Part 1.
RAILROAD COMMISSION OF TEXAS
Chapter 3.
OIL AND GAS DIVISION
16 TAC §3.14
The Railroad Commission of Texas (Commission) adopts amendments
to §3.14, relating to Plugging, with changes to the version published
in the March 14, 2003, issue of the
Texas Register
(28 TexReg 2160). The Commission adopts these amendments as a result
of changes to Texas Natural Resources Code, §89.011, made by Senate Bill
310, 77th Legislature (2001), which became effective September 1, 2001. The
Commission also adopts other amendments to allow for Commission approval of
variances from certain requirements of the rule, to clarify wording and to
conform the rule to Commission practice.
Senate Bill 310 amended Texas Natural Resources Code, §89.011, to
require that an operator plugging a well after September 1, 2001, verify the
placement of the plug at the base of the deepest fresh water stratum required
to be protected, if usable quality water strata are present. Amended §89.011
states that the well is considered to have been properly plugged only when
such verification is satisfactory and meets Commission requirements. The Commission
has been enforcing this statutory requirement since September 1, 2001, and
now adopts amendments to §3.14 to incorporate this requirement.
Statutory amendments to Texas Natural Resources Code, §89.011, also
establish that the duty of an operator to properly plug a well that is being
plugged back to produce fresh water for the use of the surface owner ends
only when the well has been properly plugged in accordance with Commission
requirements and the surface owner has obtained a permit for the well from
the groundwater conservation district, if applicable. The Commission amends §3.14(a)(4)
to state that the Commission will consider an application for a surface owner
to condition an abandoned well for fresh water production only if the surface
owner submits a signed statement attesting that one of the following four
facts exists: there is no groundwater conservation district for the area in
which the well is located; there is a groundwater conservation district for
the area where the well is located, but the groundwater conservation district
does not require that the well be permitted or registered; the surface owner
has registered the well with the groundwater conservation district for the
area where the well is located; or the surface owner has obtained a permit
from the groundwater conservation district for the area where the well is
located. In addition, the Commission adds language regarding the requirement
that the duty of the operator to properly plug the well ends only when the
well has been properly plugged in accordance with Commission requirements
up to the base of usable quality water stratum; the Commission has approved
the application to condition the well for usable quality water production
operations; and the surface owner has registered the well with, or has obtained
a permit for the well from, the groundwater conservation district, if applicable.
Because the "permitting" requirements of the various groundwater conservation
districts are not uniform, the Commission's adopted language reflects the
fact that the groundwater conservation districts may require a permit for
water wells, require registration of water wells, or neither. Information
concerning the various groundwater conservation districts can be found at
www.texasgroundwater.org.
The Commission deletes or modifies some of the definitions currently in §3.14(a)(1)
and adds new definitions. The Commission adds definitions for "approved cementer,"
"groundwater conservation district," and "related piping" for clarification.
The Commission deletes the definitions for "bay well," "offshore well," and
"land well." The Commission also considered deleting the term "individual
well bond" in response to comments; however, such deletion was not noticed
for this rulemaking. No one who might be in favor of keeping the definition
in this rule had an opportunity to comment. The Commission therefore keeps
the definition in the adopted rule and will consider its deletion in future
rulemakings. All of these terms are defined in §3.78 of this title (relating
to Fees, Performance Bonds and Alternate Forms of Financial Security Required
To Be Filed). The Commission amends the definition of "usable quality water
strata" to reflect the fact that the Texas Natural Resource Conservation Commission
is now the Texas Commission on Environmental Quality (TCEQ). The Commission
also amends the term "to serve surface notice" to "to serve notice on the
surface owner or resident" to clarify to whom the Commission requires an operator
to provide notice of intent to plug a well. The Commission proposed to use
the term "landowner" instead of "surface owner", and to replace the term "surface
notice." In response to comments that the term "surface owner" is what most
people use to refer to the person who owns the surface estate, the Commission
decided not to use "landowner." The Commission kept the element of the definition
that allows notice to be served on the surface owner or resident if the surface
owner is not present.
In the proposed amendments, the Commission included language to clarify
which specific Commission personnel have the authority to grant the various
necessary approvals and proposed an amendment to change the term "assistant
director of well plugging" to "deputy director of field operations" to reflect
the correct title. However, the Commission adopts the term "Director or the
Director's delegate" to refer to the director of the Oil and Gas Division
Director or the Commission employee to whom the Director delegates authority
to grant the various necessary approvals. The Commission adopts the term "District
Director or the District Director's delegate" to refer to the various Oil
and Gas Division District Directors or the Commission employee in each respective
District to whom the District Director delegates authority to grant the various
necessary approvals.
In §3.14(a)(3), the Commission adds a clarifying statement that the
Commission's approval of a notice of intent to plug and abandon a well does
not relieve an operator of the requirement to comply with the requirements
in subsection (b)(2) to plug the well, produce the well, or obtain an extension
to plug the well, test the well, or obtain financial assurance for the well.
In §3.14(b)(2)(A), the Commission corrects a citation in subclause
(V).
The Commission amends §3.14(b)(2)(E), to clarify the existing requirement
that inactive, bonded wells that are over 25 years old must be tested to determine
whether the well poses a potential threat of harm to natural resources.
In §3.14(b)(4)(A), the Commission clarifies that the Commission may
plug or replug any dry or inactive well, after notice and opportunity for
hearing, if any formation fluid is leaking from the well, not just oil or
gas.
In §3.14(d)(2), the Commission incorporates the statutory requirement
from Senate Bill 310 that the operator verify the placement of the plug required
at the base of the deepest usable quality water stratum by tagging the plug
with tubing or drill pipe or by an alternate method approved by the district
director or the district director's delegate. This change incorporates the
statutory requirement the Commission has been enforcing since September 1,
2001, the effective date of SB 310. In addition, the Commission adds to this
paragraph language to clarify the existing requirement that plugs be set as
necessary to separate multiple usable quality water strata.
The Commission also amends §3.14(d)(4) to include language providing
for approval of plugging materials other than cement. The Commission will
require that any such request be submitted in writing to the Director or the
Director's delegate and include all pertinent information to support such
a request. The Commission adopts as the overall standard for approval of a
request to use alternate plugging material, that the alternate plugging material
and method will ensure that the well does not pose a potential threat of harm
to natural resources.
Section 3.14(d)(9) currently requires the use of a mud-laden fluid with
specific characteristics during plugging. In response to requests from a member
of the Oil Field Cleanup Advisory Committee, the Commission adopts amendments
to allow for approval of requests for the use of alternate fluids between
plugs.
In §3.14(d)(10), the Commission makes a conforming amendment to delete
the reference to §3.94, relating to Disposal of Oil and Gas NORM Waste,
which was repealed by the Commission on February 11, 2003, and replaces it
with a reference to new §4.614(b) relating to Authorized Disposal Methods,
one of the NORM rules which the Commission adopted on that same date. The
effective date of new §4.614 is March 3, 2003.
Prior to this proposal, the Commission had received comment that the current
language in §3.14(d)(12) was confusing because it could be read to imply
that all surface and subsurface piping on a lease or other facility must be
removed after plugging. The Commission adds a definition of "related piping"
in §3.14(a)(1)(J) and amends the wording in (d)(12), to clarify that
only related surface and subsurface piping that is less than three feet beneath
the ground surface must be removed within 120 days after plugging work is
complete. The Commission clarified this requirement in a January, 1999, notice
to operators. This rule incorporates the requirements outlined in the notice.
Finally, the Commission amends the language in subsections (e), (f), and
(g) to clarify the placement and minimum length for plugs required with respect
to usable quality water strata.
The Commission received 17 comments, two of which were from the following
groups or associations: The Texas Oil and Gas Association (TXOGA) and the
Texas Independent Producers and Royalty Owners Association (TIPRO), and two
of which were from State Representatives Tommy Merritt (District 7) and Chuck
Hopson (District 11).
TXOGA and other commenters expressed general support for the intent of
the Commission to ensure fresh water protection by proper plugging methods
for groundwater isolation and fluid level tests; the amendments clarifying
the operator's responsibility for plugging; the process for transferring well
bore responsibility to the surface owner; and, the authorization of alternate
plugging materials. TIPRO expressed opposition to the part of the amendment
because of concern that the amended rule would leave certain strata of usable
quality water unprotected.
One commenter requested that the Commission not change this rule. Another
commenter expressed concern that the Commission is weakening the current well
plugging and abandonment requirements by amending the cement plugging requirements
for abandoned oil and gas wells, and expressed concern about disposal wells
in areas where there may be improperly plugged oil and gas wells. The Commission
recognizes the risk posed by improperly plugged wells, but disagrees with
these comments. First, the adopted changes are not intended to and in fact
do not weaken standards currently in effect for the protection of usable quality
subsurface water. Second, the substantive (as opposed to procedural and clarifying)
changes are adopted to implement the requirements of amended Natural Resources
Code §89.011, not to weaken the rule. Third, amendments concerning the
use of alternative plugging materials provide that such materials will not
be allowed unless the operator demonstrates that the alternative materials
will effectively protect subsurface water. Finally, applications for disposal
wells require an area of review to identify improperly plugged wells.
One commenter requested that the amendments include language to ensure
that the wells plugged back for conversion to water wells be included in the
State of Texas water well database by requiring notice (in the form of Commission
Form P-13) to be sent to the Texas Department of Licensing and Regulation
(TDLR), which licenses water well drillers, before the permit is accepted
by the RRC. The Commission agrees that plugged wells to be converted to water
wells should not be excluded from the water well database and that Form P-13
could be modified for integration into the TDLR process. The Commission is
not inclined to make such notice a prerequisite for approval of the Form P-13;
however, the Commission will provide this notice to the person at the Texas
Water Development Board who maintains TDLR water well database.
Several commenters, including TXOGA, stated that the language in subsection
(d)(12) has created confusion, resulting in unnecessary expenditures for operators
and the potential for very large future liabilities with no apparent benefits.
The Commission agrees that the particular sentence, "Within the same 120 day
period, the operator shall remove all such tanks, vessels, related surface
piping, and all subsurface piping that is less than three feet beneath the
ground surface, remove all loose junk and trash from the location, and contour
the location to discourage pooling of surface water at or around the facility
site," has been the source of confusion because it may be read to require
operators to remove all piping, including flow lines. The adopted change to
subsection (d)(12) removes this source of confusion by using the term "related
piping" when stating what the operator must remove. The adopted rule defines
"related piping" to exclude flowlines, gathering lines, and injection lines
that lead up to and away from any collection or treatment facilities covered
by the rule.
Several commenters expressed concern about the amendments not requiring
a cement plug from 50 feet above the uppermost fresh water sand to 50 feet
below the lowest freshwater sand (i.e. across the entire fresh water strata).
They urge the Commission not to change the rule to require anything less than
it has previously required. The Commission disagrees with this comment because
it is not consistent with how the Commission has applied the current requirements
of §3.14(e). The current rule and the adopted amendments provide that
both the base of the deepest usable quality water stratum and all other usable
quality water strata be protected. The adopted language clarifies this requirement.
The Commission recognizes that the current language in subsection (e) states
that "a cement plug shall be placed from 50 feet below the base of the deepest
usable quality water stratum to 50 feet above the top of the stratum," leading
people to believe the rule required a plug for the entire width of the stratum.
The Commission has never interpreted the rule to impose such a requirement,
nor is such requirement necessary to protect fresh water. The Commission has
applied the language in current subsection (e) to require a plug 50 feet below
and above the base of the deepest freshwater stratum, and 50 feet below and
above all separate usable quality water strata as identified by TCEQ and its
predecessor agencies. The adopted amendment more clearly tracks the Commission's
application and interpretation of the current language and maintains requirements
that protect usable quality water. Generally, usable quality water intervals
occur above saltwater or hydrocarbon bearing strata, and risk to usable quality
water is posed by upward migration of saltwater or hydrocarbons or both. Thus,
the rule requires that the base of deepest usable quality water strata be
protected, and when additional usable quality water strata are identified,
the amendments make clear the existing requirement that plugs shall be set
as necessary to separate these strata.
Some commenters suggested that operators, pluggers, and cementers, not
the RRC and/or Texas taxpayers, should be held liable for the proper plugging
of wells, even if they plugged wells years and/or decades ago. The Commission
holds operators and cementers responsible for proper plugging pursuant to §3.14(d)(1).
The Commission holds operators and cementers liable for the proper plugging
of wells and either or both are accountable to the Commission for complying
with the regulations in place at the time a particular well was plugged.
One commenter stated that the addition of the language to allow the TCEQ
the ability to require a plug between separate multiple usable quality water
strata is an unauthorized delegation to TCEQ. The Commission disagrees that
the amendments unlawfully delegate authority to TCEQ. TCEQ is the state agency
responsible for identifying separate usable quality water strata. The Commission
has always interpreted §3.14(e)(2) to require a plug between separate
usable quality water strata. The Commission has historically relied on the
TCEQ and its predecessor agencies, which are and have been responsible for
maintaining information concerning the location of usable water quality strata.
This reliance is reflected in the current version of §3.14. The information
from TCEQ, commonly known as the "Water Board letter," tells the responsible
operator/plugger and the Commission where usable quality water is present
in the well bore, and thus is necessary for the Commission to evaluate and
approve a proposed plugging plan.
One commenter stated that requiring the isolation of separate multiple
usable quality water strata will add significant cost to the plugging procedure.
