§3.75,
and 3.77, relating to Discharges to Waters of the State; and Brine Mining
Injection Wells; and new §§3.79, 3.81 and 3.85, relating to Definitions;
Brine Mining Injection Wells; and Manifest to Accompany Each Transport of
Liquid Hydrocarbons by Vehicle; and amendments to §§3.93, 3.99,
and 3.100, relating to Water Quality Certification Definitions; Cathodic Protection
Wells; and Seismic Holes and Core Holes. Sections 3.30, 3.81, and 3.85 are
adopted with minor changes and the remaining sections are adopted without
changes to the versions published in the June 27, 2003, issue of the
The Commission adopts these repeals, new sections, and amendments to update
references to rule numbers or titles; update agencies' names; and repeal and
renumber some rules so that the Texas Administrative Code section number matches
the commonly-used Statewide Rule number. All of the changes are non-substantive
and are made for clarification and accuracy. The amendment to §3.12 adds
overnight mail as a delivery option. The amendments to §3.100 and the
change in wording in new §3.79 (current §3.69) update the citations
to the Commission's coal and uranium mining regulations. Sections 3.99(i)
and 3.100(b) are deleted because they refer to a rule that has been repealed.
The adopted change in §3.30(f)(1)(B) makes the same change as was
proposed in subsection (f)(1)(A) to delete the reference to the OPPR and to
substitute the correct office name, Small Business and Environmental Assistance
Division. The adopted change in §3.81(i)(5)(C) corrects a reference to
the Texas Government Code. The adopted change in §3.85(g) corrects the
title of §3.1.
The Commission also adopts the review of these rules pursuant to Texas
Government Code, §2001.039, in a separate document filed simultaneously
with the
Texas Register
. In addition to the
repeals, new sections, and amendments in this document, the review also includes §§3.6,
3.16, 3.23, 3.27, 3.31, 3.34, 3.41, 3.54, 3.55, 3.62, 3.80, and 3.102, relating
to Application for Multiple Completion; Log and Completion or Plugging Report;
Vacuum Pumps; Gas To Be Measured and Surface Commingling of Gas; Gas Reservoirs
and Gas Well Allowable; Gas To Be Produced and Purchased Ratably; Application
for New Oil or Gas Field Designation and/or Allowable; Gas Reports Required;
Reports on Gas Wells Commingling Liquid Hydrocarbons before Metering; Cycling
Plant Control and Reports; Commission Forms, Applications and Filing Requirements;
and Tax Reduction for Incremental Production.
The Commission received no comments on the proposal.
16 TAC §§3.12, 3.13, 3.30, 3.70 - 3.72, 3.79, 3.81, 3.85, 3.93, 3.99, 3.100
The Commission adopts the new sections and amendments pursuant
to Texas Natural Resources Code, §§81.051 and 81.052, which provide
the Commission with jurisdiction over all persons owning or engaged in drilling
or operating oil or gas wells and persons owning or operating pipelines in
Texas and the authority to adopt all necessary rules for governing and regulating
persons and their operations under Commission jurisdiction and pursuant to
Texas Natural Resources Code §§85.042, 85.202, 86.041 and 86.042
which require the Commission to adopt rules to control waste of oil and gas.
Statutory authority: Texas Natural Resources Code, §§81.051,
81.052, 85.024, 85.202, 86.041, and 86.042.
Cross-reference to statute: Texas Natural Resources Code, §§81.051
and 81.052 and §§85.042, 85.202, 86.041 and 86.042.
Issued in Austin, Texas, on August 5, 2003.
§3.30.Memorandum of Understanding between the Railroad Commission of Texas (RRC) and the Texas Commission on Environmental Quality (TCEQ).
(a)
Need for agreement.
(1)
Section 10 of House Bill 1407, 67th Legislature, 1981,
which appeared as a footnote to the Texas Solid Waste Disposal Act, Texas
Civil Statutes, Article 4477-7, provides as follows: On or before January
1, 1982, the Texas Department of Water Resources, the Texas Department of
Health, and the Railroad Commission of Texas shall execute a memorandum of
understanding that specifies in detail these agencies' interpretation of the
division of jurisdiction among the agencies over waste materials that result
from or are related to activities associated with the exploration for and
the development, production, and refining of oil or gas. The agencies shall
amend the memorandum of understanding at any time that the agencies find it
to be necessary.
(2)
The original Memorandum of Understanding (MOU) between
the agencies became effective January 1, 1982. The MOU was revised effective
December 1, 1987, to reflect legislative clarification of the Railroad Commission's
jurisdiction over oil and gas wastes and the Texas Water Commission's (successor
to the Texas Department of Water Resources) jurisdiction over industrial and
hazardous wastes.
(3)
The agencies have determined that the revised MOU that
became effective on December 1, 1987, should again be revised to further clarify
jurisdictional boundaries and to reflect legislative changes in agency responsibility
and the combination of the Texas Water Commission, the Texas Air Control Board,
and portions of the Texas Department of Health to form the Texas Natural Resource
Conservation Commission.
(b)
General agency jurisdictions.
(1)
Texas Commission on Environmental Quality (TCEQ) (the successor
agency to the Texas Natural Resource Conservation Commission (TNRCC)). References
in this section to TCEQ shall mean TCEQ or any successor agencies.
(A)
The TCEQ has jurisdiction over solid waste under Chapter
361 of the Texas Health and Safety Code, §§361.001-361.754. The
TCEQ's jurisdiction encompasses both hazardous and nonhazardous, industrial
and municipal, solid wastes.
(B)
Under Texas Health and Safety Code, §361.003(34),
solid waste under the jurisdiction of the TCEQ is defined to include "garbage,
rubbish, refuse, sludge from a waste treatment plant, water supply treatment
plant, or air pollution control facility, and other discarded material, including
solid, liquid, semisolid, or contained gaseous material resulting from industrial,
municipal, commercial, mining, and agricultural operations and from community
and institutional activities."
(C)
Solid waste is further defined in Texas Health and Safety
Code, §361.003(34), to exclude "material which results from activities
associated with the exploration, development, or production of oil or gas
or geothermal resources and other substance or material regulated by the Railroad
Commission of Texas pursuant to Section 91.101, Natural Resources Code...."
(D)
In addition, Texas Health and Safety Code, §361.003(34),
defines the term solid waste to include the following until the United States
Environmental Protection Agency (EPA) delegates its authority under the Resource
Conservation and Recovery Act, 42 United States Code (U.S.C.) §6901,
et seq., (RCRA) to the RRC: "waste, substance or material that results from
activities associated with gasoline plants, natural gas or natural gas liquids
processing plants, pressure maintenance plants, or repressurizing plants and
is a hazardous waste as defined by the administrator of the EPA...."
(E)
After delegation of RCRA authority to the Railroad Commission
of Texas (RRC), the definition of solid waste (which defines TCEQ's jurisdiction)
will not include hazardous wastes generated at natural gas or natural gas
liquids processing plants, or reservoir pressure maintenance or repressurizing
plants. The term natural gas or natural gas liquids processing plant refers
to a plant the primary function of which is the extraction of natural gas
liquids from field gas or fractionation of natural gas liquids. The term does
not include a separately located natural gas treating plant for which the
primary function is the removal of carbon dioxide, hydrogen sulfide, or other
impurities from the natural gas stream. A separator, dehydration unit, heater
treater, sweetening unit, compressor, or similar equipment is considered a
part of a natural gas or natural gas liquids processing plant only if it is
located at a plant the primary function of which is the extraction of natural
gas liquids from field gas or fractionation of natural gas liquids. Further,
a pressure maintenance or repressurizing plant is a plant for processing natural
gas for reinjection (for reservoir pressure maintenance or repressurization)
in a natural gas recycling project. A compressor station along a natural gas
pipeline system or a pump station along a crude oil pipeline system is not
a pressure maintenance or repressurizing plant.
(2)
Railroad Commission of Texas (RRC).
(A)
Generally, under Texas Natural Resources Code, Title 3,
and Texas Water Code, Chapter 26, wastes (both hazardous and nonhazardous)
resulting from activities associated with the exploration, development, or
production of oil or gas or geothermal resources, including transportation
of crude oil or natural gas by pipeline, and other activities regulated by
the RRC are under the jurisdiction of the RRC. These wastes are termed "oil
and gas wastes." In compliance with Texas Health and Safety Code, §361.025
(concerning exempt activities), a list of activities that generate wastes
that are subject to the jurisdiction of the RRC is found at §3.8(a)(30)
of this title (relating to Water Protection) and at 30 Texas Administrative
Code §335.1 (concerning definitions), which contains a definition of
"activities associated with the exploration, development, and production of
oil or gas or geothermal resources." This MOU provides further guidance regarding
the agencies' interpretation of these rules and statutes.
(B)
Notwithstanding subparagraph (A) of this paragraph, hazardous
wastes generated at natural gas or natural gas liquids processing plants or
reservoir pressure maintenance or repressurizing plants are subject to the
jurisdiction of the TCEQ until the RRC is authorized by EPA to administer
RCRA. When the RRC is authorized by EPA to administer RCRA, jurisdiction over
such hazardous wastes will transfer from the TCEQ to the RRC.
(c)
Definition of hazardous waste.
(1)
Under the Texas Health and Safety Code, §361.003(12),
a "hazardous waste" subject to the jurisdiction of the TCEQ is defined as
"solid waste identified or listed as a hazardous waste by the administrator
of the United States Environmental Protection Agency under the federal Solid
Waste Disposal Act, as amended by the Resource Conservation and Recovery Act
of 1976, as amended (42 U.S.C. §6901, et seq.)." Similarly, under Texas
Natural Resources Code, §91.601(1), "oil and gas hazardous waste" subject
to the jurisdiction of the RRC is defined as an "oil and gas waste that is
a hazardous waste as defined by the administrator of the United States Environmental
Protection Agency under the federal Solid Waste Disposal Act, as amended by
the Resource Conservation and Recovery Act of 1976 (42 U.S.C. §6901,
et seq.)."
(2)
Federal regulations adopted under authority of the federal
Solid Waste Disposal Act, as amended by RCRA, exempt from regulation as hazardous
waste certain oil and gas wastes. Under 40 Code of Federal Regulations (CFR) §261.4(b)(5),
"drilling fluids, produced waters, and other wastes associated with the exploration,
development, or production of crude oil, natural gas or geothermal energy"
are described as wastes that are exempt from federal hazardous waste regulations.
(3)
A partial list of wastes associated with oil, gas, and
geothermal exploration, development, and production that are considered exempt
from hazardous waste regulation under RCRA can be found in EPA's "Regulatory
Determination for Oil and Gas and Geothermal Exploration, Development and
Production Wastes," 53 FedReg 25,446 (July 6, 1988). A further explanation
of the exemption can be found in the "Clarification of the Regulatory Determination
for Wastes from the Exploration, Development and Production of Crude Oil,
Natural Gas and Geothermal Energy, " 58 FedReg 15,284 (March 22, 1993). The
exemption codified at 40 CFR §261.4(b)(5) and discussed in the Regulatory
Determination has been, and may continue to be, clarified in subsequent guidance
issued by the EPA.
(d)
Jurisdiction over specific disposal activities.
(1)
Discharges under Texas Water Code, Chapter 26. Under the
Texas Water Code, Chapter 26, the TCEQ has jurisdiction over discharges of
waste into or adjacent to water in the state, other than discharges regulated
by the RRC. The RRC regulates discharges of waste from activities associated
with the exploration, development, or production of oil, gas, or geothermal
resources, including transportation of crude oil and natural gas by pipeline,
and from solution brine mining activities (except solution mining activities
conducted for the purpose of creating caverns in naturally-occurring salt
formations for the storage of wastes regulated by the TCEQ) under Texas Natural
Resources Code, Title 3, and Texas Water Code, Chapter 26. Discharges of waste
regulated by the RRC into water in the state shall not cause a violation of
the water quality standards. While water quality standards are established
by the TCEQ, the RRC has the responsibility for enforcing any violations of
such standards. Texas Water Code, Chapter 26, does not require that discharges
regulated by the RRC comply with regulations of the TCEQ that are not water
quality standards. Because of the complexity of 30 Texas Administrative Code §307.6
(concerning toxic materials), the staffs of the TCEQ and the RRC will consult
from time to time regarding application and interpretation of the Texas Surface
Water Quality Standards.
