| (C) Following an initial annulus pressure test, the
operator must continuously monitor injection pressure, rate, temperature,
injected volumes and mass, and pressure on the annulus between tubing
and long string casing to confirm that the injected fluids are confined
to the injection zone. If mass is determined using volume, the operator
must provide calculations.
(D) At least once per year until the injection well
is plugged, the operator must confirm the absence of significant fluid
movement into a USDW through channels adjacent to the injection wellbore
(external integrity) using a method approved by the director (e.g.,
diagnostic surveys such as oxygen-activation logging or temperature
or noise logs).
(E) The operator must test injection wells after any
workover that disturbs the seal between the tubing, packer, and casing
in a manner that verifies internal mechanical integrity of the tubing
and long string casing.
(F) An operator must either repair and successfully
retest or plug a well that fails a mechanical integrity test.
(2) Mechanical integrity testing plan. The applicant
must prepare and submit a mechanical integrity testing plan as part
of a permit application. The performance tests must be designed to
demonstrate the internal and external mechanical integrity of each
injection well. These tests may include:
(A) a pressure test with liquid or inert gas;
(B) a tracer survey such as oxygen-activation logging;
(C) a temperature or noise log;
(D) a casing inspection log; and/or
(E) any alternative method approved by the director,
and if necessary by the Administrator of EPA under 40 CFR §146.89(e),
that provides equivalent or better information approved by the director.
(i) Operating information.
(1) Operating plan. The applicant must submit a plan
for operating the injection wells and the geologic storage facility
that complies with the criteria set forth in §5.206(d) of this
title, and that outlines the steps necessary to conduct injection
operations. The applicant must include the following proposed operating
data in the plan:
(A) the average and maximum daily injection rates,
temperature, and volumes and/or mass of the CO2 stream;
(B) the average and maximum surface injection pressure;
(C) the sources of the CO2 stream
and the volume and/or mass of CO2 from
each source; and
(D) an analysis of the chemical and physical characteristics
of the CO2 stream prior to injection.
(2) Maximum injection pressure. The director will approve
a maximum injection pressure limit that:
(A) considers the risks of tensile failure and, where
appropriate, geomechanical or other studies that assess the risk of
tensile failure and shear failure;
(B) with a reasonable degree of certainty will avoid
initiation or propagation of fractures in the confining zone or cause
otherwise non-transmissive faults transecting the confining zone to
become transmissive; and
(C) in no case may cause the movement of injection
fluids or formation fluids in a manner that endangers USDWs.
(j) Plan for monitoring, sampling, and testing after
initiation of operation.
(1) The applicant must submit a monitoring, sampling,
and testing plan for verifying that the geologic storage facility
is operating as permitted and that the injected fluids are confined
to the injection zone.
(2) The plan must include the following:
(A) the analysis of the CO2 stream
prior to injection with sufficient frequency to yield data representative
of its chemical and physical characteristics;
(B) the installation and use of continuous recording
devices to monitor injection pressure, rate, temperature, and volume
and/or mass, and the pressure on the annulus between the tubing and
the long string casing, except during workovers;
(C) after initiation of injection, the performance
on a quarterly basis of corrosion monitoring of the well materials
for loss of mass, thickness, cracking, pitting, and other signs of
corrosion to ensure that the well components meet the minimum standards
for material strength and performance set forth in subsection (e)(1)(A)
of this section. The operator must report the results of such monitoring
semi-annually. Corrosion monitoring may be accomplished by:
(i) analyzing coupons of the well construction materials
in contact with the CO2 stream;
(ii) routing the CO2 stream
through a loop constructed with the materials used in the well and
inspecting the materials in the loop; or
(iii) using an alternative method, materials, or time
period approved by the director;
(D) monitoring of geochemical and geophysical changes,
including:
(i) periodic sampling of the fluid temperature, pH,
conductivity, reservoir pressure and static fluid level of the injection
zone and monitoring for pressure changes, and for changes in geochemistry,
in a permeable and porous formation near to and above the top confining
zone;
(ii) periodic monitoring of the quality and geochemistry
of a USDW within the AOR and the formation fluid in a permeable and
porous formation near to and above the top confining zone to detect
any movement of the injected CO2 through
the confining zone into that monitored formation;
(iii) the location and number of monitoring wells justified
on the basis of the AOR, injection rate and volume, geology, and the
presence of artificial penetrations and other factors specific to
the geologic storage facility; and
(iv) the monitoring frequency and spatial distribution
of monitoring wells based on baseline geochemical data collected under
subsection (c)(2) of this section and any modeling results in the
AOR evaluation;
(E) tracking the extent of the CO2 plume
and the position of the pressure front by using indirect, geophysical
techniques, which may include seismic, electrical, gravity, or electromagnetic
surveys and/or down-hole CO2 detection
tools;
(F) a demonstration of external mechanical integrity
pursuant to subsection (h)(2) of this section at least once per year
until the injection well is plugged, and, if required by the director,
a casing inspection log pursuant to requirements in subsection (h)(2)
of this section at a frequency established in the testing and monitoring
plan;
(G) a pressure fall-off test at least once every five
years unless more frequent testing is required by the director based
on site-specific information; and
(H) additional monitoring as the director may determine
to be necessary to support, upgrade, and improve computational modeling
of the AOR evaluation and to determine compliance with the requirements
that the injection activity not allow the movement of fluid containing
any contaminant into USDWs and that the injected fluid remain within
the permitted interval.
(k) Well plugging plan. The applicant must submit a
well plugging plan for all injection wells and monitoring wells that
includes the following:
(1) a proposal for plugging all monitoring wells that
penetrate the base of usable quality water and all injection wells
upon abandonment in accordance with §3.14 of this title (relating
to Plugging), in addition to the requirements of this section. The
proposal must include:
(A) the type and number of plugs to be used;
(B) the placement of each plug, including the elevation
of the top and bottom of each plug;
(C) the type, grade, and quantity of material to be
used in plugging and information to demonstrate that the material
is compatible with the CO2 stream; and
(D) the method of placement of the plugs;
(2) proposals for activities to be undertaken prior
to plugging an injection well, specifically:
(A) flushing each injection well with a buffer fluid;
(B) performing tests or measures to determine bottomhole
reservoir pressure;
(C) performing final tests to assess mechanical integrity;
and
(D) ensuring that the material to be used in plugging
must be compatible with the CO2 stream
and the formation fluids;
(3) a proposal for giving notice of intent to plug
monitoring wells that penetrate the base of usable quality water and
all injection wells. The applicant's plan must ensure that:
(A) the operator notifies the director at least 60
days before plugging a well. At this time, if any changes have been
made to the original well plugging plan, the operator must also provide
a revised well plugging plan. At the discretion of the director, an
operator may be allowed to proceed with well plugging on a shorter
notice period; and
Cont'd... |