The Commission disagrees because the adopted rule language does not change
Commission practice in this regard.
One commenter stated that verification of the placement of a plug by tagging
will cost $3,000 per plug just in rig time. The Commission disagrees. The
verification of the placement of the plug by tagging may add some cost to
a plugging operation, but typically not $3,000. The proper procedure for tagging
plugs is to first spot/pump the cement plug at the required depth, raise the
tubing or workstring, and shut down for a minimum of four hours to allow the
cement to set up. After four hours the tubing is lowered to tag and verify
the top of the cement. Four hours of rig time at a relatively high $250 per
hour equals a potential cost of $1,000. Furthermore, current §3.14(e)
requires open hole plugs to be evidenced by tagging with tubing or drill pipe.
The tagging requirement for all plugs at the base of the deepest usable quality
water is a specific provision in SB 310.
One commenter stated that there is no reasoned justification or statutory
authority for separation of multiple usable quality water strata occurring
above the base of the deepest "fresh water zone required to be protected"
by the placement of plugs between the multiple usable quality water strata.
The Commission disagrees. First, the practice of protecting multiple usable
quality water strata is not new. Second, by statute, the Commission is responsible
for protecting all subsurface water.
The commenter asserts that there is no analysis of the cost of this proposed
requirement on small business operators as required by Texas Government Code, §2006.001,
The Commission disagrees with these comments. The separation of multiple
usable quality water stratum occurring above the base of the deepest "fresh
water stratum required to be protected" by the placement of plugs between
the multiple usable quality water strata is consistent with current and longstanding
Commission practice. There is no need for analysis of the cost of this proposed
requirement on small business operators as required by Texas Government Code, §2006.001,
One commenter urges that the RRC's conclusion that "the RRC does not believe
the amendments will result in any additional cost" is totally unfounded. The
commenter states that evaluation of proposed §3.14(d)(2), (e)(4), (f)(3),
(g)(4) and (i)(1) and (2) discloses the distinct possibility of adding significant
cost to an operator. The Commission disagrees because all of the referenced
amendments are clarifications of existing requirements.
One commenter stated that if the RRC complies with its own rules, and if
the proposed amendments are adopted, the added cost to plug separate usable
quality water strata will reduce funds available from the Oil Field Cleanup
Fund to plug wells, with no additional benefits to the public. The Commission
disagrees. As stated above, §3.14 currently requires plugs for both the
deepest usable quality water strata and separate usable quality water stratum
where identified by TCEQ.
One commenter states that the potential perforation of intermediate casing
to place plugs separating multiple usable quality water stratum from each
other will jeopardize the integrity of the pipe, cause extraordinary additional
costs of at least $2,000 to $4,000 or more per required plug, and will not
increase protection of usable quality water stratum above the base of the
deepest usable quality water. The Commission disagrees. The perforating and
squeezing of cement plugs behind casing strings is a common oilfield practice
designed to ensure that all annuli are effectively sealed to prevent the migration
of wellbore fluids behind casing strings and into strata of usable quality
water. However, §3.13, relating to Casing, Cementing, Drilling and Completion
Requirements, requires that surface casing be cemented to the surface and,
therefore, should not require perforating for plugging purposes. If cement
does not exist behind the casing opposite usable quality water strata, providing
a conduit by which usable quality water could be contaminated, an operator
must perforate and attempt to pump cement behind the casing to eliminate the
threat of contamination. The adopted rule does not impose any new requirements
or financial obligations in this regard.
One commenter believes that "subpart (2)" appears to unnecessarily require
that tubing or drill pipe be cemented in the hole. Moreover, the phrase "plus
10% for each 1,000 feet" is ambiguous. The commenter urges that the proposed
amendment may require a very costly operation that adds nothing to the protection
of usable quality water strata or protection of the producing horizons, and
objects to §3.14(a)(4) permitting a landowner to take over a well without
the landowner being required to qualify for one of the required financial
or alternative forms of financial security found in Texas Natural Resources
Code, §91.104. The commenter states that the operator may remain liable
for plugging even though the landowner assumes responsibility for the well
as a water well.
The Commission is not clear to which "subpart (2)" the commenter is referring.
However, the Commission points out that the phrase "10% for each 1,000 feet"
has been a part of §3.14 for years and was not changed by these amendments.
The Commission disagrees with the comment that it is improper for a landowner
to take over a well without the landowner being required to qualify for one
of the required financial or alternative forms of financial security found
in Texas Natural Resource Code §91.104. Senate Bill 310 did not address
financial security requirements for converted oil and gas wells.
TXOGA and other commenters state that with respect to the definition of
Individual Well Bond, this term should be deleted completely from the rule
because it is not used. The Commission agrees to consider deleting the definition
of "Individual Well Bond" from this rule in the future, but points out that
such deletion was not part of the proposal. Because the public would not have
an opportunity to comment on such deletion, the Commission has determined
not to make it part of this rulemaking.
TIPRO, Rep. Hopson and Rep. Merritt opposed changes to subsection (e)(1)
that would allow wells with insufficient surface casing to be plugged to only
50 feet above the base of the deepest usable quality water, and asserted that
if this is the only requirement then subsurface water is at risk. The Commission
disagrees that placement of a plug 50 feet above and below the deepest usable
quality water is the only requirement. The adopted amendments do not change
the requirement that in addition to the plug required for the deepest usable
quality water depth, plugs shall be set as necessary to separate multiple
usable quality water strata by placing a plug at each depth as determined
by the TCEQ. This provision is consistent with current practice that requires
a plug at each depth identified in the Water Board letter. The adopted rule
continues the Commission practice protecting all identified strata with a
plug 50 feet above and 50 feet below the identified depth. In addition, provisions
in §3.14 (b)(7) allow the District office to require more protection
where the circumstances warrant such protection.
Commission District staff had an opportunity to visit with Rep. Merritt,
and after he was given explanation from the above paragraph, he advised the
Commission that he agrees with the proposed amendments.
TXOGA expressed appreciation for the opportunity in subsection (d)(4) to
use alternate plugging materials other than cement, but requests that the
Commission delegate to the districts the authority to approve alternate materials.
The Commission disagrees that the use of alternate plugging material may be
approved by the district director. The adopted amendment requires the Oil
and Gas Division Director or the Director's delegate to issue such approvals
because the Commission believes this type of decision warrants consistency
of application to avoid the possibility of different districts imposing different
standards. Once a new method is approved, it will become available to the
Districts.
The United States Environmental Protection Agency Region Six (EPA) commented
that because the Commission's underground injection control program under
the federal Safe Drinking Water Act requires that all Class II wells be plugged
upon abandonment in accordance with Rule 14, the EPA views the proposed amendments
to Rule 14 as a modification to the Texas Class II UIC program. EPA commented
that, in the absence of a statement of criteria by which alternate plugging
materials would be allowed under the rule, EPA would consider the amendments
of such scope as to require a program revision submission.
The Commission disagrees. The amendments to Rule 14 provide a mechanism
only for approval of alternative plugging materials. As proposed, requests
for approval of alternative plugging materials will be reviewed on a case-by-case
basis by executive staff in the Austin Headquarters. Further, such requests
will be approved only if the Commission is sure that the alternative plugging
materials will afford equal protection of usable quality water. Factors the
Commission will consider in making a decision on whether or not to approve
such a request will include but will not be limited to whether or not a well
to be plugged using an alternative method was used as an injection or disposal
well; the well's history; the well's current bottom hole pressure; the presence
of highly pressurized formations intersected by the wellbore; the method by
which the alternative material will be placed in the wellbore; and the compressive
strength and other critical properties of the alternative material to be used.
Although it would be preferable to identify an exclusive list of circumstances
under which Commission staff would approve requests to use alternative plugging
materials, the extreme variety of interplaying factors to be considered make
it impractical to do so. The Commission has added clarifying language to the
text of subsection (d)(4) to explain the process by which approval of alternative
plugging materials may be gained.
TXOGA and other commenters request clarification as to the need to place
9.5 pounds per gallon, 40 viscosity fluid in all portions of the well not
filled with cement or other alternate material. They recognize that these
fluid properties have been a requirement for many years but observe that there
seems to be no sound basis for a prescriptive mud property to be used in every
well to be plugged in the state of Texas.
The Commission agrees alternative mud can be allowed in certain circumstances
and the adopted rule makes that change in subsection (d)(9).
TXOGA also disagrees with the Commission's requirement to restrict volume
extenders from cement used for plugging. They state that operators currently
encounter difficulties in plugging depleted strata with Commission recommended
neat cement slurries. They aver that current cementing technology has advanced
compressive strengths and yields for lightweight extended cements to equal
or surpass those strengths of neat cements, and request that the Commission
allow operators the option to use the current techniques and cements to properly
isolate formations in an economical and efficient manner.
The Commission agrees with this comment in part and has made changes to
subsection (d)(4) to allow an operator to request approval to use alternate
materials other than API oil well cement without volume extenders to plug
a well.
TXOGA and other commenters object to the proposed change in the definition
of "notice" in subsection (a)(1)(L), and the use of the term "landowner" there
and in subsection (a)(4) and (5). They declare that the current definition
of notice is consistent with accepted industry practice to provide notice
to either the surface owner or the lawful resident if the surface owner is
absent; paragraph (5) currently reflects this common-sense approach. They
recommend that paragraphs (1) and (5) remain unchanged, and that the phrase
"surface owner or resident" be substituted for "landowner" in paragraph (4).
The Commission agrees to substitute the term "surface owner" for "landowner"
and to continue the practice of allowing notice to the resident or occupant
of a property if the owner is absent. The Commission has changed the proposed
language in response to this comment because the Commission agrees that the
term "surface owner" is the commonly accepted legal term for the person who
owns surface rights and the Commission does not intend this rulemaking to
change the notification standard.
TXOGA and other commenters point out that references to specific Commission
titles such as "the deputy director of field operations" may cause confusion
in the future. They suggest that the rule not specify a specific organization
title and instead substitute the phrase director or the director's delegate.
The Commission agrees with this comment and has substituted the term "Director
or the Director's delegate" in those parts of the rule where the Austin office
is responsible for the decision, and the term "District Director or the District
Director's delegate" where the district office is responsible for the decision.
For consistency, the Commission has also changed the term "Commission or its
delegate" to refer to the appropriate director instead.
TXOGA and other commenters state that in subsection (b)(2)(E) operators
are required to submit Mechanical Integrity Test results to the district office
and fluid level tests results to Austin. They observe that this is further
complicated by the requirement that hydraulic pressure tests that are not
witnessed by the district office must be submitted to Austin for review and
acceptance, and declare that these requirements have long been a difficult
problem for industry and the district offices. TXOGA and other commenters
strongly recommend that the district offices be given jurisdiction over all
MIT, fluid level, and hydraulic pressure tests.
The Commission disagrees with this comment, primarily because of resource
allocation limits. Fluid level test results are evaluated by a database calculation
and the district offices are not set up to accomplish the data entry as efficiently
as the Austin office. The Commission can accomplish this part of the process
in Austin with fewer employees than it would take in each district. The automated
process provides initial test results, and when the test results are clear,
there is no need for further Commission involvement. This resolves a majority
of the test issues. When the test results are unclear, the district will get
involved. The Commission finds that its current process is the most effective
use of limited Commission resources.
TXOGA states that proposed §3.14(b)(2)(A)(i)(V) and (b)(2)(E)(i) seem
to have a conflicting use of the terms paragraph and subparagraph and probably
should both be the same.
The Commission disagrees there are conflicting uses of the terms paragraph
and subparagraph. The reference in §3.14(b)(2)(A)(i)(V) is to subparagraph
(E) of paragraph (2) of subsection (b); the reference in (b)(2)(E)(i) is to
subparagraph (E) which concerns testing.
TXOGA comments that §3.14(a)(3), should specifically refer to the
Commission approved forms W-3A (Notice of Intent To Plug and Abandon), W-3
(Plugging Record) and W-15 (Cementing Report) where applicable to assist operators
in the proper filing procedure. They support the Commission's language in
this section to remind operators that the approval of intent to plug does
not relieve an operator of the requirement to plug wells in a timely manner,
nor does the approval extend permission to plug wells.
The Commission declines to specifically refer to the Commission approved
forms W-3A (Notice of Intent To Plug and Abandon), W-3 (Plugging Record) and
W-15 (Cementing Report) in §3.14(a)(3) because such addition was not
noticed as a part of this rulemaking. The Commission will consider such references
in future rulemakings.
One commenter recommends that the Commission add the following language
to §3.14 as new subsection (l): "The Commission recognizes the improvement
to a rule may come through its application. Where an operator can prove through
the hearings process that a more economic or safer method to plugging can
be applied that is not in Rule 14, then the hearing officer upon good cause
has the discretion to recommend a modification of any specific plugging requirement
or detail in this rule." The Commission declines to adopt the suggested change
because the proposal unnecessarily adds a layer of legal process to the rule
and is outside the scope of the notice given in this rulemaking. In this rulemaking,
the Commission creates additional flexibility with provisions allowing administrative
approval of certain requirements in the rule. If the Commission denies approval
under these new provisions or denies some other request for a variance, the
operator always has an opportunity for a hearing. Furthermore, if, as experience
accumulates, the Commission determines it should change the rule, it can propose
amendments. If an affected party wants to change the rule, it can petition
the Commission for a rulemaking.