(2)
Disposal wells under Texas Water Code, Chapter 27. Jurisdiction
over wastes disposed by injection is divided between the RRC and the TCEQ
as set forth in Texas Water Code, Chapter 27 (the Injection Well Act). The
RRC has jurisdiction under Texas Water Code, Chapter 27, over injection wells
used to dispose of oil and gas waste. Texas Water Code, Chapter 27, defines
"oil and gas waste" to mean "waste arising out of or incidental to drilling
for or producing of oil, gas, or geothermal resources, waste arising out of
or incidental to the underground storage of hydrocarbons other than storage
in artificial tanks or containers, or waste arising out of or incidental to
the operation of gasoline plants, natural gas processing plants, or pressure
maintenance or repressurizing plants. The term includes but is not limited
to salt water, brine, sludge, drilling mud, and other liquid or semi-liquid
waste material." The term "waste arising out of or incidental to drilling
for or producing of oil, gas, or geothermal resources" includes waste associated
with transportation of crude oil or natural gas by pipeline pursuant to Texas
Natural Resources Code, §91.101. The TCEQ has jurisdiction over injection
wells used to dispose of other types of waste.
(3)
Disposal of naturally occurring radioactive material (NORM).
(The term "disposal" does not include receipt, possession, use, processing,
transfer, transport, storage, or commercial distribution of radioactive materials,
including NORM. These activities are under the jurisdiction of the Texas Department
of Health per Texas Health and Safety Code, §401.011(a).)
(A)
Under Texas Health and Safety Code, §401.415, the
RRC has jurisdiction over the disposal of NORM that constitutes, is contained
in, or has contaminated oil and gas waste. This waste material is called "oil
and gas NORM waste." Oil and gas NORM waste may be generated in connection
with the exploration, development, or production of oil or gas. Oil and gas
NORM waste may also be generated in connection with geothermal resource exploration,
development, or production activities or solution brine mining activities.
(B)
Under Texas Health and Safety Code, §401.412, the
TCEQ has jurisdiction over the disposal of NORM which is not oil and gas NORM
waste.
(e)
Jurisdiction over waste from specific oil and gas activities.
(1)
Drilling, operation, and plugging of wells associated with
the exploration, development, or production of oil, gas, or geothermal resources.
Wells associated with the exploration, development, or production of oil,
gas, or geothermal resources include exploratory wells, cathodic protection
holes, core holes, oil wells, gas wells, geothermal resource wells, fluid
injection wells used for secondary or enhanced recovery of oil or gas, oil
and gas waste disposal wells, and injection water source wells. Several types
of waste materials can be generated during the drilling, operation, and plugging
of these wells. These waste materials include drilling fluids (including water-based
and oil-based fluids), cuttings, produced water, produced sand, waste hydrocarbons
(including used oil), fracturing fluids, spent acid, workover fluids, treating
chemicals (including scale inhibitors, emulsion breakers, paraffin inhibitors,
and surfactants), waste cement, filters (including used oil filters), domestic
sewage (including waterborne human waste and waste from activities such as
bathing and food preparation), and trash (including inert waste, barrels,
dope cans, oily rags, mud sacks, and garbage). Generally, these wastes, whether
disposed of by discharge, landfill, land farm, evaporation, or injection,
are subject to the jurisdiction of the RRC.
(2)
Field treatment of produced fluids. Oil, gas, and water
produced from oil, gas, or geothermal resource wells may be treated in the
field in facilities such as separators, skimmers, heater treaters, dehydrators,
and sweetening units. Waste materials that result from the field treatment
of oil and gas include waste hydrocarbons (including used oil), produced water,
hydrogen sulfide scavengers, dehydration wastes, treating and cleaning chemicals,
filters (including used oil filters), asbestos insulation, domestic sewage,
and trash are subject to the jurisdiction of the RRC.
(3)
Storage of oil.
(A)
Tank bottoms, stormwater runoff, and other wastes from
the storage of crude oil (whether foreign or domestic) before it enters the
refinery are under the jurisdiction of the RRC. In addition, waste resulting
from storage of crude oil at refineries is subject to the jurisdiction of
the TCEQ. Further, stormwater runoff from terminal facilities where both refined
products intended for use offsite and crude oil are stored in aboveground
tanks is under the jurisdiction of the TCEQ. Stormwater runoff from a terminal
facility where crude oil is stored prior to refining and at which refined
products are stored solely for use at the facility is under the jurisdiction
of the RRC.
(B)
Wastes generated from storage tanks which are part of the
refinery and wastes resulting from the wholesale and retail marketing of refined
products are subject to the jurisdiction of the TCEQ.
(4)
Underground hydrocarbon storage. The disposal of wastes,
including saltwater, resulting from the construction, creation, operation,
maintenance, closure, or abandonment of an "underground hydrocarbon storage
facility" is subject to the jurisdiction of the RRC, provided the terms "hydrocarbons"
and "underground hydrocarbon storage facility" have the meanings set out in
Texas Natural Resources Code, §91.201.
(5)
Underground natural gas storage. The disposal of wastes
resulting from the construction, operation, or abandonment of an "underground
natural gas storage facility" is subject to the jurisdiction of the RRC, provided
that the terms "natural gas" and "storage facility" have the meanings set
out in Texas Natural Resources Code, §91.173.
(6)
Transportation of crude oil or natural gas.
(A)
Crude oil and natural gas are transported by railcars,
tank trucks, barges, tankers, and pipelines. The RRC has jurisdiction over
waste from the transportation of crude oil by pipeline, regardless of the
crude oil source (foreign or domestic) prior to arrival at a refinery. The
RRC also has jurisdiction over waste from the transportation by pipeline of
natural gas, including natural gas liquids, prior to the use of the natural
gas in any manufacturing process or as a residential or industrial fuel. The
transportation wastes subject to the jurisdiction of the RRC include wastes
from pipeline compressor or pressure stations and wastes from pipeline hydrostatic
pressure tests and other pipeline operations. These wastes include waste hydrocarbons
(including used oil), treating and cleaning chemicals, filters (including
used oil filters), scraper trap sludge, trash, domestic sewage, wastes contaminated
with polychlorinated biphenyls (PCBs) (including transformers, capacitors,
ballasts, and soils), soils contaminated with mercury from leaking mercury
meters, asbestos insulation, transite pipe, and hydrostatic test waters.
(B)
The TCEQ has jurisdiction over waste from transportation
of refined products by pipeline.
(C)
The TCEQ also has jurisdiction over wastes associated with
transportation of crude oil and natural gas, including natural gas liquids,
by railcar, tank truck, barge, or tanker.
(7)
Reclamation plants.
(A)
The RRC has jurisdiction over wastes from reclamation plants
that process wastes from activities associated with the exploration, development,
or production of oil, gas, or geothermal resources, such as lease tank bottoms.
Waste management activities of reclamation plants for other wastes are subject
to the jurisdiction of the TCEQ.
(B)
In addition to waste management jurisdiction, the RRC has
jurisdiction over the conservation and prevention of waste of crude oil and
therefore must approve all movements of crude oil-containing materials to
reclamation plants. The applicable statute and regulations consist primarily
of reporting requirements for accounting purposes.
(8)
Refining of oil.
(A)
The management of wastes resulting from oil refining operations,
including spent caustics, spent catalysts, still bottoms or tars, and API
separator sludges, is subject to the jurisdiction of the TCEQ. The processing
of light ends from the distillation and cracking of crude oil or crude oil
products is considered to be a refining operation. The term "refining" does
not include the processing of natural gas or natural gas liquids.
(B)
The RRC has jurisdiction over refining activities for the
conservation and the prevention of waste of crude oil. The RRC requires that
all crude oil streams into or out of a refinery be reported for accounting
purposes. In addition, the RRC requires that materials recycled and used as
a fuel, such as still bottoms or waste crude oil, be reported.
(9)
Natural gas or natural gas liquids processing plants (including
gas fractionation facilities) and pressure maintenance or repressurizing plants.
Wastes resulting from activities associated with these facilities include
produced water, cooling tower water, sulfur bead, sulfides, spent caustics,
sweetening agents, spent catalyst, waste hydrocarbons (including used oil),
asbestos insulation, wastes contaminated with PCBs (including transformers,
capacitors, ballasts, and soils), treating and cleaning chemicals, filters,
trash, domestic sewage, and dehydration materials. These wastes are subject
to the jurisdiction of the RRC under Texas Natural Resources Code, §91.101.Disposal
of waste from activities associated with natural gas or natural gas liquids
processing plants (including gas fractionation facilities), and pressure maintenance
or repressurizing plants by injection is subject to the jurisdiction of the
RRC under Texas Water Code, Chapter 27. Notwithstanding any contrary provision
of this paragraph, until delegation of authority under RCRA to the RRC, the
TCEQ shall have jurisdiction over wastes resulting from these activities that
are not exempt from federal hazardous waste regulation under RCRA and that
are considered hazardous under applicable federal rules.
(10)
Manufacturing processes.
(A)
Wastes that result from the use of natural gas, natural
gas liquids, or products refined from crude oil in any manufacturing process,
such as the production of petrochemicals or plastics, or from the manufacture
of carbon black, are industrial wastes subject to the jurisdiction of the
TCEQ. The term "manufacturing process" does not include the processing (including
fractionation) of natural gas or natural gas liquids at natural gas or natural
gas liquids processing plants.
(B)
The RRC has jurisdiction under Texas Natural Resources
Code, Chapter 87, to regulate the use of natural gas in the production of
carbon black.
(11)
Commercial service company facilities and training facilities.
(A)
The TCEQ has jurisdiction over wastes generated at facilities,
other than actual exploration, development, or production sites (field sites),
where oil and gas industry workers are trained. In addition, the TCEQ has
jurisdiction over wastes generated at facilities where materials, processes,
and equipment associated with oil and gas industry operations are researched,
developed, designed, and manufactured. However, wastes generated from tests
of materials, processes, and equipment at field sites are under the jurisdiction
of the RRC.
(B)
The TCEQ also has jurisdiction over waste generated at
commercial service company facilities operated by persons providing equipment,
materials, or services (such as drilling and work over rig rental and tank
rental; equipment repair; drilling fluid supply; and acidizing, fracturing,
and cementing services) to the oil and gas industry. These wastes include
the following wastes when they are generated at commercial service company
facilities: empty sacks, containers, and drums; drum, tank, and truck rinsate;
sandblast media; painting wastes; spent solvents; spilled chemicals; waste
motor oil; and unused fracturing and acidizing fluids.
(C)
The term "commercial service company facility" does not
include a station facility such as a warehouse, pipeyard, or equipment storage
facility belonging to an oil and gas operator and used solely for the support
of that operator's own activities associated with the exploration, development,
or production or oil or gas or geothermal resources, including the transportation
of crude oil or natural gas by pipeline.
(D)
Notwithstanding subparagraphs (A)-(C) of this paragraph,
the RRC has jurisdiction over disposal of oil and gas wastes, such as waste
drilling fluids and NORM-contaminated pipe scale, that are managed at commercial
service company facilities.
(E)
The RRC also has jurisdiction over wastes such as vacuum
truck rinsate and tank rinsate generated at facilities operated by oil and
gas waste haulers permitted by the RRC pursuant to §3.8(f) of this title
(relating to water protection).
(12)
Spill response. Contaminated soil and other wastes that
result from a spill must be managed in accordance with the governing statutes
and regulations adopted by the agency responsible for the activity that resulted
in the spill. Coordination of issues of spill notification, prevention, and
response shall be addressed in the State of Texas Oil and Hazardous Substance
Spill Contingency Plan and may be addressed further in a separate Memorandum
of Understanding among these agencies and other appropriate state agencies.
