| (a) General permit conditions.
(1) Each condition applicable to a permit shall be
incorporated into the permit either expressly or by reference. If
incorporated by reference, a specific citation to the rules in this
chapter shall be given in the permit. The requirements listed in this
section are directly enforceable regardless of whether the requirement
is a condition of the permit.
(2) The permit may be modified, revoked and reissued,
or terminated for cause. The filing of a request by the permittee
for a permit modification, revocation and reissuance, or termination,
or a notification of planned changes or anticipated noncompliance,
does not stay any permit condition.
(b) General criteria. The director may issue a permit
under this subchapter if the applicant demonstrates and the director
finds that:
(1) the injection and geologic storage of anthropogenic
CO2 will not endanger or injure any existing
or prospective oil, gas, geothermal, or other mineral resource, or
cause waste as defined by Texas Natural Resources Code, §85.046(11);
(2) with proper safeguards, both USDWs and surface
water can be adequately protected from CO2 migration
or displaced formation fluids;
(3) the injection of anthropogenic CO2 will not endanger or injure human health
and safety;
(4) the construction, operation, maintenance, conversion,
plugging, abandonment, or any other injection activity does not allow
the movement of fluid containing any contaminant into USDWs, if the
presence of that contaminant may cause a violation of any primary
drinking water regulation under 40 CFR Part 142 or may otherwise adversely
affect the health of persons;
(5) the reservoir into which the anthropogenic CO2 is injected is suitable for or capable of
being made suitable for protecting against the escape or migration
of anthropogenic CO2 from the storage
reservoir;
(6) the geologic storage facility will be sited in
an area with suitable geology, which at a minimum must include:
(A) an injection zone of sufficient areal extent, thickness,
porosity, and permeability to receive the total anticipated volume
of the CO2 stream; and
(B) a confining zone that is laterally continuous and
free of known transecting transmissive faults or fractures over an
area sufficient to contain the injected CO2 stream
and displaced formation fluids and allow injection at proposed maximum
pressures and volumes without compromising the confining zone or causing
the movement of fluids that endangers USDWs;
(7) the applicant for the permit meets all of the other
statutory and regulatory requirements for the issuance of the permit;
(8) the applicant has provided a letter from the Groundwater
Advisory Unit of the Oil and Gas Division in accordance with §5.203(o)
of this title (relating to Application Requirements);
(9) the applicant has provided a letter of determination
from TCEQ concluding that drilling and operating an anthropogenic
CO2 injection well for geologic storage
or constructing or operating a geologic storage facility will not
impact or interfere with any previous or existing Class I injection
well, including any associated waste plume, or any other injection
well authorized or permitted by TCEQ;
(10) the applicant has provided a signed statement
that the applicant has a good faith claim to the necessary and sufficient
property rights for construction and operation of the geologic storage
facility for at least the first five years after initiation of injection
in accordance with §5.203(d)(1)(A) of this title;
(11) the applicant has paid the fees required in §5.205(a)
of this title (relating to Fees, Financial Responsibility, and Financial
Assurance);
(12) the director has determined that the applicant
has sufficiently demonstrated financial responsibility as required
in §5.205(b) of this title; and
(13) the applicant submitted to the director financial
assurance in accordance with §5.205(c) of this title.
(c) Permit conditions for injection well construction.
(1) Construction of anthropogenic CO
2 injection wells must meet the criteria in §5.203(e)
of this title.
(2) Within 30 days after the completion or conversion
of an injection well subject to this subchapter, the operator must
file with the division a complete record of the well on Commission
Form W-2, Oil Well Potential Test, Completion or Recompletion Report
and Log showing the current completion.
(3) Except in the case of an emergency repair, the
operator of a geologic storage facility must notify the director in
writing at least 30 days prior to conducting any well workover that
involves running tubing and setting packers, beginning any workover
or remedial operation, or conducting any required pressure tests or
surveys. Such activities shall not commence before the end of the
30 days unless authorized by the director. In the case of an emergency
repair, the operator must notify the director of such emergency repair
as soon as reasonably practical.
(d) Permit conditions for operating a geologic storage
facility.
(1) Operating plan.
(A) The operator must maintain and comply with the
approved operating plan.
(B) Prior to approval for the operation of a Class
VI injection well, the operator shall submit, and the director shall
consider, the following information:
(i) the final AOR based on modeling, using data obtained
during logging and testing of the well and the formation as required
by clauses (ii), (iii), (iv), (vi), (vii), and (x) of this subparagraph;
(ii) any relevant updates, based on data obtained during
logging and testing of the well and the formation as required by clauses
(iii), (iv), (vi), (vii), and (x) of this subparagraph to the information
on the geologic structure and hydrogeologic properties of the proposed
storage site and overlying formations, submitted to satisfy the requirements
of §5.203(c)(2) and (3) of this title;
(iii) information on the compatibility of the CO2 stream with fluids in the injection zones
and minerals in both the injection and the confining zones, based
on the results of the formation testing program, and with the materials
used to construct the well;
(iv) the results of the formation testing program required
by §5.203(f) of this title;
(v) final injection well construction procedures that
meet the requirements of §5.203(e) of this title;
(vi) the status of corrective action on wells in the
AOR;
(vii) all available logging and testing program data
on the well required by §5.203(f) of this title;
(viii) a demonstration of mechanical integrity pursuant
to §5.203(h) of this title;
(ix) any updates to the proposed AOR and corrective
action plan, testing and monitoring plan, injection well plugging
plan, post-injection storage facility care and closure plan, or the
emergency and remedial response plan submitted under §5.203(m)
of this subchapter, which are necessary to address new information
collected during logging and testing of the well and the formation
as required by this section, and any updates to the alternative post-injection
storage facility care timeframe demonstration submitted under §5.203(m)
of this title, which are necessary to address new information collected
during the logging and testing of the well and the formation as required
by this section; and
(x) any other information requested by the director.
(2) Operating criteria.
(A) Injection between the outermost casing protecting
USDWs and the well bore is prohibited.
(B) The total volume of CO2 injected
into the storage facility must be metered through a master meter or
a series of master meters. The volume and/or mass of CO2 injected into each injection well must be
metered through an individual well meter. If mass is determined using
volume, the operator must provide calculations.
(C) The operator must comply with a maximum surface
injection pressure limit approved by the director and specified in
the permit. In approving a maximum surface injection pressure limit,
the director must consider the results of well tests and, where appropriate,
geomechanical or other studies that assess the risks of tensile failure
and shear failure. The director must approve limits that, with a reasonable
degree of certainty, will avoid initiation or propagation of fractures
in the confining zone or cause otherwise non-transmissive faults or
fractures transecting the confining zone to become transmissive. In
no case may injection pressure cause movement of injection fluids
or formation fluids in a manner that endangers USDWs. The Commission
shall include in any permit it might issue a limit of 90 percent of
the fracture pressure to ensure that the Cont'd... |