One commenter asked that the amendments add a provision to subsection (d)(12)
stating that the surface shall receive remediation in accordance with §3.91.
The commenter also asked that the amendments add a provision allowing a landowner
to recover costs incurred in bringing a violation of §3.14 to the Commission's
attention. The Commission declines to add these provisions because they were
not noticed for this rulemaking. No one who might be against adding these
provisions had an opportunity to comment on them.
The Commission adopts amendments to §3.14 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 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, §85.202(a) and §91.101(a)(3),
which require the Commission to adopt rules requiring the proper plugging
of wells, preventing injury to adjoining property, preventing pollution of
surface and subsurface water, and confining oil, gas, and water to the strata
in which they are found; and §89.011, which requires an operator to verify
the placement of a plug at the base of the deepest freshwater strata required
to be protected.
Statutory authority: Texas Natural Resources Code, §§81.051,
81.052, 85.202(a)(2), 85.2021(c), 89.011, 91.101(3), and 91.103 - 91.107.
Cross-reference to statute: Texas Natural Resources Code, Chapters 81,
85, 89, and 91.
Issued in Austin, Texas, on July 8, 2003.
§3.14.Plugging.
(a)
Definitions and application to plug.
(1)
The following words and terms, when used in this section,
shall have the following meanings, unless the context clearly indicates otherwise:
(A)
Active operation--Regular and continuing activities related
to the production of oil and gas for which the operator has all necessary
permits. In the case of a well that has been inactive for 12 consecutive months
or longer and that is not permitted as a disposal or injection well, the well
remains inactive for purposes of this section, regardless of any minimal activity,
until the well has reported production of at least 10 barrels of oil for oil
wells or 100 mcf of gas for gas wells each month for at least three consecutive
months.
(B)
Approved cementer--A cementing company, service company,
or operator approved by the Commission to mix and pump cement for the purpose
of plugging a well in accordance with the provisions of this section. The
term shall also apply to a cementing company, service company, or operator
authorized by the Commission to use an alternate material other than cement
to plug a well.
(C)
Delinquent inactive well--An unplugged well that has had
no reported production, disposal, injection, or other permitted activity for
a period of greater than 12 months and for which, after notice and opportunity
for hearing, the Commission has not extended the plugging deadline.
(D)
Funnel viscosity--Viscosity as measured by the Marsh funnel,
based on the number of seconds required for 1,000 cubic centimeters of fluid
to flow through the funnel.
(E)
Good faith claim--A factually supported claim based on
a recognized legal theory to a continuing possessory right in a mineral estate,
such as evidence of a currently valid oil and gas lease or a recorded deed
conveying a fee interest in the mineral estate.
(F)
Groundwater conservation district--Any district or authority
created under §52, Article III, or §59, Article XVI, Texas Constitution,
that has the authority to regulate the spacing of water wells, the production
from water wells, or both.
(G)
Individual well bond--A bond or letter of credit issued:
(i)
on a Commission-approved form;
(ii)
by a third party surety, insurance company, or financial
institution approved by the Commission; and
(iii)
to secure the timely and proper plugging of a specified
well and remediation of the wellsite in accordance with Commission rules.
(H)
Operator designation form--A certificate of transportation
authority and compliance or an application to drill, deepen, recomplete, plug
back, or reenter which has been completed, signed and filed with the Commission.
(I)
Productive horizon--Any stratum known to contain oil, gas,
or geothermal resources in producible quantities in the vicinity of an unplugged
well.
(J)
Related piping--The surface piping and subsurface piping
that is less than three feet beneath the ground surface between pieces of
equipment located at any collection or treatment facility. Such piping would
include piping between and among headers, manifolds, separators, storage tanks,
gun barrels, heater treaters, dehydrators, and any other equipment located
at a collection or treatment facility. The term is not intended to refer to
lines, such as flowlines, gathering lines, and injection lines that lead up
to and away from any such collection or treatment facility.
(K)
Reported production--Production of oil or gas, excluding
production attributable to well tests, accurately reported to the Commission
on a monthly producer's report.
(L)
To serve notice on the surface owner or resident--To hand
deliver a written notice identifying the well or wells to be plugged and the
projected date the well or wells will be plugged to the surface owner or resident
if the owner is absent at least three days prior to the day of plugging or
to mail the notice by first class mail, postage pre-paid, to the last known
address of the surface owner or resident at least seven days prior to the
day of plugging.
(M)
Unbonded operator--An operator that has a current and active
organization report on file with the Commission but that does not have a current
individual performance bond, blanket performance bond, letter of credit, or
cash deposit as its financial security under §3.78 of this title (relating
to Fees, Performance Bonds, and Alternate Forms of Financial Security Required
to be Filed (Statewide Rule 78).
(N)
Usable quality water strata--All strata determined by the
Texas Commission on Environmental Quality or its successor agencies to contain
usable quality water.
(O)
Written notice--Notice actually received by the intended
recipient in tangible or retrievable form, including notice set out on paper
and hand-delivered, facsimile transmissions, and electronic mail transmissions.
(2)
The operator shall give the Commission notice of its intention
to plug any well or wells drilled for oil, gas, or geothermal resources or
for any other purpose over which the Commission has jurisdiction, except those
specifically addressed in §3.100(f)(1) of this title (relating to Seismic
Holes and Core Holes) (Statewide Rule 100), prior to plugging. The operator
shall deliver or transmit the written notice to the district office on the
appropriate form.
(3)
The operator shall cause the notice of its intention to
plug to be delivered to the district office at least five days prior to the
beginning of plugging operations. The notice shall set out the proposed plugging
procedure as well as the complete casing record. The operator shall not commence
the work of plugging the well or wells until the proposed procedure has been
approved by the district director or the director's delegate. The operator
shall not initiate approved plugging operations before the date set out in
the notification for the beginning of plugging operations unless authorized
by the district director or the director's delegate. The operator shall notify
the district office at least four hours before commencing plugging operations
and proceed with the work as approved. The district director or the director's
delegate may grant exceptions to the requirements of this paragraph concerning
the timing of notices when a workover or drilling rig is already at work on
location, and ready to commence plugging operations. Operations shall not
be suspended prior to plugging the well unless the hole is cased and casing
is cemented in place in compliance with Commission rules. The Commission's
approval of a notice of intent to plug and abandon a well shall not relieve
an operator of the requirement to comply with subsection (b)(2) of this section,
nor does such approval constitute an extension of time to comply with subsection
(b)(2) of this section.
(4)
The surface owner and the operator may file an application
to condition an abandoned well located on the surface owner's tract for usable
quality water production operations. The application shall be made on the
form prescribed by the Commission, the Application of Landowner to Condition
an Abandoned Well for Fresh Water Production.
(A)
Standard for Commission Approval. Before the Commission
will consider approval of an application:
(i)
the surface owner shall assume responsibility for plugging
the well and obligate himself, his heirs, successors, and assignees to complete
the plugging operations;
(ii)
the operator responsible for plugging the well shall place
all cement plugs required by this rule up to the base of the usable quality
water strata; and
(iii)
the surface owner shall submit:
(I)
a signed statement attesting to the fact that:
(-a-)
there is no groundwater conservation district for the
area in which the well is located; or
(-b-)
there is a groundwater conservation district for the
area where the well is located, but the groundwater conservation district
does not require that the well be permitted or registered; or
(-c-)
the surface owner has registered the well with the groundwater
conservation district for the area where the well is located; or
(II)
a copy of the permit from the groundwater conservation
district for the area where the well is located.
(B)
The duty of the operator to properly plug ends only when:
(i)
the operator has properly plugged the well in accordance
with Commission requirements up to the base of the usable quality water stratum;
(ii)
the surface owner has registered the well with, or has
obtained a permit for the well from, the groundwater conservation district,
if applicable; and
(iii)
the Commission has approved the application of surface
owner to condition an abandoned well for fresh water production.
(5)
The operator of a well shall serve notice on the surface
owner of the well site tract, or the resident if the owner is absent, before
the scheduled date for beginning the plugging operations. A representative
of the surface owner may be present to witness the plugging of the well. Plugging
shall not be delayed because of the lack of actual notice to the surface owner
or resident if the operator has served notice as required by this paragraph.
The district director or the director's delegate may grant exceptions to the
requirements of this paragraph concerning the timing of notices when a workover
or drilling rig is already at work on location and ready to commence plugging
operations.
(b)
Commencement of plugging operations and extensions.
(1)
The operator shall complete and file in the district office
a duly verified plugging record, in duplicate, on the appropriate form within
30 days after plugging operations are completed. A cementing report made by
the party cementing the well shall be attached to, or made a part of, the
plugging report. If the well the operator is plugging is a dry hole, an electric
log status report shall be filed with the plugging record.
(2)
Plugging operations on each dry or inactive well shall
be commenced within a period of one year after drilling or operations cease
and shall proceed with due diligence until completed. Plugging operations
on delinquent inactive wells shall be commenced immediately unless the well
is restored to active operation. For good cause, a reasonable extension of
time in which to start the plugging operations may be granted pursuant to
the following procedures.
(A)
Wells that have been inactive for less than 36 months.
(i)
The Commission or its delegate may administratively grant
an extension of up to one year of the deadline for plugging a well that is
operated by an unbonded operator and has been inactive, without a return to
active operation, for a period of less than 36 months if the following criteria
are met:
(I)
The well and associated facilities are in compliance with
all other laws and Commission rules;
(II)
The operator's organization report is current and active;
(III)
The operator has, and upon request provides evidence
of, a good faith claim to a continuing right to operate the well;
(IV)
The operator has paid the proper fee as provided in §3.78
of this title (relating to Fees, Performance Bonds, and Alternative Forms
of Financial Security Required To Be Filed) (Statewide Rule 78);
(V)
The operator has tested the well in accordance with the
provisions of subparagraph (E) of this paragraph and files with its application
proof of either:
(-a-)
a fluid level test conducted within 90 days prior to
the application for a plugging extension demonstrating that any fluid in the
wellbore is at least 250 feet below the base of the deepest usable quality
water strata; or,
(-b-)
a hydraulic pressure test conducted during the period
the well has been inactive demonstrating the mechanical integrity of the well;
and,
(VI)
The requested plugging extension will not extend beyond
the thirty-sixth month of inactivity.
(ii)
A plugging extension granted under this subparagraph may
not extend the period of inactivity beyond 36 months.
(B)
Wells that have been inactive for 36 months or longer.
(i)
The Commission or its delegate may administratively grant
an extension of up to one year of the deadline for plugging a well that is
operated by an unbonded operator and has been inactive, without a return to
active operation, for a period of 36 months or longer if the criteria set
out in subclauses (I)-(IV) of subsection (b)(2)(A)(i) of this section are
met, and, in addition:
(I)
The operator has tested the well in accordance with the
provisions of subparagraph (E) of this paragraph and files with its application
proof of either:
(-a-)
a fluid level test conducted within 90 days prior to
the application for a plugging extension demonstrating that any fluid in the
wellbore is at least 250 feet below the base of the deepest usable quality
water strata, or,
(-b-)
a hydraulic pressure test conducted during the period
the well has been inactive and not more than four years prior to the date
of application demonstrating the mechanical integrity of the well; and,
(II)
The operator files an individual well bond in the amount
provided for in §3.78(m) of this title (relating to Fees, Performance
Bonds, and Alternative Forms of Financial Security Required To Be Filed) (Statewide
Rule 78).
(ii)
An operator may rebut the presumed estimated plugging
costs for a specific well for which a plugging extension is sought at hearing
by clear and convincing evidence establishing a higher or lower prospective
plugging cost for the well. The operator, Commission staff, or any owner of
the surface or mineral estate on which the well is located may initiate a
hearing on the prospective plugging cost for a well for the purpose of setting
the amount of an individual well bond by filing a request for hearing.
(C)
Plugging of inactive wells operated by bonded operators.
An operator that maintains valid, Commission-approved financial security in
the form of an individual performance bond, blanket performance bond, letter
of credit, or cash deposit as provided in §3.78 of this title (relating
to Fees, Performance Bonds, and Alternate Forms of Financial Security Required
to be Filed) (Statewide Rule 78) will be granted a one-year plugging extension
for each well it operates that has been inactive for 12 months or more at
the time its annual organizational report is approved by the Commission if
the following criteria are met:
(i)
The well and associated facilities are in compliance with
all laws and Commission rules; and,
(ii)
The operator has, and upon request provides evidence of,
a good faith claim to a continuing right to operate the well.
(D)
Revocation or denial of plugging extension.
(i)
The Commission or its delegate may revoke a plugging extension
if the operator of the well that is the subject of the extension fails to
maintain the well and all associated facilities in compliance with Commission
rules; fails to maintain a current and accurate organizational report on file
with the Commission; fails to provide the Commission, upon request, with evidence
of a continuing good faith claim to operate the well; or fails to obtain or
maintain a valid individual well bond or organizational bond or letter of
credit as required by this subsection.
(ii)
If the Commission or its delegate declines to grant or
continue a plugging extension or revokes a previously granted extension, the
operator shall either return the well to active operation or, within 30 days,
plug the well or request a hearing on the matter.
(E)
The operator of any well more than 25 years old that becomes
inactive and subject to the provisions of this paragraph or the operator of
any well for which a plugging extension is sought under the terms of subparagraph
(A) or (B) of this paragraph shall plug or test such well to determine whether
the well poses a potential threat of harm to natural resources, including
surface and subsurface water, oil and gas.