(f)
Interagency activities.
(1)
Recycling and pollution prevention.
(A)
The TCEQ and the RRC encourage generators to eliminate
pollution at the source and recycle whenever possible to avoid disposal of
solid wastes. Questions regarding source reduction and recycling may be directed
to the TCEQ Small Business and Environmental Assistance Division, telephone
number (800) 447-2827, or to the Waste Minimization Program at the RRC. The
TCEQ reserves the right to require generators to explore source reduction
and recycling alternatives prior to authorizing disposal of any waste under
the jurisdiction of the RRC at a facility regulated by the TCEQ; similarly,
the RRC reserves the right to require generators to explore source reduction
and recycling alternatives prior to authorizing disposal of any waste under
the jurisdiction of the TCEQ at a facility regulated by the RRC.
(B)
The TCEQ Small Business and Environmental Assistance Division
and the RRC Waste Minimization Program will meet at least two times each year
to maintain a working relationship to enhance the efforts to share information
and use resources more efficiently. The TCEQ Small Business and Environmental
Assistance Division will make the proper TCEQ personnel aware of the services
offered by the RRC Waste Minimization Program, share information with the
RRC Waste Minimization Program to maximize services to oil and gas operators,
and advise oil and gas operators of RRC Waste Minimization Program services.
The RRC Waste Minimization Program will make the proper RRC personnel aware
of the services offered by the TCEQ Small Business and Environmental Assistance
Division, share information with the TCEQ Small Business and Environmental
Assistance Division to maximize services to industrial operators, and advise
industrial operators of the TCEQ Small Business and Environmental Assistance
Division services.
(2)
Treatment of wastes under RRC jurisdiction at facilities
registered by TCEQ's Petroleum Storage Tank Division.
(A)
Soils contaminated with constituents that are physically
and chemically similar to those normally found in soils at leaking underground
petroleum storage tanks from generators under the jurisdiction of the RRC
are eligible for treatment at TCEQ regulated soil treatment facilities once
alternatives for recycling and source reduction have been explored. For the
purpose of this provision, soils containing petroleum substance(s) as defined
in 30 Texas Administrative Code §334.481 (concerning definitions) are
considered to be similar, but drilling muds, acids, or other chemicals used
in oil and gas activities are not considered similar. Generators under the
jurisdiction of the RRC must meet the same requirements as generators under
the jurisdiction of the TCEQ when sending their petroleum contaminated soils
to soil treatment facilities under TCEQ jurisdiction. Those requirements are
in 30 Texas Administrative Code §334.496 (concerning shipping procedures
applicable to generators of petroleum-substance waste), except subsection
(c) which is not applicable, and 30 Texas Administrative Code §334.497
(concerning recordkeeping and reporting procedures applicable to generators).
RRC generators with questions on these requirements should call the TCEQ Petroleum
Storage Tank (PST) Division, Responsible Party Investigations Section, telephone
number (512) 239-2200.
(B)
Generators under RRC jurisdiction should also be aware
that TCEQ regulated soil treatment facilities are required by 30 Texas Administrative
Code §334.499 (concerning shipping requirements applicable to owners
or operators of storage, treatment, or disposal facilities) to maintain documentation
on the soil sampling and analytical methods, chain-of-custody, and all analytical
results for the soil received at the facility and transported off-site or
reused on-site.
(C)
The RRC must specifically authorize management of contaminated
soils under its jurisdiction at facilities registered by the PST Division
of the TCEQ. The RRC may grant such authorizations by rule, or on an individual
basis through permits or other written authorizations.
(D)
All waste materials, including those that have been treated,
that are subject to the jurisdiction of the RRC and are managed at facilities
registered by the PST Division of the TCEQ will remain subject to the jurisdiction
of the RRC. Such materials will be subject to RRC regulations regarding final
reuse, recycling, or disposal.
(E)
TCEQ waste codes and registration numbers are not required
for management of wastes under the jurisdiction of the RRC at facilities registered
by the PST Division of the TCEQ.
(3)
Disposal of wastes under RRC jurisdiction at facilities
permitted by the TCEQ.
(A)
As provided in this paragraph, waste materials subject
to the jurisdiction of the RRC may be managed at solid waste facilities under
the jurisdiction of the TCEQ once alternatives for recycling and source reduction
have been explored. The RRC must specifically authorize management of wastes
under its jurisdiction at facilities regulated by the TCEQ. The RRC may grant
such authorizations by rule, or on an individual basis through permits or
other written authorizations. In addition, except as provided in subparagraph
(B) of this paragraph, the concurrence of the TCEQ is required to manage waste
under the jurisdiction of the RRC at a facility regulated by the TCEQ. The
TCEQ's concurrence may be subject to specified conditions.
(B)
A facility under the jurisdiction of the TCEQ may accept,
without further individual concurrence, waste under the jurisdiction of the
RRC if that facility is permitted or otherwise authorized to accept that particular
type of waste. The phrase "that type of waste" does not specifically refer
to waste under the jurisdiction of the RRC, but rather to the waste's physical
and chemical characteristics.
(C)
In all other instances, individual written concurrences
from the TCEQ shall be required to manage wastes under the jurisdiction of
the RRC at TCEQ regulated facilities. (This is required only if the TCEQ regulated
facility receiving the waste does not have approval to accept the waste included
in its permit or other authorization provided by the TCEQ.) To obtain an individual
concurrence, the waste generator must provide to the TCEQ sufficient information
to allow the concurrence determination to be made, including the identity
of the proposed waste management facility, the process generating the waste,
the quantity of waste, and the physical and chemical nature of the waste involved
(using process knowledge and/or laboratory analysis as defined in 30 Texas
Administrative Code, Chapter 335, Subchapter R (concerning waste classification)).
In obtaining TCEQ approval, generators may use their existing knowledge about
the process or materials entering it to characterize their wastes. Material
Safety Data Sheets, manufacturer's literature, and other documentation generated
in conjunction with a particular process may be used. Process knowledge must
be documented and submitted with the request for approval.
(D)
Notwithstanding subparagraphs (A)-(C) of this paragraph,
waste sludge subject to the jurisdiction of the RRC, other than domestic septage
that is not mixed with other waste materials, may not be applied to the land
at a facility permitted by the TCEQ for the beneficial use of sewage sludge
or water treatment sludge. Domestic septage collected from portable toilets
at facilities subject to RRC jurisdiction that is not mixed with other waste
materials may be managed at a facility permitted by the TCEQ for disposal,
incineration, or land application for beneficial use of such domestic septage
waste without specific authorization from the TCEQ.
(E)
Additional guidance regarding requirements for, and restrictions
on, management of particular types of wastes regulated by the RRC at facilities
registered or permitted by the TCEQ may be issued in the future.
(F)
TCEQ waste codes and registration numbers are not required
for management of wastes under the jurisdiction of the RRC at facilities under
the jurisdiction of the TCEQ. If a receiving facility nevertheless requests
or requires a TCEQ waste code for waste under the jurisdiction of the RRC,
a code consisting of the following may be provided:
(i)
the sequence number "RRCT";
(ii)
the appropriate form code, as specified in 30 Texas Administrative
Code Chapter 335, Subchapter R, Appendix 3 (concerning form codes); and
(iii)
the waste classification code "H" if the waste is a hazardous
oil and gas waste, or "R" if the waste is a nonhazardous oil and gas waste.
(G)
If a facility requests or requires a TCEQ waste generator
registration number for wastes under the jurisdiction of the RRC, the registration
number "XXXRC" may be provided.
(H)
Wastes that are under the jurisdiction of the RRC need
not be reported to the TCEQ's Industrial and Hazardous Waste Division.
(4)
Management of nonhazardous wastes under TCEQ jurisdiction
at facilities regulated by the RRC.
(A)
Once alternatives for recycling and source reduction have
been explored, and with prior authorization from the RRC, the following nonhazardous
wastes subject to the jurisdiction of the TCEQ may be disposed of, other than
by injection into a Class II well, at a facility regulated by the RRC; bioremediated
at a facility regulated by the RRC (prior to reuse, recycling, or disposal);
or reclaimed at a crude oil reclamation facility regulated by the RRC: nonhazardous
wastes that are chemically and physically similar to oil and gas wastes, but
excluding soils, media, debris, sorbent pads, and other clean-up materials
that are contaminated with refined petroleum products.
(B)
To obtain an individual authorization from the RRC, the
waste generator must provide the following information, in writing, to the
RRC: the identity of the proposed waste management facility, the quantity
of waste involved, a hazardous waste determination that addresses the process
generating the waste and the physical and chemical nature of the waste, and
any other information that the RRC may require. As appropriate, the RRC shall
reevaluate any authorization issued pursuant to this paragraph.
(C)
Once alternatives for recycling and source reduction have
been explored, and subject to the RRC's individual authorization, the following
wastes under the jurisdiction of the TCEQ are authorized without further TCEQ
approval to be disposed of at a facility regulated by the RRC, bioremediated
at a facility regulated by the RRC, or reclaimed at a crude oil reclamation
facility regulated by the RRC: nonhazardous bottoms from tanks used only for
crude oil storage; unused and/or reconditioned drilling and completion/workover
wastes from commercial service company facilities; used and/or unused drilling
and completion/workover wastes generated at facilities where workers in the
oil and gas exploration, development, and production industry are trained;
used and/or unused drilling and completion/workover wastes generated at facilities
where materials, processes, and equipment associated with oil and gas exploration,
development, and production operations are researched, developed, designed,
and manufactured; unless other provisions are made in the underground injection
well permit used and/or unused drilling and completion wastes (but not workover
wastes) generated in connection with the drilling and completion of Class
I, III, and V injection wells; wastes (such as contaminated soils, media,
debris, sorbent pads, and other cleanup materials) associated with spills
of crude oil and natural gas liquids if such wastes are under the jurisdiction
of the TCEQ; and sludges from washout pits at commercial service company facilities.
(D)
In a public health, public safety, or environmental emergency,
the RRC and the TCEQ may consider allowing injection of wastes under the jurisdiction
of the TCEQ into Class II injection wells permitted by the RRC.
(E)
Pursuant to Texas Water Code, §27.0511(g), TCEQ concurrence
is required for injection of TCEQ-regulated waste in connection with a secondary
or tertiary recovery project.
(F)
Additional guidance regarding requirements for, and restrictions
on, management of particular types of wastes covered under this MOU may be
issued in the future.
(5)
Drilling in landfills. The TCEQ will notify the Environmental
Services Section of the Oil and Gas Division of the RRC and the landfill owner
at the time a drilling application is submitted if an operator proposes to
drill a well through a landfill regulated by the TCEQ. The RRC and the TCEQ
will cooperate and coordinate with one another in advising the appropriate
parties of measures necessary to reduce the potential for the landfill contents
to cause groundwater contamination as a result of landfill disturbance associated
with drilling operations.
(6)
Coordination of enforcement actions and cooperative sharing
of enforcement information.
(A)
In the event that a generator or transporter disposes,
without proper authorization, of wastes regulated by the TCEQ at a facility
permitted by the RRC, the TCEQ is responsible for enforcement actions against
the generator or transporter, and the RRC is responsible for enforcement actions
against the disposal facility. In the event that a generator or transporter
disposes, without proper authorization, of wastes regulated by the RRC at
a facility permitted by the TCEQ, the RRC is responsible for enforcement actions
against the generator or transporter, and the TCEQ is responsible for enforcement
actions against the disposal facility.
(B)
The TCEQ and the RRC agree to cooperate with one another
by sharing enforcement information. Employees of either agency who discover,
in the course of their official duties, information that indicates a violation
of a statute, regulation, order, or permit pertaining to wastes under the
jurisdiction of the other agency, are encouraged to notify the other agency.
In addition, to facilitate enforcement actions, each agency is encouraged
to share information in its possession with the other agency if requested
by the other agency to do so.
(g)
Definitions. Words shall have meaning as defined in the
rules of each agency. Words not so defined shall have their regular meaning
as used as a term of art in industry practice.
(h)
Disputes. The staff of the RRC and the TCEQ shall meet
as necessary to attempt to resolve any disputes regarding interpretation of
this MOU and disputes regarding definitions and terms of art. If a staff-level
meeting fails to resolve the dispute, the dispute will be elevated to the
senior management of both agencies for resolution.
(i)
Effective date. This Memorandum of Understanding, as of
its effective date, shall supersede the prior Memorandum of Understanding
among the agencies, dated December 1, 1987.
§3.81.Brine Mining Injection Wells.
(a)
Definitions. The following words and terms, when used in
this section, shall have the following meanings, unless the context clearly
indicates otherwise.
(1)
Affected person--A person who, as a result of the activity
sought to be permitted, has suffered or may suffer actual injury or economic
damage other than as a member of the general public.
(2)
Brine mining facility or facility--The brine mining injection
well, and the pits, tanks, fresh water wells, pumps, and other structures
and equipment that are or will be used in conjunction with the brine mining
injection well.
(3)
Brine mining injection well--A well used to inject fluid
for the purpose of extracting brine by the solution of a subsurface salt formation.
The term "brine mining injection well" does not include a well used to inject
fluid for the purpose of leaching a cavern for the underground storage of
hydrocarbons or the disposal of waste, or a well used to inject fluid for
the purpose of extracting sulphur by the thermofluid mining process.
(4)
Commission--The Railroad Commission of Texas.
(5)
Director--The director of the Oil and Gas Division or a
staff delegate designated in writing by the director of the Oil and Gas Division
or the commission.
(6)
Existing brine mining injection well--A brine mining injection
well in which injection operations began prior to the effective date of this
section.
(7)
Fresh water--Water having bacteriological, physical, and
chemical properties that make it suitable and feasible for beneficial use
for any lawful purpose.
(8)
New brine mining injection well--A brine mining injection
well in which injection operations begin on or after the effective date of
this section.
(9)
Permit--A written authorization issued by the commission
under this section for the operation of a brine mining injection well.
(10)
Person--A natural person, corporation, organization, government
or governmental subdivision or agency, business trust, estate, trust partnership,
association, or any other legal entity.
(11)
Pollution--The alteration of the physical, chemical, or
biological quality of, or the contamination of, water that makes it harmful,
detrimental, or injurious to humans, animal life, vegetation or property or
to public health, safety, or welfare, or impairs the usefulness or the public
enjoyment of the water for any lawful or reasonable purpose.
(b)
Prohibitions.
(1)
Unauthorized injection. No person may operate a brine mining
injection well without obtaining a permit from the commission under this section.
No person may begin constructing a new brine mining injection well until the
commission has issued a permit to operate the well under this section and
a permit to drill, deepen, plug back, or reenter the well under §3.5
of this title (relating to Application to Drill, Deepen, or Plug Back) (Rule
5).
(2)
Fluid migration. No person may operate a brine mining injection
well in a manner that allow fluids to escape from the permitted injection
zone. If fluids are migrating from the permitted injection zone, the operator
shall immediately cease injection operations.
(3)
Falsifying documents and tampering with gauges. No person
may knowingly make any false statement, representation, or certification in
any application, report, record, or other document submitted or required to
be maintained under this section or under any permit issued pursuant to this
section, or falsify, tamper with, or knowingly render inaccurate any monitoring
device or method required to be maintained under this section or under any
permit issued pursuant to this section.
(c)
Standards for permit issuance. A permit may be issued only
if the commission determines that the operation of the brine mining injection
well will not result in the pollution of fresh water. All permits issued under
this section will contain the conditions required by subsections (f) and (g)
of this section, and all other conditions reasonably necessary to prevent
the pollution of fresh water.
(d)
Permit application.
(1)
Duty to apply. Any person who operates or proposes to operate
a brine mining injection well shall file a permit application with the commission
in Austin within the time provided in paragraph (2) of this subsection. The
applicant shall mail or deliver a copy of the application to the appropriate
district office on the same day the application is mailed or delivered to
the commission in Austin. A permit application will be considered filed with
the commission on the date it is received by the commission in Austin.
(2)
Time to apply.
(A)
Any person who proposes to operate a new brine mining injection
well shall file a permit application at least 180 days before the date on
which injection is to begin, unless a later date has been authorized by the
director.
(B)
Any person who is operating an existing brine injection
well shall file a permit application within 90 days of the effective date
of this section.
(C)
Any person who has obtained a permit under this section
and who wishes to continue to operate the brine mining injection well after
the permit expires shall file an application for new permit at least 180 days
before the existing permit expires, unless a later date has been authorized
by the director.
(3)
Who applies. When a brine mining facility is owned by one
person but is operated by another person, it is the operator's duty to file
an application for a permit.
(4)
Application requirements for all applicants. All applicants
shall submit the following information, using application forms supplied by
the commission:
(A)
name, mailing address, and location of the brine mining
facility for which the application is submitted;
(B)
the operator's name, mailing address, telephone number,
and status as federal, state, private, public, or other entity, and a statement
indicating whether the operator is the owner of the facility;
(C)
the proposed uses for the brine mined at the facility;
(D)
a listing of all permits or construction approvals for
the facility received or applied for under federal or state environmental
programs;
(E)
a topographic map, or other map if the topographic map
is unavailable, extending one mile beyond the property boundaries of the facility,
depicting the facility and those springs, other surface water bodies, drinking
water wells, and other wells listed in public records or otherwise known to
the applicant within 1/4 mile of the facility property boundary;
(F)
a plat showing the oil and gas operators of the tract on
which the facility is located and the tracts adjacent to the tract on which
the facility is located. On the plat or on a separate sheet attached to the
plat, the applicant shall list the names and addresses of the oil and gas
operators;
(G)
a plat showing the surface ownership of the tract on which
the facility is located and the tracts adjacent to the tract on which the
facility is located. On the plat or on a separate sheet attached to the plat,
the applicant shall list the names and addresses of the surface owners, as
determined from the current county tax rolls or other reliable sources, and
shall identify the source of the list. If the director determines that, after
diligent efforts, the applicant has been unable to ascertain the name and
address of one or more surface owners, the director may waive the requirements
of this subparagraph with respect to those surface owners;
(H)
a map with surveys marked showing the type, location, and
depth of all wells of public record within a 1/4 mile radius of the brine
mining injection well that penetrate the salt formation. The applicant shall
attach the following information to the map:
(i)
a tabulation of the wells showing the dates the wells were
drilled and the present status of the wells; and
(ii)
plugging records for plugged and abandoned wells and completion
records for other wells;
(I)
a letter from the Texas Commission on Environmental Quality
stating the depth to which fresh water strata should be protected;
(J)
a complete electric log of the brine mining injection well
or a nearby well. On the log, the applicant shall identify the geologic formations
between the land surface and the top of the salt formation and the depths
at which they occur;
(K)
a drawing of the surface and subsurface construction details
of the brine mining injection well;
(L)
the proposed maximum daily injection rate and maximum injection
pressure;
(M)
the proposed injection procedure;
(N)
the proposed mechanical integrity testing procedure;
(O)
the source of mining water to be used at the facility.
If the source is groundwater, the following information must be included:
(i)
the groundwater formation name;
(ii)
an depth of the groundwater formation; and
(iii)
an analysis of the groundwater;
(P)
the direction of the hydraulic gradient in the area; and
(Q)
the proposed groundwater monitoring plan, or an alternate
plan for assuring that fluids are not escaping from the permitted injection
zone.
(5)
Additional information. The applicant shall submit any
other information required on the application form supplied by the commission.
In addition to the information reported on the application form, the applicant
shall submit, at the director's request, any other information the commission
may reasonably require to assess the brine mining injection well and to determine
whether to issue a permit.
(e)
Signatories to applications and reports.
(1)
Applications. All applications shall be signed as follows:
(A)
for a corporation, by a responsible corporate officer.
A responsible corporate officer means a president, secretary, treasurer, or
vice-president of the corporation in charge of a principal business function,
or any other person who performs similar policy-making or decision-making
functions for the corporation; or
(B)
for a partnership or sole proprietorship, by a general
partner or the proprietor, respectively.
(2)
Reports. All reports required by permits and other information
requested by the commission shall be signed by a person described in paragraph
(1) of this subsection or by a duly authorized representative of that person.
A person is a duly authorized representative only if:
(A)
the authorization is made in writing by a person described
in paragraph (1) of this subsection;
(B)
the authorization specifies an individual or position having
responsibility for the overall operation of the regulated facility; and
(C)
the authorization is submitted to the commission before
or together with any report of information signed by the authorized representative.
(3)
Certification. Any person signing a document under paragraph
(1) or (2) of this subsection shall make the following certification: "I certify
under penalty of law that this document and all attachments were prepared
under my direction or supervision in accordance with a system designed to
assure that qualified personnel properly gathered and evaluated the information
submitted. Based on my inquiry of the person or persons who manage the system,
or who are directly responsible for gathering the information, the information
submitted is, to the best of my knowledge and belief, true, accurate, and
complete. I am aware that there are significant penalties for submitting false
information."
(f)
Conditions applicable to all permits. The conditions specified
in this subsection apply to all permits.
(1)
Duty to comply. The operator shall comply with all conditions
of the permit. Any permit noncompliance is grounds for enforcement action,
for permit termination, revocation and reissuance, or modification, or for
denial of a permit renewal application.
(2)
Duty to reapply. If the operator wishes to continue a permitted
activity after the expiration date of the permit, the operator shall apply
for and obtain a new permit.
(3)
Need to halt or reduce activity not a defense. It is not
a defense for an operator in an enforcement action that it would have been
necessary to halt or reduce the permitted activity in order to maintain compliance
with the conditions of the permit.
(4)
Duty to mitigate. The operator shall take all reasonable
steps to minimize and correct any adverse effect on the environment resulting
from noncompliance with the permit.
(5)
Proper operation and maintenance. The operator shall at
all times properly operate and maintain all facilities and systems of treatment
and control, and related appurtenances, that are installed or used by the
operator to achieve compliance with the conditions of the permit. Proper operation
and maintenance includes effective performance, adequate funding, adequate
operator staffing and training, and adequate laboratory and process controls,
including appropriate quality assurance procedures. This provision requires
the operation of back-up and auxiliary facilities or similar systems only
when necessary to achieve compliance with the conditions of the permit.
(6)
Permit actions. The permit may be modified, revoked and
reissued, or terminated for cause. The filing of a request by the operator
for a permit modification, revocation and reissuance, or termination, or a
notification of planned changes or anticipated noncompliance does not stay
any permit condition.
(7)
Property rights. The permit does not convey any property
rights of any sort, or any exclusive privilege.
(8)
Duty to provide information. The operator shall also furnish
to the commission, within a time specified by the commission, any information
that the commission may request to determine whether cause exists for modifying,
revoking and reissuing, or terminating the permit, or to determine compliance
with the permit. The operator shall also furnish to the commission, upon request,
copies of records required to be kept under the conditions of the permit.
(9)
Inspection and entry. The operator shall allow any member
or employee of the commission, on proper identification, to:
(A)
enter upon the premises where a regulated activity is conducted
or where records are kept under the conditions of the permit;
(B)
have access to and copy, during reasonable working hours,
any records required to be kept under the conditions of the permit;
(C)
inspect any facilities, equipment (including monitoring
and control equipment), practices, or operations regulated or required under
the permit; and
(D)
sample or monitor any substance or parameter for the purpose
of assuring compliance with the permit or as otherwise authorized by the Texas
Water Code, §27.071, or the Texas Natural Resources Code, §91.1012.
(10)
Monitoring and records.
(A)
Samples and measurements taken for the purpose of monitoring
must be representative of the monitored activity.