(i)
In general, a fluid level test is a sufficient test for
purposes of this subparagraph. The operator shall give the district office
written notice specifying the date and approximate time it intends to conduct
the fluid level test at least 48 hours prior to conducting the test; however,
upon a showing of undue hardship, the district director or the director's
delegate may grant a written waiver or reduction of the notice requirement
for a specific well test. The director or the director's delegate may require
alternate methods of testing if necessary to ensure the well does not pose
a potential threat of harm to natural resources. Alternate methods of testing
may be approved by the director or the director's delegate by written application
and upon a showing that such a test will provide information sufficient to
determine that the well does not pose a threat to natural resources.
(ii)
No test other than a fluid level test shall be acceptable
without prior approval from the district director or the director's delegate.
The district director or the director's delegate shall be notified at least
48 hours before any test other than a fluid level test is conducted. Mechanical
integrity test results shall be filed with the district office and fluid level
test results shall be filed with the Commission in Austin. Test results shall
be filed on a Commission-approved form, within 30 days of the completion of
the test. Upon request, the operator shall file the actual test data for any
mechanical integrity or fluid level test that it has conducted.
(iii)
Notwithstanding the provisions of clause (ii) of this
subparagraph, a hydraulic pressure test may be conducted without prior approval
from the district director or the director's delegate, provided that the operator
gives the district office written notice specifying the date and approximate
time for the test at least 48 hours prior to the time the test will be conducted,
the production casing is tested to a depth of at least 250 feet below the
base of usable quality water strata, or 100 feet below the top of cement behind
the production casing, whichever is deeper, and the minimum test pressure
is greater than or equal to 250 psig for a period of at least 30 minutes.
(iv)
If the operator performs a hydraulic pressure test in
accordance with the provisions of clause (iii) of this subparagraph, the well
shall be exempt from further testing for five years from the date of the test,
except to the extent compliance with paragraph (2) of subsection (b) of this
section requires more frequent testing. Further, the Commission or its delegate
may require the operator to perform testing more frequently to ensure that
the well does not pose a threat of harm to natural resources. The Commission
or its delegate may approve less frequent well tests under this subparagraph
upon written request and for good cause shown provided that less frequent
testing will not increase the threat of harm to natural resources.
(v)
Wells that are returned to continuous production, as evidenced
by three consecutive months of reported production of at least 10 barrels
of oil or 100 mcf of gas per month, need not be tested.
(3)
Transfer of operatorship. A transfer of operatorship submitted
for any well or lease will not be approved unless the operator acquiring the
well or lease has on file with the Commission financial security as provided
in §3.78 of this title (relating to Fees, Performance Bonds, and Alternate
Forms of Financial Security Required to be Filed) (Statewide Rule 78).
(4)
The Commission may plug or replug any dry or inactive well
as follows:
(A)
After notice and hearing, if the well is causing or is
likely to cause the pollution of surface or subsurface water or if oil, gas,
or other formation fluid is leaking from the well, and:
(i)
Neither the operator nor any other entity responsible for
plugging the well can be found; or
(ii)
Neither the operator nor any other entity responsible
for plugging the well has assets with which to plug the well.
(B)
Without a hearing if the well is a delinquent inactive
well and:
(i)
the Commission has sent notice of its intention to plug
the well as required by §89.043(c) of the Texas Natural Resources Code;
and
(ii)
the operator did not request a hearing within the period
(not less than 10 days after receipt) specified in the notice.
(C)
Without notice or hearing, if:
(i)
The Commission has issued a final order requiring that
the operator plug the well and the order has not been complied with; or
(ii)
The well poses an immediate threat of pollution of surface
or subsurface waters or of injury to the public health and the operator has
failed to timely remediate the problem.
(5)
The Commission may seek reimbursement from the operator
and any other entity responsible for plugging the well for state funds expended
pursuant to paragraph (4) of this subsection.
(c)
Designated operator responsible for proper plugging.
(1)
The entity designated as the operator of a well specifically
identified on the most recent Commission-approved operator designation form
filed on or after September 1, 1997, is responsible for properly plugging
the well in accordance with this section and all other applicable Commission
rules and regulations concerning plugging of wells.
(2)
As to any well for which the most recent Commission-approved
operator designation form was filed prior to September 1, 1997, the entity
designated as operator on that form is presumed to be the entity responsible
for the physical operation and control of the well and to be the entity responsible
for properly plugging the well in accordance with this section and all other
applicable Commission rules and regulations concerning plugging of wells.
The presumption of responsibility may be rebutted only at a hearing called
for the purpose of determining plugging responsibility.
(d)
General plugging requirements.
(1)
Wells shall be plugged to insure that all formations bearing
usable quality water, oil, gas, or geothermal resources are protected. All
cementing operations during plugging shall be performed under the direct supervision
of the operator or his authorized representative, who shall not be an employee
of the service or cementing company hired to plug the well. Direct supervision
means supervision at the well site during the plugging operations. The operator
and the cementer are both responsible for complying with the general plugging
requirements of this subsection and for plugging the well in conformity with
the procedure set forth in the approved notice of intention to plug and abandon
for the well being plugged. The operator and cementer may each be assessed
administrative penalties for failure to comply with the general plugging requirements
of this subsection or for failure to plug the well in conformity with the
approved notice of intention to plug and abandon the well.
(2)
Cement plugs shall be set to isolate each productive horizon
and usable quality water strata. Plugs shall be set as necessary to separate
multiple usable quality water strata by placing the required plug at each
depth as determined by the Texas Commission on Environmental Quality or its
successor agencies. The operator shall verify the placement of the plug required
at the base of the deepest usable quality water stratum by tagging with tubing
or drill pipe or by an alternate method approved by the district director
or the district director's delegate.
(3)
Cement plugs shall be placed by the circulation or squeeze
method through tubing or drill pipe. Cement plugs shall be placed by other
methods only upon written request with the written approval of the district
director or the director's delegate.
(4)
All cement for plugging shall be an approved API oil well
cement without volume extenders and shall be mixed in accordance with API
standards. Slurry weights shall be reported on the cementing report. The district
director or the director's delegate may require that specific cement compositions
be used in special situations; for example, when high temperature, salt section,
or highly corrosive sections are present. An operator shall request approval
to use alternate materials, other than API oil well cement without volume
extenders, to plug a well by filing with the director or the director's delegate
a written request providing all pertinent information to support the use of
the proposed alternate material and plugging method. The director or the director's
delegate shall determine whether such a request warrants approval, after considering
factors which include but are not limited to whether or not the well to be
plugged was used as an injection or disposal well; the well's history; the
well's current bottom hole pressure; the presence of highly pressurized formations
intersected by the wellbore; the method by which the alternative material
will be placed in the wellbore; and the compressive strength and other performance
specifications of the alternative material to be used. The director or the
director's delegate shall approve such a request only if the proposed alternate
material and plugging method will ensure that the well does not pose a potential
threat of harm to natural resources.
(5)
Operators shall use only cementers approved by the director
or the director's delegate, except when plugging is conducted in accordance
with subparagraph (B)(ii) of this paragraph or paragraph (6) of this subsection.
Cementing companies, service companies, or operators may apply for designation
as approved cementers. Approval will be granted on a showing by the applicant
of the ability to mix and pump cement or other alternate materials as approved
by the director or the director's delegate in compliance with this rule. An
approved cementer is authorized to conduct plugging operations in accordance
with Commission rules in each Commission district.
(A)
A cementing company, service company, or operator seeking
designation as an approved cementer shall file a request in writing with the
district director of the district in which it proposes to conduct its initial
plugging operations. The request shall contain the following information:
(i)
the name of the organization as shown on its most recent
approved organizational report;
(ii)
a list of qualifications including personnel who will
supervise mixing and pumping operations;
(iii)
length of time the organization has been in the business
of cementing oil and gas wells;
(iv)
an inventory of the type of equipment to be used to mix
and pump cement or other alternate materials as approved by the director or
the director's delegate; and
(v)
a statement certifying that the organization will comply
with all Commission rules.
(B)
No request for designation as an approved cementer will
be approved until after the district director or the director's delegate has:
(i)
inspected all equipment to be used for mixing and pumping
cement or other alternate materials as approved by the director or the director's
delegate; and
(ii)
witnessed at least one plugging operation to determine
if the cementing company, service company, or operator can properly mix and
pump cement or other alternate materials as approved by the director or the
director's delegate according to the specifications required by this rule.
(C)
The district director or the director's delegate shall
file a letter with the director or the director's delegate recommending that
the application to be designated as an approved cementer be approved or denied.
If the district director or the director's delegate does not recommend approval,
or the director or the director's delegate denies the application, the applicant
may request a hearing on its application.
(D)
Designation as an approved cementer may be suspended or
revoked for violations of Commission rules. The designation may be revoked
or suspended administratively by the director or the director's delegate for
violations of Commission rules if:
(i)
the cementer has been given written notice by personal
service or by registered or certified mail informing the cementer of the proposed
action, the facts or conduct alleged to warrant the proposed action, and of
its right to request a hearing within 10 days to demonstrate compliance with
Commission rules and all requirements for retention of designation as an approved
cementer; and
(ii)
the cementer did not file a written request for a hearing
within 10 days of receipt of the notice.
(6)
An operator may request administrative authority to plug
its own wells without being an approved cementer. An operator seeking such
authority shall file a written request with the district director and demonstrate
its ability to mix and pump cement or other alternate materials as approved
by the director or the director's delegate in compliance with this subsection.
The district director or the director's delegate shall determine whether such
a request warrants approval. If the district director or the director's delegate
refuses to administratively approve this request, the operator may request
a hearing on its request.
(7)
The district director or the director's delegate may require
additional cement plugs to cover and contain any productive horizon or to
separate any water stratum from any other water stratum if the water qualities
or hydrostatic pressures differ sufficiently to justify separation. The tagging
and/or pressure testing of any such plugs, or any other plugs, and respotting
may be required if necessary to ensure that the well does not pose a potential
threat of harm to natural resources.
(8)
For onshore or inland wells, a 10-foot cement plug shall
be placed in the top of the well, and casing shall be cut off three feet below
the ground surface.
(9)
Mud-laden fluid of at least 9-1/2 pounds per gallon with
a minimum funnel viscosity of 40 seconds shall be placed in all portions of
the well not filled with cement or other alternate material as approved by
the director or the director's delegate. The hole shall be in static condition
at the time the cement plugs are placed. The district director or the director's
delegate may grant exceptions to the requirements of this paragraph if a deviation
from the prescribed minimums for fluid weight or viscosity will insure that
the well does not pose a potential threat of harm to natural resources. An
operator shall request approval to use alternate fluid other than mud-laden
fluid by filing with the district director a written request providing all
pertinent information to support the use of the proposed alternate fluid.
The district director or the director's delegate shall determine whether such
a request warrants approval, and shall approve such a request only if the
proposed alternate fluid will insure that the well does not pose a potential
threat of harm to natural resources.
(10)
Non-drillable material that would hamper or prevent reentry
of a well shall not be placed in any wellbore during plugging operations,
except in the case of a well plugged and abandoned under the provisions of §3.35
or §4.614(b) of this title (relating to Procedures for Identification
and Control of Wellbores in Which Certain Logging Tools Have Been Abandoned
(Statewide Rule 35); and Authorized Disposal Methods, respectively). Pipe
and unretrievable junk shall not be cemented in the hole during plugging operations
without prior approval by the district director or the director's delegate.
(11)
All cement plugs, except the top plug, shall have sufficient
slurry volume to fill 100 feet of hole, plus 10% for each 1,000 feet of depth
from the ground surface to the bottom of the plug.
(12)
The operator shall fill the rathole, mouse hole, and cellar,
and shall empty all tanks, vessels, related piping and flowlines that will
not be actively used in the continuing operation of the lease within 120 days
after plugging work is completed. Within the same 120 day period, the operator
shall remove all such tanks, vessels, and related piping, remove all loose
junk and trash from the location, and contour the location to discourage pooling
of surface water at or around the facility site. The operator shall close
all pits in accordance with the provisions of §3.8 of this title (relating
to Water Protection (Statewide Rule 8)). The district director or the director's
delegate may grant a reasonable extension of time of not more than an additional
120 days for the removal of tanks, vessels and related piping.
(e)
Plugging requirements for wells with surface casing.
(1)
When insufficient surface casing is set to protect all
usable quality water strata and such usable quality water strata are exposed
to the wellbore when production or intermediate casing is pulled from the
well or as a result of such casing not being run, a cement plug shall be a
minimum of 100 feet in length and shall extend at least 50 feet above and
50 feet below the base of the deepest usable quality water stratum. This plug
shall be evidenced by tagging with tubing or drill pipe. The plug shall be
respotted if it has not been properly placed. In addition, a cement plug shall
be set across the shoe of the surface casing. This plug shall be a minimum
of 100 feet in length and shall extend at least 50 feet above and below the
shoe.
(2)
When sufficient surface casing has been set to protect
all usable quality water strata, a cement plug shall be placed across the
shoe of the surface casing. This plug shall be a minimum of 100 feet in length
and shall extend at least 50 feet above the shoe and at least 50 feet below
the shoe.
(3)
If surface casing has been set deeper than 200 feet below
the base of the deepest usable quality water stratum, an additional cement
plug shall be placed inside the surface casing across the base of the deepest
usable quality water stratum. This plug shall be a minimum of 100 feet in
length and shall extend at least 50 feet below and 50 feet above the base
of the deepest usable quality water stratum.
(4)
Plugs shall be set as necessary to separate multiple usable
quality water strata by placing the required plug at each depth as determined
by the Texas Commission on Environmental Quality or its successor agencies.
(f)
Plugging requirements for wells with intermediate casing.
(1)
For wells in which the intermediate casing has been cemented
through all usable quality water strata and all productive horizons, a cement
plug meeting the requirements of subsection (d)(11) of this section shall
be placed inside the casing and centered opposite the base of the deepest
usable quality water stratum, but extend no less than 50 feet above and below
the base of the deepest usable quality water stratum.
(2)
For wells in which intermediate casing is not cemented
through all usable quality water strata and all productive horizons, and if
the casing will not be pulled, the intermediate casing shall be perforated
at the required depths to place cement outside of the casing by squeeze cementing
through casing perforations.
(3)
Additionally, plugs shall be set as necessary to separate
multiple usable quality water strata by placing the required plug at each
depth as determined by the Texas Commission on Environmental Quality or its
successor agencies.
(g)
Plugging requirements for wells with production casing.
(1)
For wells in which the production casing has been cemented
through all usable quality water strata and all productive horizons, a cement
plug meeting the requirements of subsection (d)(11) of this section shall
be placed inside the casing and centered opposite the base of the deepest
usable quality water stratum and across any multi-stage cementing tool. This
plug shall be a minimum of 100 feet in length and shall extend at least 50
feet below and 50 feet above the base of the deepest usable quality water
stratum.
(2)
For wells in which the production casing has not been cemented
through all usable quality water strata and all productive horizons and if
the casing will not be pulled, the production casing shall be perforated at
the required depths to place cement outside of the casing by squeeze cementing
through casing perforations.
(3)
The district director or the director's delegate may approve
a cast iron bridge plug to be placed immediately above each perforated interval,
provided at least 20 feet of cement is placed on top of each bridge plug.
A bridge plug shall not be set in any well at a depth where the pressure or
temperature exceeds the ratings recommended by the bridge plug manufacturer.
(4)
Additionally, plugs shall be set as necessary to separate
multiple usable quality water strata by placing the required plug at each
depth as determined by the Texas Commission on Environmental Quality or its
successor agencies.
(h)
Plugging requirements for well with screen or liner.
(1)
If practical, the screen or liner shall be removed from
the well.
(2)
If the screen or liner is not removed, a cement plug in
accordance with subsection (d)(11) of this section shall be placed at the
top of the screen or liner.
(i)
Plugging requirements for wells without production casing
and open-hole completions.
(1)
Any productive horizon or any formation in which a pressure
or formation water problem is known to exist shall be isolated by cement plugs
centered at the top and bottom of the formation. Each cement plug shall have
sufficient slurry volume to fill a calculated height as specified in subsection
(d)(11) of this section.
(2)
If the gross thickness of any such formation is less than
100 feet, the tubing or drill pipe shall be suspended 50 feet below the base
of the formation. Sufficient slurry volume shall be pumped to fill the calculated
height from the bottom of the tubing or drill pipe up to a point at least
50 feet above the top of the formation, plus 10% for each 1,000 feet of depth
from the ground surface to the bottom of the plug.
(j)
The district director or the director's delegate shall
review and approve the notification of intention to plug in a manner so as
to accomplish the purposes of this section. The district director or the director's
delegate may approve, modify, or reject the operator's notification of intention
to plug. If the proposal is modified or rejected, the operator may request
a review by the director or the director's delegate. If the proposal is not
administratively approved, the operator may request a hearing on the matter.
After hearing, the examiner shall recommend final action by the Commission.
(k)
Plugging horizontal drainhole wells. All plugs in horizontal
drainhole wells shall be set in accordance with subsection (d)(11) of this
section. The productive horizon isolation plug shall be set from a depth 50
feet below the top of the productive horizon to a depth either 50 feet above
the top of the productive horizon, or 50 feet above the production casing
shoe if the production casing is set above the top of the productive horizon.
If the production casing shoe is set below the top of the productive horizon,
then the productive horizon isolation plug shall be set from a depth 50 feet
below the production casing shoe to a depth that is 50 feet above the top
of the productive horizon. In accordance with subsection (d)(7) of this section,
the Commission or its delegate may require additional plugs.
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 July 8, 2003.
TRD-200304133
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Effective date: July 28, 2003
Proposal publication date: March 14, 2003
For further information, please call: (512) 475-1295
The Railroad Commission of Texas adopts new §8.235, relating
to Natural Gas Pipelines Public Education and Liaison, and §8.310, relating
to Hazardous Liquids and Carbon Dioxide Pipelines Public Education and Liaison,
with changes to the versions published in the March 14, 2003, issue of the
The Commission adopts §8.235 and §8.310 to implement Texas Utilities
Code, §121.2015, and Texas Natural Resources Code, §117.011, respectively,
which were enacted by Senate Bill (SB) 310, 77th Legislature (2001). House
Bill (HB) 1931, 78th Legislature, Regular Session (2003) amended Texas Natural
Resources Code, §117.011, effective June 20, 2003. As adopted, the rules
implement the requirements of SB 310 and HB 1931 and support the Commission's
current enforcement provisions for emergency response liaison found in 49
CFR Parts 192 and 195.
New §8.235 and §8.310 are similar in requiring pipeline operators
to conduct liaison activities in person except as otherwise provided by each
section. Subsection (a) of each rule requires each operator of a pipeline
or the operator's designated representative to communicate and conduct liaison
activities with fire, police, and other appropriate emergency response officials.
The liaison activities are those required by 49 CFR Part 192.615(c)(1)-(4),
for natural gas pipelines, and 49 CFR Part 195.402(c)(12), for hazardous liquids
pipelines. The Commission has added clarifying language to subsection (a)
of both rules that specifies annual liaison meetings.
Subsection (b) of each new rule sets out the methods by which pipeline
operators are required to arrange meetings in person with emergency response
officials. Operators subject to §8.235 are required to attempt to schedule
a meeting in person by mail, fax, telephone, or e-mail; the Commission has
changed the "and" to "or" in subsection (b)(2) to make it clear that these
are alternatives. In a change from proposed new §8.310, hazardous liquid
and carbon dioxide pipeline operators may also use any one of the methods,
instead of being required to exhaust, in sequence, all of them. If a scheduled
meeting does not take place, both rules require the operator or operator's
representative to make one more effort to re-schedule the meeting in person
using one of the listed methods before proceeding to arrange a conference
call.
Subsection (c) of both new rules permits pipeline operators to conduct
community liaison activities by means of a telephone conference call if the
meeting cannot be conducted in person. Pursuant to new §8.235, the natural
gas pipeline operator or the operator's representative must make an effort
to conduct a community liaison meeting by telephone conference call with the
officials by one of the listed methods. The Commission has changed the "and"
to "or" in subsection (c)(2) to make it clear that these are alternatives.
Again, in an adopted change from the proposal, but consistent with the amendments
made to Texas Natural Resources Code, §117.012 by HB 1931, in new §8.310(c)(2),
the hazardous liquid or carbon dioxide pipeline operator or the operator's
representative may use any one of the methods, instead of being required to
exhaust, in sequence, all of the listed methods. If a scheduled conference
call does not take place, both rules require the operator or operator's representative
to make one more effort to re-schedule the community liaison telephone conference
call with the officials using one of the listed methods before proceeding
to proceeding to mail the liaison information pursuant to subsection (d) of
both rules.
Subsection (d) of both new rules permits the community liaison information
to be delivered by mailing the information by certified mail, return receipt
requested, if the operator or the operator's representative has made the efforts
required by subsections (b) and (c) but has not successfully arranged and
held either a meeting in person or a telephone conference.
Under new §8.235(e), an owner or operator of a natural gas pipeline
or natural gas pipeline facility any part of which is located within 1,000
feet of a public school building or recreational area must notify the Commission
and provide the specified information. While Texas Natural Resources Code, §117.012,
as amended by HB 1931, includes specific provisions for the safety education
of school districts with school buildings located within 1,000 feet of a hazardous
liquid or carbon dioxide pipeline, there are no similar provisions for natural
gas pipelines in Texas Utilities Code, §121.2015. However, Texas Utilities
Code, §121.201, authorizes the Commission by rule to "adopt safety standards
for the transportation of gas and for gas pipeline facilities." The extension
of the requirement to provide the Commission with information about school
districts with natural gas pipelines within 1,000 feet of a school building
or recreational area falls within the broad authority granted to the Commission
to enhance public safety.
Another change adopted in §8.310 is the deletion of proposed subsections
(e) and (f). The Commission is removing these provisions from this rule and
proposing concurrently with this adoption a separate new rule that incorporates
the requirements of Texas Natural Resources Code, §117.012, as amended
by HB 1931, 78th Legislature, Regular Session, (2003). Because proposed new §8.310(e)
and (f) are significantly different from the requirements of Texas Natural
Resources Code, §117.012, as amended, the Commission has determined that
publication of those provisions and solicitation of comment on them is necessary.
New §8.235(f) and proposed §8.310(g), now redesignated as subsection
(e), prescribe record-keeping requirements. Operators must maintain records
documenting compliance with the liaison activities required by the revised
proposed new rules. Records of attendance and acknowledgment of receipt by
the emergency response officials must be retained for five years from the
date of the event that is commemorated by the record. Records of certified
mail and/or telephone transmissions undertaken in compliance with subsections
(b) and (c) of these sections satisfy the record-keeping requirement.
The Commission received two comments on the proposed new rules, neither
from a group or an association. One comment expressed support for the new
rules conditioned on the stipulation that only transmission pipelines operating
at 20% SMYS or greater are included. Another comment expressed a similar concern
with respect to the scope of the rules, but provided a more extensive explanation
and suggestion for changing the language. This comment urged the Commission
to include in §8.235(a) the following statement: "The term 'natural gas
pipeline' or 'natural gas pipeline facilities' means those facilities defined
as Gathering Lines or Transmission Lines by 49 CFR Part 192" as a way of clarifying
that the rule does not apply to distribution facilities.
The Commission disagrees with both comments that would add language to
limit the applicability of these rules. The scope of the requirement to conduct
community liaison activities is clearly set forth in 49 CFR Part 192.615(c)(1)-(4)
and 49 CFR Part 195.402(c)(12), as cited in the rules.
Another comment with respect to §8.235(a) and §8.310(a) concerned
the lack of a statement of frequency of the required community liaison activities,
and suggested that the rule specify that the meetings be conducted on an annual
basis, which is consistent with most operators' current practices.
The Commission agrees that this change is helpful, and has made this change
in both rules.
Another comment questioned the basis and the need for §8.235(e) in
its entirety. This subsection requires owners or operators of natural gas
pipelines of natural gas pipeline facilities, any part of which is located
within 1,000 feet of a public school building or recreational area, to notify
the Commission by filing with the Gas Services Division, Pipeline Safety Section,
the name of the school; the street address of the school; and the identification
(system name) of the pipeline. The comment agreed with the inclusion in §8.310(e)
which provides specific requirements with respect to hazardous liquids or
carbon dioxide pipelines or pipeline facilities located within 1,000 feet
of a school, but opined that no public safety benefit is gained through the
collection, documentation, and submission of data regarding locations of public
schools and recreational areas as they relate to natural gas pipelines. The
comment observed that by its very nature, natural gas does not pose the same
safety and environmental concerns as hazardous liquids because natural gas
is lighter than air and naturally dissipates upward, in contrast to hazardous
liquids, which tend to pool on the ground. The comment goes on to state that
the safety considerations in comparing the two scenario types are significantly
different and should be treated as such within the proposed rules. The comment
concludes that the "mere collection of locational information and the transmittal
of that information to the Commission serves as nothing more than a record
keeping function with no clear benefits to the public safety" and urged the
Commission to delete subsection (e) from new §8.235.
The Commission disagrees with this comment. As proposed, the rules clearly
provide for significantly different procedures for natural gas pipelines compared
with hazardous liquids and carbon dioxide pipelines. Under the proposal, owners
or operators of hazardous liquids and carbon dioxide pipelines would be required
to consult with the fire department in whose jurisdiction the school is located
or another appropriate local emergency response entity regarding the emergency
response plan prepared as required by 49 CFR Part 195, and present the plan
at the first annual budget meeting of the board of trustees of the school
district in which the school is located after the plan is developed and at
subsequent annual budget meetings of the board of trustees of the school district
on the request of the board. In addition, the components of the presentation
were specified in the proposed rule. Operators of hazardous liquids or carbon
dioxide pipelines may use proposed API Recommended Practice 1162, entitled
Public Awareness Programs for Pipeline Operators, as guidance in preparing
and presenting the public education program for school districts. The presentation
was to contain a description of the pipeline and pipeline facilities within
1,000 feet of a school building or recreational area; a list of the products
carried by the pipelines and material safety data sheets for the products;
general facility maps; names and phone numbers of pipeline emergency response
personnel to contact in the event of an emergency; provisions for an emergency
preparedness drill; and information regarding the prevention of third party
damage to the pipeline. No provisions even remotely similar to these were
proposed for natural gas pipelines.
This comment offers an alternative argument, in the event that the Commission
chooses to retain the provisions of §8.235(e), for removing the requirement
to identify recreational areas within 1,000 feet of a natural gas pipeline
or pipeline facilities, pointing to Texas Natural Resources Code, §117.012(k),
as authority for limiting the reported information to just public schools.