(B)
The operator shall retain records of all monitoring information,
including all calibration and maintenance records and all original chart recordings
for continuous monitoring instrumentation, copies of all reports required
by the permit, and records of all data used to complete the permit application,
for at least three years from the date of the sample, measurement, report,
or application. This period may be extended by request of the commission at
any time.
(C)
Records of monitoring information must include the date,
exact place, and time of the sampling or measurements; the individual(s) who
performed the sampling or measurements; the date(s) analyses were performed;
the individual(s) who performed the analyses; the analytical techniques or
methods used; and the results of the analyses.
(11)
Signatory requirements. All reports and other information
submitted to the commission shall be signed and certified in accordance with
subsection (e) of this section.
(12)
Reporting requirements.
(A)
The operator shall notify the commission as soon as possible
of any planned physical alteration or addition to the facility.
(B)
The operator shall give advance notice to the commission
of any planned changes in the facility that may result in noncompliance with
permit requirements.
(C)
Monitoring results shall be reported at the intervals specified
in the permit.
(D)
Reports of compliance or noncompliance with the requirements
contained in any compliance schedule of the permit shall be submitted no later
than 30 days after each scheduled date.
(E)
The operator shall report to the commission any noncompliance
that may endanger human health or the environment.
(i)
An oral report shall be made to the appropriate district
office immediately after the operator becomes aware of the noncompliance.
A written report shall be filed with the Austin office within five days of
the time the operator becomes aware of the noncompliance. The written report
must contain the following information:
(I)
a description of the noncompliance and its cause;
(II)
the period of noncompliance, including exact dates and
times, and, if the noncompliance has not been corrected, the anticipated time
it is expected to continue; and
(III)
steps taken or planned to reduce, eliminate, and prevent
recurrence of the noncompliance.
(ii)
Information that shall be reported under this subparagraph
includes the following:
(I)
any monitoring or any other information that indicates
that any contaminant may endanger fresh water; or
(II)
any noncompliance with a permit condition or malfunction
of the injection system that may cause fluid migration into or between fresh
water strata.
(F)
The operator shall report any noncompliance not reported
under subparagraphs (C), (D), and (E) of this paragraph at the time monitoring
reports are submitted. The report must contain the information listed in subparagraph
(E) of this paragraph.
(G)
If the operator becomes aware that it failed to submit
any relevant facts or submitted incorrect information in a permit application
or a report to the commission, the operator shall promptly submit the relevant
facts or correct information.
(13)
Transfers. The permit is not transferable to any person
except by modification, or revocation and reissuance, to change the name of
the operator and incorporate other necessary requirements.
(14)
Completion report. Injection operations may not begin
in any new brine mining injection well until the operator has submitted a
completion report to the director, and the director has reviewed the completion
report and found the well in compliance with the conditions of the permit.
(15)
Workovers. The operator shall notify the appropriate district
office at least 48 hours before performing any workover or corrective maintenance
operations that involve the removal of the tubing or well stimulation.
(16)
Mechanical integrity.
(A)
No person may perform injection operations in a brine mining
injection well that lacks mechanical integrity. A well has mechanical integrity
if:
(i)
there is not significant leak in the casing; and
(ii)
there is no significant fluid movement into fresh water
strata through vertical channels adjacent to the wellbore.
(B)
For any existing brine mining injection well, mechanical
integrity must be demonstrated annually. For any new brine mining injection
well, mechanical integrity must be demonstrated before injection operations
begin and annually thereafter. In addition, for all brine mining injections
wells, mechanical integrity must be demonstrated after any workover that involves
the removal of the tubing.
(C)
To demonstrate the absence of a significant leak in the
casing, the operator shall conduct a fluid pressure test in accordance with
the following procedures:
(i)
the operator shall submit a written test procedure to the
commission in Austin at least 15 days before the test;
(ii)
the operator shall notify the district office orally at
least 48 hours before the test;
(iii)
the operator shall perform the test using the test procedure
submitted prior to the testing unless otherwise instructed by the commission;
and
(iv)
the operator shall file a complete record of the test
with the commission in Austin within 30 days after the test.
(D)
In lieu of an annual fluid pressure test, the operator
may monitor the pressure of a hydrocarbon pad or blanket contained in the
annulus space of the well, provided the operator has obtained written approval
from the director prior to using this method.
(E)
One of the following methods shall be used to demonstrate
the absence of significant fluid movement into fresh water strata through
vertical channels adjacent to the wellbore:
(i)
the results of a temperature or noise log; or
(ii)
where the nature of the casing precludes the use of the
logging techniques prescribed in clause (i) of this subparagraph, cementing
records demonstrating the presence of adequate cement to prevent such movement.
(F)
The director may allow the use of a method of demonstrating
mechanical integrity other than one listed in subparagraphs (C), (D), and
(E) of this paragraph with the approval of the administrator of the Environmental
Protection Agency obtained pursuant to 40 Code of Federal Regulations §146.8(d).
(G)
Mechanical integrity must be demonstrated to the satisfaction
of the director. In conducting and evaluating the results of a mechanical
integrity test, the operator and the director will apply procedures and standards
generally accepted in the industry. In reporting the results of a mechanical
integrity test, the operator must include a description of the method and
procedures used. In evaluating the results, the director will review monitoring
and other test data submitted since the previous mechanical integrity test.
(17)
Notice of conversion or abandonment. The operator shall
notify the commission at such times as the permit requires before conversion
or abandonment of the well.
(18)
Plugging. Within one year after cessation of brine mining
injection operations, the operator shall plug the well in accordance with §3.14(a)
and (c)(h) of this title (relating to Plugging) (Rule 14(a) and (c)-(h)).
For good cause, the director may grant a reasonable extension of time in which
to plug the well if the operator submits a proposal that describes actions
or procedures to ensure that the well will not endanger fresh water during
the period of the extension.
(g)
Other permit conditions. In addition to the conditions
required in all permits, the commission will establish conditions, as required
on a case-by-case basis, to provide for and assure compliance with the requirements
specified in this subsection.
(1)
Duration. Permits will be effective for a term up to the
operating life of the facility. The commission will review each permit issued
pursuant to this section at least once every five years to determine whether
cause exists for modification, revocation and reissuance, or termination of
the permit.
(2)
Operating requirements. Permits will prescribe operating
requirements, which will at a minimum specify that:
(A)
except during well stimulation, injection pressure at the
wellhead may not exceed a maximum calculated to assure that the injection
pressure does not initiate new fractures or propagate existing fractures in
the injection zone; and
(B)
in no case may the injection pressure initiate fractures
in the confining zone or cause the escape of injection or formation fluids
from the injection zone.
(3)
Monitoring requirements. Permits will specify the following
monitoring requirements:
(A)
requirements concerning the proper use, maintenance, and
installation, when appropriate, of monitoring equipment or methods;
(B)
requirements concerning the type, intervals, and frequency
of monitoring sufficient to yield data representative of the monitored activity,
including continuous monitoring when appropriate; and
(C)
requirements to report monitoring results with a frequency
dependent on the nature and effect of the monitored activity, but in no case
less than quarterly.
(4)
Construction requirements. Permits will specify construction
requirements to assure that the injection operations will not endanger fresh
water. Changes in construction requirements during construction may be approved
by the director as minor modifications of the permit. No such changes may
be physically incorporated into the construction of the well prior to approval
of the modifications by the director.
(A)
An existing brine mining injection well shall achieve compliance
with the construction requirements according to a compliance schedule established
as soon as possible and in no case later than one year after the effective
date of the permit. The permit will require the operator to submit a written
compliance report within 30 days after compliance has been achieved.
(B)
A new brine mining injection well must be cased and cemented
in accordance with §3.13 of this title (relating to Casing, Cementing,
Drilling, and Completion Requirements), (Rule 13), provided, however, that
the operator shall set and cement surface casing in accordance with the letter
obtained from the Texas Commission on Environmental Quality pursuant to subsection
(d)(4)(I) of this section regardless of the total depth of the well. No alternative
program for setting less surface casing will be authorized.
(C)
Appropriate logs and other tests must be conducted during
the drilling and construction of a new brine mining injection well. A descriptive
report interpreting the results of such logs and tests must be prepared by
a knowledgeable log analyst and submitted to the director. The logs and tests
appropriate to each well will be determined based on the depth, construction,
and other characteristics of the well, the availability of similar data in
the area, and the need for additional information that may arise from time
to time as the construction of the well progresses.
(5)
Financial responsibility. It shall be a permit condition
that the operator maintain financial responsibility and resources to plug
and abandon the brine mining injection well. The operator shall show evidence
of such financial responsibility to the commission by submitting a surety
bond or letter of credit in a form prescribed by the commission. Such bond
or letter of credit shall be maintained until the well is plugged in accordance
with subsection (f)(18) of this section.
(6)
Corrective action. For all known wells that penetrate the
injection zone within a 1/4 mile radius of the brine mining injection well
and are improperly completed, plugged, or abandoned, the commission will consider
requiring corrective action to prevent movement of fluid into fresh water
strata.
(A)
In determining the need for corrective action, the commission
will consider the following factors: nature and volume of injected fluid;
nature of native fluids; potentially affected population; geology; hydrology;
history of the injection operation; completion and plugging records; abandonment
procedures in effect at the time a well was abandoned; and hydraulic connections
with fresh water.
(B)
For an existing brine mining injection well requiring corrective
action, any permit issued will include a compliance schedule leading to compliance
with corrective action requirements. The compliance schedule will require
compliance as soon as possible and in no case later than one year after the
effective date of the permit. The permit will require the operator to submit
a written compliance report within 30 days after all required corrective action
has been taken.
(C)
For a new brine mining injection well, the operator may
not begin injection operations until all required corrective action has been
taken.
(h)
Modification, revocation and reissuance, and termination
of permits. A permit may be modified, revoked and reissued, or terminated
by the commission either upon the written request of any interested person,
including the operator, or upon the commission's initiative, but only for
the reasons and under the conditions specified in this subsection. Except
for minor modifications made under paragraph (2) of this subsection, the commission
will follow the applicable procedures in subsection (i) of this section. In
the case of a modification, the commission may request additional information
or an updated application. In the case of a revocation and reissuance, the
commission will require a new application. If a permit is modified, only the
conditions subject to modification are reopened. The term of a permit may
not be extended by modification. If a permit is revoked and reissued, the
entire permit is reopened and subject to revision, and the permit is reissued
for a new term.
(1)
Modification, or revocation and reissuance. The following
are causes for modification, or revocation and reissuance:
(A)
material and substantial alterations or additions to the
facility occurred after permit issuance and justify permit conditions that
are different or absent in the existing permit;
(B)
the commission receives new information;
(C)
the standards or regulations on which the permit was based
have been changed by promulgation of amended standards or regulations or by
judicial decision after the permit was issued;
(D)
the commission determines good cause exists for modifying
a compliance schedule, such as a act of God, strike, flood, materials shortage,
or other event over which the operator has little or no control and for which
there is no reasonably available remedy;
(E)
cause exists for terminating a permit under paragraph (3)
of this subsection, and the commission determines that modification, or revocation
and reissuance, is appropriate; or
(F)
a transfer of the permit is proposed.
(2)
Minor modifications. With the operator's consent, the director
may make minor modifications to a permit administratively, without following
the procedures of subsection (i) of this section. Minor modifications may
only:
(A)
correct clerical or typographical errors, or clarify any
description or provision in the permit, provided that the description or provision
is not changed substantively;
(B)
require more frequent monitoring or reporting;
(C)
change construction requirements provided that any changes
shall comply with the requirements of subsection (g)(4) of this section; or
(D)
allow a transfer of the permit where the director determines
that no change in the permit is necessary other than a change in the name
of the operator, provided that a written agreement between the current operator
and the new operator containing a specific data for the transfer of permit
responsibility, coverage, and liability has been submitted to the commission.
(3)
Termination. The following are causes for terminating a
permit during its term, or for denying a permit renewal application:
(A)
the operator fails to comply with any condition of the
permit or this section;
(B)
the operator fails to disclose fully all relevant facts
in the permit application or during the permit issuance process, or misrepresents
any relevant fact at any time;
(C)
a material change of conditions occurs in the operation
or completion of the well, or there are material changes in the information
originally furnished;
(D)
the commission determines that the permitted injection
endangers human health or the environment, or that pollution of fresh water
is occurring or is likely to occur as a result of the permitted injection;
or
(E)
fluids are escaping from the permitted injection zone.
(i)
Permitting procedures.
(1)
Review of applications. Upon receipt of an application
for a permit, the director will review the application for completeness. Within
30 days after receipt of the application, the director will notify the applicant
in writing whether the application is complete or deficient. A notice of deficiency
will state the additional information necessary to complete the application,
and a date for submitting this information. The application will be deemed
withdrawn if the necessary information is not received by the specified date,
unless the director has extended this date upon request of the applicant.
Upon timely receipt of the necessary information, the director will notify
the applicant that the application is complete. The director will not begin
processing a permit until the application is complete.
(2)
Permit denial. If the director administratively denies
a permit application, a notice of administrative denial will be mailed to
the applicant. The applicant will have a right to a hearing on request. If
the applicant requests a hearing, the notice of administrative denial will
be subject to the same procedures as a draft permit prepared under paragraph
(3) of this subsection.
(3)
Draft permits.
(A)
A draft permit will be prepared when the director tentatively
decides:
(i)
to issue a permit;
(ii)
to modify, or revoke and reissue, a permit; or
(iii)
to terminate a permit, in which case the director will
prepare a notice of intent to terminate, which is a type of draft permit.
(B)
A draft permit will contain all proposed permit conditions.
(4)
Fact sheets. The director will prepare a fact sheet to
accompany every draft permit that the director finds is the subject of widespread
public interest or raises important issues. The fact sheet will briefly set
forth the principal facts and the significant factual, legal, methodological,
and policy questions considered in preparing the draft permit. The fact sheet
will include information satisfying the requirements of 40 Code of Federal
Regulations §124.8(b).
(5)
Notice.
(A)
The commission will give notice when a draft permit is
prepared under paragraph (3) of this subsection, and when a hearing is scheduled
under paragraph (7) of this subsection.
(B)
Notice will be given by the methods specified in this subparagraph.
(i)
A copy of the notice will be mailed to the following persons:
(I)
any agency that the commission knows has issued or is required
to issue a permit for the same facility under any federal or state environmental
program;
(II)
the United States Environmental Protection Agency;
(III)
persons on a mailing list developed according to 40 Code
of Federal Regulations §124.10(c)(1)(viii);
(IV)
any unit of local government having jurisdiction over
the area where the facility is or is proposed to be located, and each state
agency having any authority under state law with respect to the construction
or operation of the facility;
(V)
the operator; and
(VI)
any oil and gas operators or surface owners required to
be listed in the application under subsection (d)(4)(F) and (G) of this section.
If, pursuant to subsection (d)(4)(G), the director waived the requirement
to list certain surface owners in the application, the applicant shall notify
such persons by publishing the notice. The notice shall be published by the
applicant once each week for two consecutive weeks in a newspaper of general
circulation for the county where the facility is located. The applicant shall
file proof of publication with the commission in Austin.
(ii)
The notice shall be published by the applicant at least
once in a newspaper of general circulation for the county where the facility
is located. The applicant shall file proof of publication with the commission
in Austin.
(C)
Notices will include information satisfying the requirements
of 40 Code of Federal Regulations §124.10(d) and the Texas Government
Code, Chapter 2001.
(D)
A copy of any draft permit, fact sheet, and application
will be mailed to the persons notified under subparagraph (B)(i)(I) and (II)
of this paragraph, and to any other person upon request. The applicant will
be mailed a copy of any draft permit and fact sheet.
(E)
The Texas Commission on Environmental Quality, the Texas
Water Development Board, the Texas Department of Health, the Texas Parks and
Wildlife Department, the United States Fish and Wildlife Service, other state
and federal agencies with jurisdiction over fish, shellfish, and wildlife
resources, the Advisory Council on Historic Preservation, state historic preservation
officers, and other appropriate government authorities will be given opportunity
to receive copies of notices, applications, draft permits, and fact sheets.
(6)
Comments and requests for hearing. Notice of a draft permit
will allow at least 30 days for public comment. During the public comment
period, any interested person may submit written comments on the draft permit
and may request a hearing if one has not already been scheduled.
(7)
Hearings on draft permits.
(A)
A hearing will be held:
(i)
when the director finds, on the basis of requests, a significant
degree of public interest in a draft permit;
(ii)
when an applicant or an affected person requests a hearing
on a draft permit; or
(iii)
when an operator requests a hearing on a draft permit
prepared when the director tentatively decides to modify, revoke and reissue,
or terminate a permit.
(B)
The commission may hold a hearing at its discretion, for
instance, when a hearing might clarify one or more issues involved in the
permit decision.
(C)
Notice of a hearing will be given at least 30 days before
the hearing. The public comment period under paragraph (6) of this subsection
will automatically be extended to the close of any hearing under this paragraph.
(8)
Administrative approval. After the close of the public
comment period, the director may issue, modify, revoke and reissue, or terminate
a permit administratively if no hearing is required under paragraph (7) of
this subsection.
(9)
Response to comments. When a final permit is issued, the
commission will respond in writing to comments received during the public
comment period. The response will be made available to the public and will:
(A)
specify which provisions, if any, of the draft permit have
been changed in the final permit, and the reasons for the changes; and
(B)
briefly describe and respond to all significant comments
on the draft permit raised during the public comment period, or during any
hearing on the draft permit.
(j)
Commission review of administrative actions. Administrative
actions performed by the director or commission staff pursuant to this section
are subject to review by the commissioners.
(k)
Federal regulations. All references to the Code of Federal
Regulations in this section are references to the 1987 edition of the Code.
The following federal regulations are adopted by reference and can be obtained
at the William B. Travis Building, 1701 North Congress Avenue, Austin, Texas
78711: 40 Code of Federal Regulations §§124.8(b), 124.10(c)(1)(viii),
124.10(d), and 146.8(d). Where the word "director" is used in the adopted
federal regulations, it should be interpreted to mean "commission."
(l)
Effective date. This section becomes effective upon approval
of the commission's Class III Underground Injection Control (UIC) Program
for brine mining injection wells by the United States Environmental Protection
Agency under the Safe Drinking Act, §1422 (42 United States Code §300h-1).
§3.85.Manifest To Accompany Each Transport of Liquid Hydrocarbons by Vehicle.
(a)
The following words and terms, when used in this section,
shall have the following meanings, unless the context clearly indicates otherwise.
(1)
Cargo manifest--One or more documents that together contain
the information required by subsection (c) of this section. That part of a
manifest which contains information unique to the particular transport being
described (such as date and time of removal) must be part of a book, tablet,
or series, wherein the documents are sequentially numbered.
(2)
Commission--The Railroad Commission of Texas.
(3)
Facility--Any place used to store, process, refine, reclaim,
dispose of, or treat liquid hydrocarbons.
(4)
Lease--A well producing oil, gas, or oil and gas, and any
group of contiguous wells producing oil, gas, or oil and gas of any number
operated as a producing unit.
(5)
Liquid hydrocarbons--Unrefined oil or condensate, and refined
oil or condensate to be blended with unrefined liquid hydrocarbons.
(6)
Oil tanker vehicle--A motor vehicle licensed for highway
use on a public highway or used on a public highway:
(A)
that is equipped with, carrying, pulling, or otherwise
transporting an assembly, compartment, tank, or other container that is used
for transporting, hauling, or delivering liquids; and
(B)
that is being used to transport liquid hydrocarbons on
a public highway.
(7)
Public highway--A way or place of whatever nature open
to the use of the public as a matter of right for the purpose of vehicular
travel, even if the way or place is temporarily closed for the purpose of
construction, maintenance, or repair.
(8)
Transporter--Each gatherer, storer, or other handler of
liquid hydrocarbons who moves or transports those liquid hydrocarbons by truck
or other motor vehicle, provided however, that the provisions of this rule
do not apply to:
(A)
common carriers as defined in the Natural Resources Code,
Chapter 111; or
(B)
the movement of salt water, brine, sludge, drilling mud,
or other liquid or semiliquid material if the commission has authorized the
entity to move such material and such material contains less than 7.0% liquid
hydrocarbon, by volume, or if not authorized by the commission, the movement
is not for hire and the material moved does not contain more than 7.0% liquid
hydrocarbons by volume.
(b)
A cargo manifest must be carried in each oil tanker vehicle
transporting liquid hydrocarbons on a public highway in this state and must
be presented on request for inspection as provided by subsection (f) of this
section.
(c)
For each load of liquid hydrocarbons loaded onto and transported
by an oil tanker vehicle, the cargo manifest must include:
(1)
an identification of the lease or facility from which the
liquid hydrocarbons were removed, which must include:
(A)
the lease or facility name; and
(B)
the name of the operator of the lease or facility;
(2)
the total quantity of liquid hydrocarbons removed from
the lease or facility and loaded onto the oil tanker vehicle; provided that
for purposes of indicating quantity on the copy of the manifest left with
the lease operator, top and bottom gauges will suffice. On the other copies,
an estimate in barrels must be included;
(3)
the date and hour when the liquid hydrocarbons were removed
from the lease or facility and loaded onto the oil tanker vehicle;
(4)
the identity of the transporter which must include;
(A)
the company or individual transporter's name and address;
(B)
the oil tanker vehicle driver's name; and
(C)
a unique number for the oil tanker vehicle that for a truck
tractor and semitrailer type oil tanker vehicle must include unique vehicle
numbers for both truck tractor and semitrailer; and
(5)
the intended point of destination for the liquid hydrocarbons,
including the name of the receiving facility.
(d)
Copy of manifest to be left at the lease.
(1)
A copy of the cargo manifest must be left at the lease
or facility from which the liquid hydrocarbons were removed or delivered to
the lease or facility operator, his agent, or his representative.
(2)
The requirements of this section may be met by leaving
a separate document at the lease or facility from which the liquid hydrocarbons
were removed or by delivering to the lease or facility operator a separate
document that includes information required under subsection (c)(1)-(3) and
(4)(A) and (B) this section.
(3)
If more than one load of liquid hydrocarbons is removed
from a single tank or other container of liquid hydrocarbons within a period
of 24 consecutive hours, subsection (c)(2) and (3) of this section may be
met for purposes of this section by a separate document that includes:
(A)
the total quantity of liquid hydrocarbons removed;
(B)
the date and hour the first load was removed; and
(C)
the date and hour the last load was removed.
(4)
If the operator of a facility requires that a transporter
leave at the facility or deliver to the operator a document other than the
transporter's cargo manifest, a transporter may meet the requirements of this
section by leaving those specified documents at an agreed location or delivering
the document to the operator.
(e)
After the delivery of all liquid hydrocarbons in an oil
tanker vehicle is completed, the cargo manifest must be maintained in the
records of the transporter for a period of not less than two years from the
date the liquid hydrocarbons are removed from the oil tanker vehicle.
(f)
Upon request from a commission agent or other law enforcement
official the transporter must produce the cargo manifest for inspection immediately,
whether it is on an oil tanker vehicle or in the records of the transporter.
Copies of cargo manifests must be filed with the commission, upon request
from the commission.
(g)
Companies or individuals who do not have organization reports
(Form P-5) on file with the Railroad Commission, as required by §3.1
of this title (relating to Organization Report; Retention of Records; Notice
Requirement (commonly referred to as Statewide Rule 1)), may not issue cargo
manifests.
(h)
Every truck or other vehicle covered by this section shall
bear on both sides thereof the name of the company or individual responsible
for such transportation, the number of the vehicle, and the number of the
certificate or permit authorizing the service. In the case of vehicles not
for hire, this number shall be the company's organizational report (P-5) number.