The comment asserts that because nowhere in legislation has the Commission
been directed to collect information on recreation areas in the vicinity of
pipelines and concludes that although the Commission has "some broad authority"
under the statutes related to pipeline safety regulation, the Commission has
failed to demonstrate any need for expanding the record keeping requirements,
has not asserted any specific safety benefit to be realized by having pipeline
operators identify recreational areas and report them to the Commission, and
has not demonstrated any specific instances in which the availability of such
information would have eliminated a pipeline incident. The comment concludes
that the requirement to report the location of recreational areas within 1,000
feet of natural gas pipelines or pipeline facilities provides no public safety
benefit and should be eliminated from the adopted rule.
The Commission disagrees that it must be specifically directed in statute
to collect information about the distance of pipeline facilities from public
schools. Further, the Commission disagrees that it must wait for a specific
pipeline incident involving a school to justify collection of such information.
The Commission also disagrees that collecting information about schools and
recreational areas within 1,000 feet of a natural gas pipeline or pipeline
facility provides "no public safety benefit." The comment described the characteristics
of natural gas that is not under pressure; natural gas under pressure in a
pipeline is very different. It is common knowledge that natural gas pipelines
can and do explode, with significant safety and environmental consequences.
Such an event near a school could involve catastrophic consequences, including
loss of life and the potential for extensive property damage or loss.
This comment further objects to use of the broad term "recreational areas"
because it could encompass a great variety of facilities and uses of property.
The comment complained that it is not clear whether "recreational areas" is
limited to those areas and facilities owned and/or operated by public schools,
or encompasses the entire spectrum of such areas. Further, the comment pointed
out that it would be extremely difficult to develop and communicate emergency
response plans for these facilities. The comment again concludes that reports
relating to "recreational areas" under §8.235(e) should be deleted from
the subsection.
The Commission agrees that the term "recreational area" could be extremely
broad, and agrees that it would indeed be difficult to develop and communicate
emergency response plans for every possible type of recreational area, but
points out that §8.235(e) does not require that. All this subsection
requires is the identification and reporting to the Commission of public school
buildings and recreational areas that are within 1,000 feet of a natural gas
pipeline or pipeline facility. To address the concern that it is not clear
whether the term "recreational area" was limited to those owned or operated
by a public school, the Commission has added language clarifying that "recreational
area" is indeed limited to such areas owned or operated by and typically associated
with public schools, such as playgrounds and outdoor areas for football, baseball,
basketball, track, tennis, golf, and buildings, such as gymnasia or field
houses that may be used for such sports and activities.
Finally, a comment regarding the record keeping requirements in §8.235(f)
pointed out that operators of natural gas pipelines and pipeline facilities
are not required to conduct community liaison activities with school boards
or school principals, and this requirement should be deleted from subsection
(f). The Commission agrees and has removed this language.
Subchapter C. REQUIREMENTS FOR NATURAL GAS PIPELINES ONLY
16 TAC §8.235
The Commission adopts new §8.235 pursuant to Texas Utilities
Code, §121.2015, which requires the Commission to adopt rules regarding
public education and awareness relating to gas pipeline facilities and community
liaison for responding to an emergency relating to a gas pipeline facility
and mandates that the Commission require operators or their designated representatives
to communicate and conduct liaison activities with fire, police, and other
appropriate public emergency response officials by meetings in person except
as provided by §121.2015; and Texas Utilities Code, §121.201, which
authorizes the Commission by rule to adopt safety standards for the transportation
of gas and for gas pipeline facilities and to take any other requisite action
in accordance with 49 U.S.C. §60101, et seq., or a succeeding law. The
requirement that operators of natural gas pipelines or pipeline facilities
provide information to the Commission about school districts with natural
gas pipelines or pipeline facilities within 1000 feet of a school building
or recreational area falls within the broad authority granted to the Commission
to enhance public safety.
Statutory authority: Texas Utilities Code, §121.201 and §121.2015.
Cross-reference to statute: Texas Utilities Code, §121.201 and §121.2015.
Issued in Austin, Texas, on July 8, 2003.
§8.235.Natural Gas Pipelines Public Education and Liaison.
(a)
Liaison activities required. Each operator of a natural
gas pipeline or natural gas pipeline facilities or the operator's designated
representative shall communicate and conduct liaison activities on an annual
basis with fire, police, and other appropriate public emergency response officials.
The liaison activities are those required by 49 CFR Part 192.615(c)(1)-(4).
These liaison activities shall be conducted in person, except as provided
by this section.
(b)
Meetings in person. The operator or the operator's representative
may conduct the required community liaison activities as provided by subsection
(c) of this section only if the operator or the operator's representative
has made an effort to conduct a community liaison meeting in person with the
officials by one of the following methods:
(1)
mailing a written request for a meeting in person to the
appropriate officials by certified mail, return receipt requested;
(2)
sending a request for a meeting in person to the appropriate
officials by facsimile transmission; or
(3)
making one or more telephone calls or e-mail message transmissions
to the appropriate officials to request a meeting in person.
(4)
If a scheduled meeting does not take place, the operator
or operator's representative shall make an effort to re-schedule the community
liaison meeting in person with the officials using one of the methods in paragraphs
(1)-(3) of this subsection before proceeding to arrange a conference call
pursuant to subsection (c) of this section.
(c)
Conference call. If the operator or operator's representative
cannot arrange a meeting in person after complying with subsection (b) of
this section, the operator or the operator's representative shall make an
effort to conduct community liaison activities by means of a telephone conference
call with the officials by one of the following methods:
(1)
mailing a written request for a telephone conference to
the appropriate officials by certified mail, return receipt requested;
(2)
sending a request for a telephone conference to the appropriate
officials by facsimile transmission; or
(3)
making one or more telephone calls or e-mail message transmissions
to the appropriate officials to request a telephone conference.
(4)
If a scheduled telephone conference call does not take
place, the operator or operator's representative shall make an effort to re-schedule
the community liaison telephone conference call with the officials using one
of the methods in paragraphs (1)-(3) of this subsection before proceeding
to mail the liaison information pursuant to subsection (d) of this section.
(d)
Mailing liaison information. If the operator or the operator's
representative has made the efforts required by subsections (b) and (c) but
has not successfully arranged and held either a meeting in person or a telephone
conference, the community liaison information required to be conveyed may
be delivered by mailing the information by certified mail, return receipt
requested.
(e)
Proximity to public school. Each owner or operator of a
natural gas pipeline or natural gas pipeline facility any part of which is
located within 1,000 feet of a public school building or public school recreational
area shall notify the Commission by filing with the Gas Services Division,
Pipeline Safety Section, the following information:
(1)
the name of the school;
(2)
the street address of the school; and
(3)
the identification (system name) of the pipeline.
(f)
Records. The operator shall maintain records documenting
compliance with the liaison activities required by this section. Records of
attendance and acknowledgment of receipt by the emergency response officials
shall be retained for five years from the date of the event that is commemorated
by the record. Records of certified mail and/or telephone transmissions undertaken
in compliance with subsections (b) and (c) of this section satisfy the record-keeping
requirements of this subsection.
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 July 8, 2003.
TRD-200304134
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Effective date: July 28, 2003
Proposal publication date: March 14, 2003
For further information, please call: (512) 475-1295
16 TAC §8.310
The Commission adopts new §8.310 pursuant to Texas Natural
Resources Code, §117.011, which gives the Commission jurisdiction over
all pipeline transportation of hazardous liquids or carbon dioxide and over
all hazardous liquid or carbon dioxide pipeline facilities as provided by
49 U.S.C. §60101, et seq., and §117.012, as amended by HB 1931 (78th
Legislature, Regular Session, 2003), which directs the Commission to adopt
rules regarding public education and awareness concerning hazardous liquid
or carbon dioxide pipeline facilities and community liaison for the purpose
of responding to an emergency concerning a hazardous liquid or carbon dioxide
pipeline facility and mandates that the Commission require operators of hazardous
liquids or carbon dioxide pipelines or pipeline facilities to conduct liaison
activities with fire, police, and other appropriate public emergency response
officials by meetings in person except as otherwise provided by §117.012.
Statutory authority: Texas Natural Resources Code, §117.011 and §117.012.
Cross-reference to statute: Texas Natural Resources Code, §117.011
and §117.012.
Issued in Austin, Texas on July 8, 2003.
§8.310.Hazardous Liquids and Carbon Dioxide Pipelines Public Education and Liaison.
(a)
Liaison activities required. Each operator of a hazardous
liquid or carbon dioxide pipeline or pipeline facilities or the operator's
designated representative shall communicate and conduct liaison activities
on an annual basis with fire, police, and other appropriate public emergency
response officials. The liaison activities are those required by 49 CFR Part
195.402(c)(12). These liaison activities shall be conducted in person, except
as provided by this section.
(b)
Meetings in person. The operator or the operator's representative
may conduct required community liaison activities as provided by subsection
(c) of this section only if the operator or the operator's representative
has completed one of the following efforts to conduct a community liaison
meeting in person with the officials:
(1)
mailing a written request for a meeting in person to the
appropriate officials by certified mail, return receipt requested;
(2)
sending a request for a meeting in person to the appropriate
officials by facsimile transmission; or
(3)
making one or more telephone calls or e-mail message transmissions
to the appropriate officials to request a meeting in person.
(4)
At any time the operator or operator's representative makes
contact with the appropriate officials and schedules a meeting in person,
no further attempts to make contact under this section are necessary. However,
if a scheduled meeting does not take place, the operator or operator's representative
shall make an effort to re-schedule the community liaison meeting in person
with the officials using one of the methods in paragraphs (1)-(3) of this
subsection before proceeding to arrange a conference call pursuant to subsection
(c) of this section.
(c)
Conference call. If the operator or operator's representative
cannot arrange a meeting in person after complying with subsection (b) of
this section, the operator or the operator's representative shall make one
of the following efforts to conduct community liaison activities by means
of a telephone conference call with the officials:
(1)
mailing a written request for a telephone conference to
the appropriate officials by certified mail, return receipt requested;
(2)
sending a request for a telephone conference to the appropriate
officials by facsimile transmission; or
(3)
making one or more telephone calls or e-mail message transmissions
to the appropriate officials to request a telephone conference.
(4)
At any time the operator makes contact with the appropriate
officials and schedules a telephone conference call, no further attempts to
make contact under this section are necessary. However, if a scheduled telephone
conference call does not take place, the operator or operator's representative
shall make an effort to re-schedule the telephone conference call with the
officials using one of the methods in paragraphs (1)-(3) of this subsection
before proceeding to mail the liaison information pursuant to subsection (d)
of this section.
(d)
Mailing liaison information. If the operator or the operator's
representative has made all of the efforts required by subsections (b) and
(c) but has not successfully arranged either a meeting in person or a telephone
conference, the community liaison information required to be conveyed may
be delivered by mailing the information by certified mail, return receipt
requested.
(e)
Records. The operator shall maintain records documenting
compliance with the liaison activities required by this section. Records of
attendance and acknowledgment of receipt by the emergency response officials
shall be retained for five years from the date of the event that is commemorated
by the record. Records of certified mail and/or telephone transmissions undertaken
in compliance with subsections (b) and (c) of this section satisfy the record-keeping
requirements of this subsection.
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 July 8, 2003.
TRD-200304138
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Effective date: July 28, 2003
Proposal publication date: March 14, 2003
For further information, please call: (512) 475-1295
Subchapter A. GENERAL REQUIREMENTS
16 TAC §9.1
The Railroad Commission of Texas adopts an amendment to §9.1,
relating to Application of Rules, Severability, and Retroactivity, with one
change to the version published in the March 28, 2003, issue of the
Texas Natural Resources Code, §113.011, provides that the Commission
shall administer and enforce the laws of Texas and the rules and standards
of the Commission relating to liquefied petroleum gas (LP-gas). Texas Natural
Resources Code, §113.051, provides that the Commission shall promulgate
and adopt rules or standards or both relating to any and all aspects or phases
of the liquefied petroleum gas industry that will protect or tend to protect
the health, welfare, and safety of the general public.
Recently, it has become more difficult for original equipment manufacturers
of vehicles and fuel supply containers that use LP-gas doing business in Texas
to make, manufacture, and market vehicles and fuel supply containers nationally
due to differences in state rules and regulations. Vehicles and fuel supply
containers using LP-gas comprise a small percent of the market for vehicles
and fuel supply containers. Differing state requirements increase costs associated
with making, manufacturing, and marketing these vehicles and fuel supply containers
across the country. Current national standards, which have been adopted by
the Commission, impose safety standards and specifications on vehicles and
fuel supply containers that insure a high degree of safety to the public health,
safety, and welfare. Therefore, the Commission has determined that it is in
the public interest to exclude original equipment manufacturers of vehicles
and fuel supply containers from Commission safety rules that deviate from
national safety standards and that do not marginally increase public safety
in order to remove regulatory burdens that increase the cost of making, manufacturing,
and marketing vehicles and fuel supply containers using LP-gas.