The identifying signs shall be printed in letters not less than two inches
in height, in sharp color contrast to the background, and shall be plainly
legible for a distance of at least 50 feet.
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of
the Secretary of State on August 5, 2003.
TRD-200304756
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Effective date: August 25, 2003
Proposal publication date: June 27, 2003
For further information, please call: (512) 475-1295
16 TAC §§3.65 - 3.67, 3.69, 3.72, 3.75, 3.77
The Commission adopts the repeals pursuant to Texas Natural
Resources Code, §§81.051 and 81.052, which provide the Commission
with jurisdiction over all persons owning or engaged in drilling or operating
oil or gas wells and persons owning or operating pipelines in Texas and the
authority to adopt all necessary rules for governing and regulating persons
and their operations under Commission jurisdiction and pursuant to Texas Natural
Resources Code §§85.042, 85.202, 86.041 and 86.042 which require
the Commission to adopt rules to control waste of oil and gas.
Statutory authority: Texas Natural Resources Code, §§81.051,
81.052, 85.024, 85.202, 86.041, and 86.042.
Cross-reference to statute: Texas Natural Resources Code, §§81.051
and 81.052 and §§85.042, 85.202, 86.041 and 86.042.
Issued in Austin, Texas, on August 5, 2003.
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed
with the Office of the Secretary of State on August 5, 2003.
TRD-200304755
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Effective date: August 25, 2003
Proposal publication date: June 27, 2003
For further information, please call: (512) 475-1295
Subchapter B. REQUIREMENTS FOR NATURAL GAS AND HAZARDOUS LIQUIDS PIPELINES
16 TAC §8.101
The Railroad Commission of Texas adopts amendments to §8.101,
relating to Pipeline Integrity Assessment and Management Plans for Natural
Gas and Hazardous Liquids Pipelines, without changes to the proposal published
in the March 28, 2003, issue of the
Texas Register
(28 TexReg 2679). As amended, §8.101 provides an alternative
means for approval of the use of direct assessment by hazardous liquids and
natural gas pipeline operators as an assessment tool. Previously, §8.101(b)(1)
required that a hearing be held in all instances in which a pipeline operator's
integrity assessment plan lists direct assessment or other methods of assessment
not specifically listed in the rule as the assessment methodology. Proposed
new §8.103 set forth procedures for reviewing operators' requests for
approval of direct assessment and other technology options listed in §8.101(b)(1).
The Commission does not adopt proposed new §8.103 and withdraws the proposal.
In April 2001, the Commission adopted §8.101, which requires all natural
gas and hazardous liquids pipeline operators to develop an integrity assessment
and management plan for their pipeline systems. In §8.101(b)(1)(C), the
rule listed four different assessment tools available to operators to assess
the integrity of their pipelines. Of the four assessment tools listed, two--direct
assessment and other technology or assessment methodology not specifically
listed--required a hearing and Commission approval prior to their use. To
date, there have been no hearings on the direct assessment or other new technology
methods. The Commission amends §8.101(b)(1)(C) to remove the mandate
for a hearing when an operator requests approval of direct assessment or other
technology options not specifically listed in §8.101(b)(1). Such requests
would still require the approval of the Commission. The amendment will provide
each operator the opportunity for a hearing, if needed, but does not mandate
that a hearing be conducted. Commission approval of a direct assessment methodology
could be achieved by an order of the Commission without a hearing. Under the
adopted amendment, Pipeline Safety staff would work with the operators to
review requests for approval of direct assessment plans and, upon the concurrence
of both the operator and the Pipeline Safety staff, would present to the Commission
a recommendation of approval of the assessment methodology in the form of
an agreed order. If an operator and Pipeline Safety staff could not reach
an agreement regarding the method or methods of assessment, the operator would
have had an opportunity to request a hearing as provided in proposed new §8.103.
New §8.103 was intended to provide specific procedural guidelines
for operators and staff in applying for and reviewing requests for approval
of direct assessment or other assessment methodology not specifically listed
in §8.101(b)(1)(C) and, if necessary, in conducting any hearing that
might be convened.
The Commission received six written comments on the proposal from Atmos
Energy (Atmos), Air Products and Chemicals, Inc. (Air Products), Texas Oil &
Gas Association (TxOGA), the Association of Texas Intrastate Natural Gas Pipelines
(ATINGP), Houston Pipe Line Company (HPL), and TXU Gas Company and TXU Fuel
Company (TXU), jointly, and one oral comment from an attorney practicing
before the Commission.
The two comments from associations expressed agreement with the proposed
amendment to §8.101 to remove the requirement that a hearing be conducted
in every application for approval of direct assessment. One association was
generally in agreement with proposed new §8.103 but expressed disagreement
or requested clarification with respect to specific elements of the rule.
The other association opposed new §8.103 as premature.
Each of the commenters supported the adoption of §8.101 without any
changes. TXU's comments lauded the ability of pipeline operators to discuss
various technical issues with the Commission's Pipeline Safety Section staff
in an informal setting that promotes the free and easy exchange of information,
contrasted to the formal processes attendant to an evidentiary hearing that
often inhibits the open dialogue necessary for full understanding of a new
methodology. The proposed approach promotes the integration of suggestions
from the Pipeline Safety Staff into new methodologies, resulting in improvements.
Atmos' comment suggested the Commission allow an additional year for operators
to have direct assessment plans approved by the Commission. The Commission
did not propose an amendment to the deadline for submitting baseline assessments.
Operators may, however, apply and receive approval for direct assessment methods
for assessments beyond their baseline assessments.
Air Products also supports the recommended changes to §8.101 without
revision and feels the efforts conducted so far by both the Commission staff
and Air Products have been effective in the process to approve direct assessment
methodologies. HPL, while supporting §8.101, expressed concern over the
wording in §8.103. Houston Pipeline asked that we consider the comments
submitted by TxOGA and ATINGP, with which HPL agrees.
TXU's comments support the changes made to §8.101, but additionally
urge the Commission to consider treating direct assessment as a basic assessment
method similar to in-line inspection and pressure testing without Commission
approval. TXU's rationale is to make the Commission rules similar to the federal
requirements found in the Pipeline Safety Improvement Act of 2002.
TXU opposed adoption of §8.103 as proposed and expressed concerns
about the language in §8.103. In TXU's opinion, the informal procedures
currently in use by the Pipeline Safety staff adequately address the items
covered by the rule, and no formal procedures are necessary. TXU observed
that it would be appropriate to remain silent on procedures for review, but
in the event that the Commission adopts a procedural rule, offered language
to replace §8.103.
The oral comment from an attorney practicing before the Commission generally
supported adoption of §8.103 as proposed, observing that it was a useful
reference for operators in crafting applications for approval of direct assessment,
guidance that was lacking until now or had to be obtained by calling or writing
Commission staff.
ATINGP also supported the adoption of changes to §8.101, but opposed
adoption of §8.103 as premature. ATINGP commented that the rule is too
inflexible and there may be alternative approaches to resolve the procedural
issues addressed in §8.103. ATINGP suggested that procedural issues can
better be handled through a prehearing conference which could establish a
procedural schedule as well as resolve outstanding issues. By holding a prehearing
conference, the stage would be set if there is the need for a formal hearing.
TxOGA submitted comments in support of the proposed amendments to §8.101,
and provided general support of proposed new §8.103; however, TxOGA did
identify several concerns with specific portions of new §8.103. Specifically,
TxOGA suggested that §8.103(c) does not clearly address the approval
process for administrative approval of the integrity assessment tools. HPL
also observed that the rule is not clear with respect to administrative approval
processes.
TxOGA also questioned the requirement in §8.103(c) for providing the
number of miles in the system, suggesting that the information is already
available through the T-4 permit and/or the integrity management plan and
that the information request is not appropriate as part of the direct assessment
review.
TxOGA sought clarification regarding the requirements in §8.103(c)(4),
which requires information regarding the availability of previous test data
on pipeline facilities.
TxOGA requested clarification on proposed §8.103(c)(5), concerning
the request for risk factors used in the integrity risk model. TxOGA specifically
requested clarification as to whether the Commission is requesting a matrix
or the actual data for the segments.
In §8.103(c)(7), TxOGA questioned the clarity of the rule in its requirement
for validation data. TxOGA suggested that the Commission include more specific
information to clarify this section in order to determine what is actually
required as sample verification data.
TxOGA requested clarification of the Commission's intent with respect to
the language in §8.103(g) and suggested the Commission include provisions
for division administrative reviews under §8.103(d).
The Commission agrees that proposed new §8.103 is premature and declines
to adopt it; the proposal is withdrawn.
The Commission adopts the amendment to §8.101 pursuant to
Texas Natural Resources Code, §§117.001-117.101, which authorize
the Commission to adopt safety standards and practices applicable to the transportation
of hazardous liquids and carbon dioxide and associated pipeline facilities
within Texas to the maximum degrees permissible under, and to take any other
requisite action in accordance with, 49 United States Code Annotated, §60101,
et seq.; and Texas Utilities Code, §§121.201-121.210, which authorize
the Commission to adopt safety standards and practices applicable to the transportation
of gas and to associated pipeline facilities within Texas to the maximum degree
permissible under, and to take any other requisite action in accordance with,
49 United States Code Annotated, §60101, et seq.
Statutory authority: Texas Natural Resources Code, §§117.001-117.101;
and Texas Utilities Code, §§121.201-121.210.
Cross-reference to sections affected: Texas Natural Resources Code, §§117.001-117.101;
and Texas Utilities Code, §§121.201-121.210.
Issued in Austin, Texas, on August 5, 2003.
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of
the Secretary of State on August 5, 2003.
TRD-200304757
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Effective date: August 25, 2003
Proposal publication date: March 28, 2003
For further information, please call: (512) 475-1295
Subchapter A. GENERAL REQUIREMENTS
16 TAC §§9.2, 9.9, 9.51 - 9.54
The Railroad Commission of Texas (Commission) adopts amendments
to §§9.2, 9.9, and 9.51-9.54, relating to Definitions; Requirements
for Certificate Renewal; General Requirements for Training and Continuing
Education; Training and Continuing Education Courses; Continuing Education
Credit for Previous Courses; and Commission-Approved Outside Instructors,
without changes to the versions published in the June 27, 2003, issue of the
In §9.2, the Commission adds new definitions for "AFT materials,"
"applicant" and "certificate holder"; revises the definition of "CETP" to
reflect the recent transfer of ownership of that program from the National
Propane Gas Association to the Propane Education and Research Council; revises
the definition of "outside instructor" to clarify that classes taught by approved
outside instructors may be presented for Railroad Commission training credit
as well as for continuing education credit; clarifies the definition of "training";
and renumbers the remaining definitions. The three new definitions are for
clarification and do not substantively change current Commission policies
or procedures.
Section 9.9(c) includes the increase in the annual certificate renewal
fee from $25 to $35. This fee is the primary source of funding for the training
and continuing education program for the approximately 10,000 LP-gas certificate
holders. The $10 increase will cover about $100,000 of the approximately $135,700
of general revenue that was available for training and continuing education
in the 2002-2003 biennium but will not be available in the 2004-2005 biennium.
The Commission plans to make up the approximately $35,700 difference through
grants or cost savings. Other new language in §9.9(c) expressly states
that governmental employees do not have to pay this fee and, in subsection
(c)(1), clarifies the dates of the two-year period during which an individual
whose certification has lapsed may pay a late-filing fee instead of complying
with the requirements for a new certificate. Other clarifying language in
subsection (d) regards lapsed certifications.
Throughout §§9.51-9.54, some non-substantive changes have been
adopted, mainly with regard to the use of the word "course." The Commission
will use the word "course" to refer to each individual course of instruction
included in the Commission's curriculum. The Commission will use the word
"class" to refer to a particular session held at a specific time and place.