New subsection (f) excludes vehicles and fuel supply containers that meet
certain requirements from the provisions of Chapter 9. Specifically, vehicles
and fuel supply containers that have been manufactured or installed by an
original equipment manufacturer, that comply with Title 49, Code of Federal
Regulations, the Federal Motor Vehicle Safety Standards, and that comply with
the National Fire Protection Association (NFPA) Code 58, Liquefied Petroleum
Gas Code , are excluded from the requirements of Chapter 9, except as specified
in new subsection (g). New subsection (g) mandates that vehicles and fuel
supply containers excluded pursuant to §9.1(f) must still comply with
the requirements of §9.203, relating to School Bus, Public Transportation,
Mass Transit, and Special Transit Vehicle Installations and Inspections, and
the Commission's exception to NFPA 58 §8.2.3.1(k) under §9.403,
relating to Sections in NFPA 58 Not Adopted by Reference, and Adopted With
Changes, Additional Requirements, or Corrections.
Under new subsection (g), even though a vehicle complies with NFPA 58 standards,
the Commission will still require that vehicle to be equipped with a fixed
liquid level gauge and the gauge must be used when filling the fuel supply
container.
The Commission received one comment on the proposal from Ford Motor Company
(Ford) concerning three subsections of the amended rule. Ford commented that
subsection (f)(1) should contain the following additional language: "or the
supplier contracted by OEMs to manufacturer or install such systems." Ford
submitted the following rationale for this change: "All work done by suppliers
directly contracted by OEMs to modify vehicles is specified to meet the same
criteria as if completed by the OEM."
The Commission disagrees with Ford's comment that subsection (f)(1) should
be amended to include additional language to exempt additional parties who
may have a contractual agreement with an OEM to manufacture or install systems
for OEMs. The purpose of the Commission's rule is to exempt OEM vehicles from
certain Texas-specific requirements. Under the proposed rule, an OEM may use
parts supplied from third party suppliers to manufacture LP-gas vehicles or
fuel supply containers and still fall within the exemption. Likewise, an OEM
may install in its vehicles LP-gas systems or fuel supply containers obtained
from third party suppliers and still fall within the exemption provided by
the amended rule. The proposed rule is not intended to limit the supply choices
which an OEM may make with respect to the manufacture of the OEM's vehicles
and fuel supply containers. The purpose and intent of the amendment is to
exempt from certain LP-gas rule requirements OEM vehicles, without regard
to whether an OEM uses third party suppliers.
Ford commented that subsection (f)(2) should contain the following additional
language: "except as pre-empted by Title 49 CFR, FMVSS," and submitted the
following rationale for this proposed change: "NHTSA has taken the following
position in cases where State requirements cover the same topic as FMVSS with
respect to Federal preemption of state laws, 49 U.S.C. 30103(b) provides in
pertinent part that: '(b) PREEMPTION - (1) When a motor vehicle safety standard
is in effect under this chapter, a State or political subdivision of a State
may prescribe or continue in effect a standard applicable to the same aspect
of performance of a motor vehicle or motor vehicle equipment only if the standard
is identical to the standard prescribed under this chapter.'"
The Commission disagrees with Ford's comment that subsection (f)(2) should
be amended to include additional language that states the Commission's rule
is only effective if not pre-empted by federal law or regulation. This language
is unnecessary and redundant because the Commission's rule is not currently
pre-empted by federal law or regulation; further, if a federal statute or
rule is enacted that does pre-empt the Commission's rule, federal pre-emption
would apply regardless of whether the Commission's rule so stated.
Last, Ford commented that subsection (g) should contain the following additional
language: "Alternatively, the fixed liquid level gauge and use of same is
not required if the stop fill valve or a substitute device achieves the same
purpose of the fixed liquid level gauge, i.e., to prevent potential release
of LPG through the pressure relief valve if the internal tank stop fill valve
allows tank overfill." Ford submitted the following rationale for this proposed
change: "Rationale for change: OEMs need the design flexibility to consider
other possibilities to be able to meet the EPA emission requirements for 2006
MY and protect against the potential for unwanted LPG release. If the rule
is modified as recommended above, both the current need to have and use the
fixed liquid level gauge and the need to discontinue its use by 2006 MY would
be accommodated without further rule change. The unequivocal requirement to
have and use the fixed liquid level gauge is unnecessarily design restrictive.
Without the adoption of a rule change there will be no alternative except
to discontinue offering LPG powered vehicles in the State of Texas as of the
2006 Model Year."
The Commission disagrees with the comment submitted by Ford that subsection
(g) should be changed. The Commission recognizes the problem indicated by
Ford in its comment regarding the use of fixed liquid level gauges. However,
the Commission addresses alternatives to using fixed liquid level gauges in
the Commission's proposed exception to NFPA 58, 2001 edition, §8.2.3(l).
The exception to this NFPA §8.2.3.(l) reads as follows (the Commission's
added language is italicized): "Where an overfilling prevention device is
installed on an engine fuel container, venting of gas through a fixed maximum
liquid level gauge shall not be required
provided:
1. The OPD is verified by the owner of the vehicle to be working properly;
2. The verification of the valve is documented yearly and clearly marked on
the container in a visible location; and 3. The OPD is replaced every two
years, documentation is kept by the owner of the vehicle, and the container
is marked in a visible location verifying its replacement."
The language
in §9.1(g) does not need to be changed.
The Commission adopts the amendments under Texas Natural Resources
Code, §113.051, which authorizes the Commission to adopt rules relating
to any and all aspects or phases of the LP-gas industry that will protect
or tend to protect the health, welfare, and safety of the general public,
and §113.052, which authorizes the Commission to adopt by reference,
in whole or in part, the published codes of the National Fire Protection Association
as standards to be met in the design, construction, fabrication, assembly,
installation, use, and maintenance of containers, tanks, appliances, systems,
and equipment for the transportation, storage, delivery, use, and consumption
of LP-gas or any one or more of these purposes.
Statutory authority: Texas Natural Resources Code, §113.051 and §113.052.
Cross-reference to statute: Texas Natural Resources Code, Chapter 113.
Issued in Austin, Texas, on July 8, 2003.
§9.1.Application of Rules, Severability, and Retroactivity.
(a)
The
LP-Gas Safety Rules
apply
to the location and operation of liquefied petroleum gas systems, equipment,
and appliances. These standards also apply to truck and railcar loading racks,
but do not apply to marine terminals, natural gasoline plants, refineries,
tank farms, gas manufacturing plants, plants engaged in processing liquefied
petroleum gases, or to railcar loading racks used in connection with these
excluded establishments.
(1)
Subchapter A, General Requirements, applies to various
types of LP-gas activities, including licensing, examination, and training
requirements.
(2)
Subchapter B, Stationary Installations and Container Requirements,
applies to proposed and existing stationary LP-gas installations and containers,
including cylinder exchange racks.
(3)
Subchapter C, Vehicles and Vehicle Dispensers, applies
to transports and bobtails that deliver LP-gas, and school buses and other
vehicles that are powered by LP-gas.
(4)
Subchapter D, Adoption by Reference of NFPA 54 (
National Fuel Gas Code
), applies to the adoption by reference of NFPA
54 and specifies additional or alternative requirements from those found in
NFPA 54.
(5)
Subchapter E, Adoption by Reference of NFPA 58 (
LP-Gas Code
), applies to the adoption by reference of NFPA 58 and specifies
additional or alternative requirements from those found in NFPA 58.
(6)
Subchapter F, Adoption by Reference of NFPA 51 (
Standard for the Design and Installation of Oxygen-Fuel Gas Systems for Welding,
Cutting, and Allied Processes
), applies to the use of LP-gas as a welding
fuel.
(b)
If any term, clause, or provision of these rules is for
any reason declared invalid, the remainder of the provisions shall remain
in full force and effect, and shall in no way be affected, impaired, or invalidated.
(c)
Nothing in these rules shall be construed as requiring,
allowing, or approving the unlicensed practice of engineering or any other
professional occupation requiring licensure.
(d)
Unless otherwise stated, the
LP-Gas Safety Rules
are not retroactive.
(e)
As stated in Texas Natural Resources Code, Chapter 113,
any LP-gas container with a water capacity of one gallon or less, or any LP-gas
piping system, or appliance attached or connected to such a container is exempt
from the
LP-Gas Safety Rules
, including any
adopted NFPA pamphlets. For the purpose of consistency, the figure of 4.20
lb is used to determine the weight of one gallon of LP-gas. The omission of
a specific NFPA 58 pamphlet or any other NFPA rule containing any such applicable
language from Table 1 of §9.403 of this title (relating to Sections in
NFPA 58 Not Adopted by Reference, and Adopted With Changes, Additional Requirements,
or Corrections) is inadvertent and shall not be read or understood as requiring
or allowing any such size of LP-gas container to comply with the adopted LP-gas
safety rule requirements.
(f)
This chapter shall not apply to vehicles and fuel supply
containers that:
(1)
are manufactured or installed by original equipment manufacturers;
(2)
comply with Title 49, Code of Federal Regulations, the
Federal Motor Vehicle Safety Standards; and
(3)
comply with the National Fire Protection Association (NFPA)
Code 58,
Liquefied Petroleum Gas Code
.
(g)
Vehicles and fuel supply containers excluded from the requirements
of this chapter pursuant to subsection (f) of this section shall comply with
the requirements of §9.203 of this title, relating to School Bus, Public
Transportation, Mass Transit, and Special Transit Vehicle Installations and
Inspections, and the Commission's exception to NFPA 58 §8.2.3.1(k) in
Table 1 in §9.403(a), relating to Sections in NFPA 58 Not Adopted by
Reference, and Adopted with Changes, Additional Requirements, or Corrections.
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 July 8, 2003.
TRD-200304140
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Effective date: July 28, 2003
Proposal publication date: March 28, 2003
For further information, please call: (512) 475-1295
Subchapter G. SURFACE COAL MINING AND RECLAMATION OPERATIONS, PERMITS, AND COAL EXPLORATION PROCEDURES SYSTEMS
2.
GENERAL REQUIREMENTS FOR PERMITS AND PERMIT APPLICATIONS
16 TAC §12.108
The Railroad Commission of Texas adopts an amendment to §12.108,
relating to Permit Fees, without change from the version published in the
April 11, 2003, issue of the
Texas Register
(28
TexReg 3028). This section addresses fees to be paid to the Commission for
the processing of applications for new coal mining permits, permit revisions,
and permit renewals, as well as annual fees paid for each acre of land mined.
The Commission amends subsection (b) to increase the annual per-acre fee
to facilitate recovery of the Commission's costs of providing various services.
Specifically, the adopted amendment increases the annual fee from $120 to
$300 for each acre of land in the permit area on which the permittee actually
conducted operations for the removal of coal and lignite during a calendar
year. The fee currently in effect is set at the statutory minimum and has
not been increased since the provision in the Texas Surface Coal Mining and
Reclamation Act that authorizes the Commission to set the fee, Texas Natural
Resources Code, §134.055, became effective September 1, 1985 (Acts 1985,
69th Leg., ch 239, §70); Vernon's Ann. Civ. Stat. art. 5920-11, §18(c).
As adopted, the new fee amount will go into effect on September 1, 2003.
The per-acre fee for calendar year 2003 will be calculated as follows: for
each acre of land on which a permittee actually conducted operations for the
removal of coal and lignite during the period January 1, 2003, through August
31, 2003, each permittee will pay to the Commission an annual fee of $120
per acre. For each acre of land on which a permittee actually conducted operations
for the removal of coal and lignite during the period September 1, 2003, through
December 31, 2003, each permittee will pay to the Commission an annual fee
of $300 per acre. Beginning January 1, 2004, the annual $300 per acre fee
will apply for each acre of land within the permit area on which a permittee
actually conducted operations for the removal of coal and lignite during the
calendar year.
The Commission also amends the title of §12.108 to change the word
"permits" to "permit."
The Commission received a total of three comments on the proposed amendments.
One was from an association, the Texas Mining and Reclamation Association
(TMRA), and generally opposed the rule as proposed. Two other entities, TXU
Energy (TXU) and Alcoa, also filed comments.
Both TXU and TMRA suggested the Commission focus on internal cost efficiencies
to avoid or minimize the fee increase. The Commission agrees that efficiency
in using public resources is always warranted, and notes that the agency is
undergoing an internal agency-wide efficiency review. TMRA suggested the Commission
postpone any fee increase until after an efficiency review has been completed
and changes proposed during such review have been undertaken. The Commission
disagrees with this comment because the Commission has been directed by the
Legislature to increase and assess surface mining fees to cover the Commission's
cost of permitting and inspecting coal mining facilities (Article VI-Natural
Resources, Pages VI-43- 44, Rider 9, Conference Comm. Report on H.B. 1, General
Appropriations Act, 2004-2005 Biennium, 78th Legislature, Regular Session
(2003). The fee increase is necessary to cover the Commission's cost of permitting
and inspecting coal mining facilities. Alcoa submitted a comment after the
close of the comment period stating that it "does not oppose the proposed
fee increase for the purpose of maintaining state delegation of this federal
program."
The Commission adopts the amendments under Texas Natural Resources
Code, §134.013, which authorizes the Commission to promulgate rules pertaining
to surface coal mining operations; §134.055, which authorizes the Commission
to obtain annual fees; and Texas Government Code, §2001.006, which authorizes
the Commission to promulgate rules to implement legislation that has become
law but has not become effective.
Statutory authority: Texas Natural Resources Code, §134.013 and §134.055;
Texas Government Code, §2001.006.
Cross-reference to statute: Texas Natural Resources Code, §134.013
and §134.055.
Issued in Austin, Texas, on July 8, 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 July 8, 2003.
TRD-200304144
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Effective date: July 28, 2003
Proposal publication date: April 11, 2003
For further information, please call: (512) 475-1295
Subchapter A. SCOPE AND DEFINITIONS
16 TAC §13.1
The Railroad Commission of Texas adopts an amendment to §13.1,
relating to Scope, without changes to the version published in the March 28,
2003, issue of the
Texas Register
(28 TexReg
2685). Specifically, the Commission adopts new subsections (c) and (d) to
exclude original equipment manufacturers (OEM) of compressed natural gas (CNG)
vehicles and fuel supply containers from the requirements of 16 TAC Chapter
13, Subchapters A, B, C, D, E, and F, except for §13.24, relating to
Filings Required for School Bus, Mass Transit, and Special Transit Installations.
The Commission also amends subsection (b) to reflect a change in statutory
language under Texas Natural Resources Code, §116.002.
Texas Natural Resources Code, §116.011, provides that the Commission
shall administer and enforce the rules and standards under Chapter 116 of
the Natural Resources Code relating to compressed natural gas and liquefied
natural gas. Texas Natural Resources Code, §116.012, provides that to
protect the health, safety, and welfare of the general public, the Commission
shall adopt necessary rules and standards relating to the work of compression
and liquefaction, storage, sale or dispensing, transfer and transportation,
use or consumption, and disposal of compressed natural gas or liquefied natural
gas. Texas Natural Resources Code, §116.013, provides that the Commission
may adopt by reference all or part of the published codes of nationally recognized
societies as standards to be met in the design, construction, fabrication,
assembly, installation, use, and maintenance of CNG or LNG components and
equipment.
Recently, it has become more difficult for original equipment manufacturers
of vehicles and fuel supply containers that use CNG doing business in Texas
to make, manufacture, and market vehicles and fuel supply containers nationally
due to differences in state rules and regulations. Vehicles and fuel supply
containers using compressed natural gas comprise a small percent of the market
for vehicles and fuel supply containers. Differing state requirements increase
costs associated with making, manufacturing, and marketing these vehicles
and fuel supply containers across the country. Current national standards,
which have been adopted by the Commission, impose standards and specifications
on vehicles and fuel supply containers that insure a high degree of safety
to the public health, safety, and welfare. Therefore, the Commission has determined
that it is in the public interest to exclude original equipment manufacturers
of vehicles and fuel supply containers from Commission safety rules that deviate
from national safety standards and that do not marginally increase public
safety in order to remove regulatory burdens that increase the cost of making,
manufacturing, and marketing vehicles and fuel supply containers using compressed
natural gas.
New §13.1(c) excludes CNG vehicles and fuel supply containers that
meet certain requirements from the provisions of Chapter 13, Subchapters A,
B, C, D, E, and F. Specifically, CNG vehicles and fuel supply containers that
have been manufactured or installed by an original equipment manufacturer,
that comply with Title 49, Code of Federal Regulations, the Federal Motor
Vehicle Safety Standards, and that comply with the National Fire Protection
Association (NFPA) Code 52,
Compressed Natural Gas
(CNG) Vehicular Systems Code
, are excluded from the requirements of
Chapter 13, except as specified in proposed new subsection (d). New subsection
(d) mandates that CNG vehicles and fuel supply containers excluded pursuant
to §13.1(c) must still comply with the requirements of §13.24, relating
to Filings Required for School Bus, Mass Transit, and Special Transit Installations.
The Commission received one comment on the proposal from Ford Motor Company
(Ford) concerning two subsections of the amended rule. Ford commented that
subsection (c)(1) should contain the following additional language: "or the
supplier contracted by OEMs to manufacturer or install such systems." Ford
submitted the following rationale for this change: "All work done by suppliers
directly contracted by OEMs to modify vehicles is specified to meet the same
criteria as if completed by the OEM."
The Commission disagrees with Ford's comment that subsection (c)(1) should
be amended to include additional language to exempt additional parties who
may have a contractual agreement with an OEM to manufacture or install systems
for OEMs. The purpose of the Commission's rule is to exempt OEM vehicles from
certain Texas-specific requirements. Under the proposed rule, an OEM may use
parts supplied from third party suppliers to manufacture CNG vehicles or fuel
supply containers and maintain the exemption. Likewise, an OEM may install
in its vehicles CNG systems or fuel supply containers obtained from third
party suppliers and still fall within the exemption provided by the amended
rule. The proposed rule is not intended to limit the supply choices which
an OEM may make with respect to the manufacture of the OEM's vehicles and
fuel supply containers. The purpose and intent of the amendment is to exempt
from certain CNG rule requirements OEM vehicles, without regard to whether
an OEM uses third party suppliers.
Ford commented that subsection (c)(2) should contain the following additional
language: "except as pre-empted by Title 49 CFR, FMVSS." Ford submitted the
following rationale for this proposed change: "NHTSA has taken the following
position in cases where State requirements cover the same topic as FMVSS with
respect to Federal preemption of state laws, 49 U.S.C. 30103(b) provides in
pertinent part that '(b) PREEMPTION - (1) When a motor vehicle safety standard
is in effect under this chapter, a State or political subdivision of a State
may prescribe or continue in effect a standard applicable to the same aspect
of performance of a motor vehicle or motor vehicle equipment only if the standard
is identical to the standard prescribed under this chapter.'"
The Commission disagrees with Ford's comment that subsection (c)(2) should
be amended to include additional language that states the Commission's rule
is only effective if not pre-empted by federal law or regulation. This language
is unnecessary and redundant because the Commission's rule is not currently
pre-empted by federal law or regulation; further, if a federal statute or
rule is enacted that does pre-empt the Commission's rule, federal pre-emption
would apply regardless of whether the Commission's rule so stated.
Last, Ford submitted the following comment regarding subsection (c)(3)
of the proposed amendment: "MEMO: Exceptions to NFPA 52 are embedded within
NFPA 52 for manufacturers that self-certify to FMVSS."
The Commission neither disagrees nor agrees with Ford's comment regarding
subsection (c)(3) as the comment appears neither to support nor oppose the
Commission's proposed amendment.
The Commission adopts the amendments under Texas Natural Resources
Code, §116.012, which authorizes the Commission to adopt rules and standards
relating to the work of compression and liquefaction, storage, sale or dispensing,
transfer or transportation, use or consumption, and disposal of compressed
natural gas or liquefied natural gas, and §116.013, which authorizes
the Commission to adopt by reference, in whole or in part the published codes
of nationally recognized societies as standards to be met in the design, construction,
fabrication, assembly, installation, use, and maintenance of CNG or LNG components
and equipment.
Statutory authority: Texas Natural Resources Code, §116.012 and §116.013.
Cross-reference to statute: Texas Natural Resources Code, Chapter 116.
Issued in Austin, Texas, on July 8, 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 July 8, 2003.
TRD-200304141
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Effective date: July 28, 2003
Proposal publication date: March 28, 2003
For further information, please call: (512) 475-1295
16 TAC §13.2004
The Railroad Commission of Texas adopts the repeal of §13.2004,
relating to Applicability, Severability, and Retroactivity, without change
from the version published in March 28, 2003, issue of the
Texas Register
(28 TexReg 2688). The repeal is in conjunction with
a separate but concurrent adoption of a new §14.2004, with the same title,
to be in new 16 TAC Chapter 14 entitled Regulations for Liquefied Natural
Gas. This repeal is for the purpose of renumbering this rule to move it to
Chapter 14 and to add some new language to exclude original equipment manufacturers
(OEM) of liquefied natural gas (LNG) vehicles and fuel supply containers from
the requirements of 16 TAC Chapter 14, to be entitled Regulations for Liquefied
Natural Gas (LNG), except for §14.2004, relating to Filing Required for
School Bus, Mass Transit and Special Transit Vehicles. In the separate rulemaking,
new §14.2004 is adopted in place of §13.2004 as part of the move
of the LNG rules out of Chapter 13 and into Chapter 14.
The Commission received no comments regarding the proposed repeal of §13.2004
and the renumbering of the rule to new §14.2004.
The repeal is adopted under the Texas Natural Resources Code, §116.012,
which authorizes the Commission to adopt rules and standards relating to the
work of compression and liquefaction, storage, sale or dispensing, transfer
or transportation, use or consumption, and disposal of compressed natural
gas or liquefied natural gas, and §116.013, which authorizes the Commission
to adopt by reference, in whole or in part the published codes of nationally
recognized societies as standards to be met in the design, construction, fabrication,
assembly, installation, use, and maintenance of CNG or LNG components and
equipment.
Statutory authority: Texas Natural Resources Code, §116.012 and §116.013.
Cross-reference to statute: Texas Natural Resources Code, Chapter 116.
Issued in Austin, Texas, on July 8, 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 July 8, 2003.
TRD-200304142
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Effective date: July 28, 2003
Proposal publication date: March 28, 2003
For further information, please call: (512) 475-1295
Subchapter A. GENERAL APPLICABILITY AND REQUIREMENTS
16 TAC §14.2004
The Railroad Commission of Texas adopts new §14.2004,
relating to Applicability, Severability, and Retroactivity, without changes
from the version published in the March 28, 2003, issue of the
Texas Register
(28 TexReg 2689). Specifically, the Commission adopts
new wording in subsections (e) and (f) to exclude original equipment manufacturers
(OEM) of liquefied natural gas (LNG) vehicles and fuel supply containers from
the requirements of 16 TAC Chapter 14, to be entitled Regulations for Liquefied
Natural Gas, except for §14.2046, relating to Filing Required for School
Bus, Mass Transit and Special Transit Vehicles. In a separate rulemaking,
the repeal of existing §13.2004 is adopted with new §14.2004 adopted
in its place as part of the move of the LNG rules out of Chapter 13 and into
Chapter 14.
Texas Natural Resources Code, §116.011, provides that the Commission
shall administer and enforce the rules and standards under Chapter 116 of
the Natural Resources Code relating to compressed natural gas and liquefied
natural gas. Texas Natural Resources Code, §116.012, provides that to
protect the health, safety, and welfare of the general public, the Commission
shall adopt necessary rules and standards relating to the work of compression
and liquefaction, storage, sale or dispensing, transfer and transportation,
use or consumption, and disposal of compressed natural gas or liquefied natural
gas. Texas Natural Resources Code, §116.013, provides that the Commission
may adopt by reference all or part of the published codes of nationally recognized
societies as standards to be met in the design, construction, fabrication,
assembly, installation, use, and maintenance of CNG or LNG components and
equipment.
Recently, it has become more difficult for original equipment manufacturers
of vehicles and fuel supply containers that use LNG gas doing business in
Texas to make, manufacture, and market vehicles and fuel supply containers
nationally due to differences in state rules and regulations. Vehicles and
fuel supply containers using liquefied natural gas comprise a small percent
of the market for vehicles and fuel supply containers. Differing state requirements
increase costs associated with making, manufacturing, and marketing these
vehicles and fuel supply containers across the country. Current national standards,
which have been adopted by the Commission, impose standards and specifications
on vehicles and fuel supply containers that insure a high degree of safety
to the public health, safety, and welfare. Therefore, the Commission has determined
that it is in the public interest to exclude original equipment manufacturers
of vehicles and fuel supply containers from Commission safety rules that deviate
from national safety standards and that do not marginally increase public
safety in order to remove regulatory burdens that increase the cost of making,
manufacturing, and marketing vehicles and fuel supply containers using liquified
natural gas.
New §14.2004(e) excludes LNG vehicles and fuel supply containers that
meet certain requirements from the provisions of Chapter 14. Specifically,
LNG vehicles and fuel supply containers that have been manufactured or installed
by an original equipment manufacturer, that comply with Title 49, Code of
Federal Regulations, the Federal Motor Vehicle Safety Standards, and that
comply with the National Fire Protection Association (NFPA) Code 57,
The Commission received no comments on the proposal.
The Commission adopts the new section under Texas Natural Resources
Code, §116.012, which authorizes the Commission to adopt rules and standards
relating to the work of compression and liquefaction, storage, sale or dispensing,
transfer or transportation, use or consumption, and disposal of compressed
natural gas or liquefied natural gas, and §116.013, which authorizes
the Commission to adopt by reference, in whole or in part the published codes
of nationally recognized societies as standards to be met in the design, construction,
fabrication, assembly, installation, use, and maintenance of CNG or LNG components
and equipment.
Statutory authority: Texas Natural Resources Code, §116.012 and §116.013.
Cross-reference to statute: Texas Natural Resources Code, Chapter 116.
Issued in Austin, Texas, on July 8, 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 July 8, 2003.
TRD-200304143
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Effective date: July 28, 2003
Proposal publication date: March 28, 2003
For further information, please call: (512) 475-1295
Chapter 25.
SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS
Subchapter O. UNBUNDLING AND MARKET POWER
Chapter 8.
PIPELINE SAFETY REGULATIONS
Subchapter D. REQUIREMENTS FOR HAZARDOUS LIQUIDS PIPELINES ONLY
Chapter 9.
LP-GAS SAFETY RULES
Chapter 12.
COAL MINING REGULATIONS
Chapter 13.
REGULATIONS FOR COMPRESSED NATURAL GAS (CNG) AND LIQUEFIED NATURAL GAS (LNG)
Subchapter G. GENERAL APPLICABILITY AND REQUIREMENTS
Chapter 14.
REGULATIONS FOR LIQUEFIED NATURAL GAS (LNG)
Part 2.
PUBLIC UTILITY COMMISSION OF TEXAS