The Commission adopts substantive amendments in §9.51(b) regarding
failure to comply with a training or continuing education requirement by an
assigned deadline and the payment of late-filing fees. In subsection (b)(1),
the Commission extends the training and continuing education requirements
to Category D, F, G, J, and K applicants and certificate holders. Categories
D, F, G, J, and K are being added to the currently covered Category E and
Category I to increase public safety by training approximately 400 additional
individuals whose jobs require them to handle propane in Texas. The Commission
has increased the number and types of courses offered in its training and
continuing education program to accommodate certificate holders in these additional
categories.
In §9.51(d), the Commission adopts new language to clarify that an
individual who is required to pay a fee for a class may not receive credit
for the class until the fee is paid in full.
In §9.51(e), the Commission updates class schedules on its web site
monthly, rather than twice a year, to ensure that current schedule information
is available timely.
In §9.51(f)(1), the Commission deletes the requirement that registration
forms be filed with the AFRED training section at least seven calendar days
prior to a class. The Commission would rather have the classes be well attended,
instead of having vacancies in a class because an individual was late in getting
the registration form to the Commission. Also in subsection (f)(1), the Commission
has added to the required registration information the registrant's level
and category of certification, to ensure that applicants and certified individuals
register for a course that will confer Railroad Commission training or continuing
education credit. In subsection (f)(2)(A), Categories F and G are added to
Category I, currently in the rule, in the references to the 16-hour required
course of instruction. New language is also adopted with regard to eight-hour
and 80-hour classes. New subparagraph (B) clarifies that the class fee does
not include the rules examination fee or the license fee. Also, a new sentence
in subparagraph (C) states that current certificate holders who have paid
the annual renewal fee and who want to add a new certification other than
a Category E, F, G, or I shall not be required to pay the $75 class fee. In
subsection (f)(2)(B), the Commission has deleted the reference to courses
P115, P116, and P117, which are no longer offered.
In §9.51(f)(2), the Commission adds new subparagraph (E) to allow
individuals or governmental subdivisions to request that the Commission conduct
a non-credit course and authorize the Commission to do so if an instructor
is available to teach the requested course and enough students have registered.
The new language also establishes the fees for such courses.
In subsection (f)(3), the Commission has added language to clarify its
current practices when registering individuals for classes. The language clarifies
that priority for registering in eight-hour classes will be given to individuals
whose renewal deadline is the soonest, and priority for registering in 16-hour
and 80-hour classes is based on the date the course fee is paid. Other new
language allows the AFRED training section to reschedule individuals who were
registered for a class that was cancelled.
Other changes in §9.51 are non-substantive and involve changes in
wording, organization, or punctuation for clarity.
In §9.52(a), the Commission has added the same categories added in §9.51(b)(1).
New wording specifically states that Category E applicants shall attend the
80-hour course; Categories F, G, and I applicants shall attend the 16-hour
course; and all other applicants shall attend an eight-hour course. The corresponding
new categories are also added to subsection (a)(1), with one exception: New
subsection (a)(1)(K) includes appliance service and installation employee-level
applicants. This group was already included in the rules, but was not listed
in subsection (a)(1), and is added now for clarification. Another clarification
in subsection (a)(3) adds a reference to AFT requirements, and in subsection
(a)(4) the cross-reference to §9.17 is corrected from subsection (e)
to subsection (g).
Current §9.52(b) specifies how the Commission phased in the continuing
education requirements for certificate holders when this rule was first adopted
in February 2001 and amended in May 2001 by assigning renewal dates randomly
over the following four years. This random assignment was necessary in order
for the Commission's training staff to train the approximately 10,000 certificate
holders in existence at that time. Now that this initial random assignment
has taken place, the language in subsection (b)(1) is deleted because it is
no longer necessary. New language in subsection (b) clarifies how the four-year
continuing education deadline date will be determined. Language is also added
to subsection (b)(1)(A) to add the same new categories that were added in
subsection (a)(1) of this rule.
In a substantive amendment, new §9.52(b)(1)(B) specifies May 31, 2005,
as the deadline for current Category D, F, G, J, and K certificate holders
who hold only one certification as of the effective date of these amendments
to complete their continuing education requirement. Current Category D, F,
G, J, and K certificate holders who hold more than one certification as of
the effective date of these amendments shall complete their continuing education
requirement by their current assigned continuing education deadline. In paragraph
(3), a new sentence clearly states that governmental employees are not required
to pay the annual certificate renewal fee.
New §9.52(c) clarifies that the Commission's Train-the-Trainer classes
do not count for training or continuing education credit. This wording clarifies
that Category D or E certificate holders who are approved outside instructors
must comply with all course requirements for each of those activities and
may not receive "double credit" for one course.
Section 9.52(f) deals with advanced field training (AFT). The Commission
adopts some clarifying amendments and deletes the requirements that completed
AFT certification paperwork be submitted to the Commission. The Commission
requires the AFT to be properly completed within 30 calendar days of attending
a class. All of the qualification tasks must be completed, including the AFT
qualification checklist. Completed AFT materials, including the certification
page, must be retained and readily available for inspection by an authorized
person at a licensee's business location in Texas. In paragraph (1), new wording
states that the responsibility for certifying AFT shall not be delegated to
an unauthorized individual. New paragraph (2) illustrates different scenarios
related to the retention of AFT materials and clarifies who is responsible
for keeping the AFT materials. Additionally, the text will clarify that all
the performance tasks in the AFT certificate must be completed. In paragraph
(3), renumbered from (2), Categories F and G are added to Category I with
respect to required completion of the 16-hour management course.
Existing subsection (f) regarding computer-based continuing education courses
is repealed. The Commission wishes to avoid the cost of updating its current
computer-based courses in light of the recent decline in usage. However, as
specified in §9.53(2), the Commission will continue to award credit for
computer-based courses through September 1, 2003.
The Commission adopts some substantive changes in §9.52(g) to divide
into four tables the current single table that lists each course offered and
specifies which certificate holders may complete that course for training
or continuing education credit. The four-table format is more specific and
better organized. With the addition of Categories D, F, G, J, and K to the
training and continuing education program, the information in the tables has
been expanded to include those categories. In particular, the changes are
as follows:
1. Dates have been added following the title of each table. As the tables
are revised in future rulemakings, the date will be changed to a "Revision"
date.
2. The Commission has added the following new courses indicated on Tables
1 and 2: 2.2/2.4, Inspecting, Requalifying, Filling and Transporting DOT Cylinders;
and Evacuating, Transporting, Maintaining and Refitting ASME Tanks; 3.1, Residential
Propane System Layout and Design; 3.2, Residential Propane System Installation;
3.7, Electrical Troubleshooting and Repairing Residential Gas Appliances;
3.11, Residential Propane System Inspection; and 6.1, Regulatory Compliance.
3. The first table, entitled "LP-Gas Management-Level Training and Continuing
Education Courses," includes Categories D, E, F, G, I, J, and K management-level
courses, course numbers, hours, and titles, and indicates whether AFT is included.
An "x" in the row for a particular course indicates the course is approved
for the corresponding license category. For example, a Category D management-level
applicant or certificate holder who will be required to attend training or
continuing education may take course 1.1, 3.1, 3.2, 3.5, 3.7, 3.11, or the
80-hour course.
4. Table 2, entitled "LP-Gas Employee-Level Training and Continuing Education
Courses," lists employee-level courses. As compared to the current table in §9.52,
in the segment of the table entitled "Railroad Commission Training and Continuing
Education Courses Available After September 1, 1997," some courses have been
eliminated and some courses have been added. The following courses will no
longer be offered: P109A, Appliance Installation; P113A, Appliance Service
Persons Overview; P115, GAS Check (3 days); P116, GAS Check (2 days); P117,
GAS Check (self-study); P120, Bulk Plant Management; P121, Propane Distribution
Systems; and P122, Residential Systems Safety Inspection--Appliances and Exterior.
These courses do not appear on any of the new tables.
5. In Table 3, entitled "Courses Which Count Towards Continuing Education
Credit For Management-Level Certificate Holders," and Table 4, entitled "Courses
Which Count Towards Continuing Education Credit For Employee-Level Applicants
or Certificate Holders," the Propane Education and Research Council's (PERC)
GAS Check course (formerly offered by the National Propane Gas Association
(NPGA)) has been added. The two tables are divided to show which courses apply
to management-level certificate holders and which courses apply to employee-level
certificate holders.
Section 9.53 covers continuing education credit for previous courses. This
section was originally adopted to allow certificate holders who had taken
Commission courses prior to the establishment of the training and continuing
education program to receive credit for those courses in certain instances.
Only non- substantive changes are adopted in this rule, namely, a clarification
of the random assignment of initial due dates as previously discussed in the
corresponding amendment to §9.52(b). In paragraph (2), the date of September
1, 2003, is added to indicate the date on which credit will no longer be given
for completing the Commission's current computer-based courses.
Section 9.54 covers the requirements for Commission-approved outside instructors.
In subsection (a)(1), the Commission adds that outside instructors may also
offer training classes for specified management-level and employee-level applicants,
as well as continuing education for current certificate holders. New subparagraphs
(A) and (B) add that Category D certificate holders may also become outside
instructors and clarify what courses may be offered by a Category D or Category
E outside instructor. Subsection (b) also includes some nonsubstantive new
language regarding the outside instructor application process for Category
D.
In subsection (h), the Commission adopts a new Train-the-Trainer refresher
course that outside instructors must attend prior to their next renewal deadline.
The new refresher course replaces the previous requirement that an outside
instructor must teach at least one course each year to maintain certification
as an outside instructor and will help ensure that outside instructors know
current rules and requirements. As with the language in §9.52(c), new
language in §9.54(j)(1) states that the Train-the-Trainer class will
not count towards a Category D or E applicant's or certificate holder's training
or continuing education requirement.
The Commission simultaneously adopts the review and readoption of §§9.2,
9.9, and 9.51 - 9.54 in accordance with Texas Government Code, §2001.039.
The notice of adopted review will be filed with the
Texas Register
concurrently with this adoption.
The Commission received one comment on the proposed amendments, from the
Texas Propane Gas Association (TPGA). TPGA's comment was directed specifically
to the proposed $10 increase in the annual renewal fee, from $25 to $35, in §9.9(c).
Rather than increase this fee, representing approximately $100,000 in additional
revenue, TPGA suggested that the Commission decrease staff and expenses to
align both with current appropriations, and further suggested that a thorough
audit review of the entire training program must be completed prior to any
approval of a fee increase.
The Commission does not agree with TPGA's comments and suggestions. First,
the fee increase is necessary to make up the loss of general revenue appropriations
that occurred in the 78th Legislature. Because there has been no decrease
in the LP-gas industry's demand for Commission training and continuing education
courses and classes, reducing staff would impair the ability of the Commission
to deliver propane safety training that benefits both the industry and its
customers, as well as the general public.
Second, the Commission's financial operations are audited, as required
by state law, and scrutinized by several entities: the Commission's internal
audit function; the State Auditor's Office; the Comptroller of Public Accounts;
the Legislative Budget Board; the Governor's Budget Office; and the Sunset
Advisory Commission. The Commission does not agree that an additional audit
is necessary.
The Commission adopts the amendments under the Texas Natural
Resources Code, §113.051, which authorizes the Commission to adopt rules
relating to any and all aspects or phases of the LP-gas industry that will
protect or tend to protect the health, welfare, and safety of the general
public.
Statutory authority: Texas Natural Resources Code, §113.051
Cross-reference to statute: Texas Natural Resources Code, §113.051
Issued in Austin, Texas, on August 5, 2003.
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of
the Secretary of State on August 5, 2003.
TRD-200304759
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Effective date: August 25, 2003
Proposal publication date: June 27, 2003
For further information, please call: (512) 475-1295
Chapter 402.
BINGO REGULATION AND TAX
Chapter 8.
PIPELINE SAFETY REGULATIONS
Chapter 9.
LP-GAS SAFETY RULES
Part 9.
TEXAS LOTTERY COMMISSION