between formations above the injection zone and the fluids being
injected. Typically a portion of the wellbore in the injection zone is
left open or the casing is perforated to allow injected fluid to enter
into the injection zone.
    Inside the long string casing, injection tubing is run from the
surface to a depth within the injection zone. This tubing may be
engineered of steel, an alloy, fiberglass, or a composite material most
suitable for the injectate's composition. The tubing extends from the
wellhead down to the storage zone where it is sealed by a mechanical
device known as a packer. The area between the tubing and long string
casing is isolated and the fluid injected into the well can only enter
the geologic formation for which it is targeted. With this type of well
construction, the fluid within the well tubing has minimal contact with
the components of the well that protect USDWs.
    The space between the injection tubing and the long string casing
and above the packer is called the annulus. The annulus between the
wellhead and the packer is a water-tight space filled with a non-
corrosive fluid that helps to protect the inside of the casing and
outside of the tubing from damage due to chemical reactions. In
addition, monitoring the pressure of the annulus using standard
pressure devices can easily detect any leaks in the tubing, long string
casing, or packer.
    Due to the buoyancy of CO2, today's proposal includes
enhancements to typical deep well construction procedures to provide
additional barriers to CO2 leakage outside of the injection
zone. The proposal would require that surface casing for GS wells be
set through the base of the lowermost USDW and cemented to the surface.
The long-string casing would be cemented in place along its entire
length. GS wells would also be constructed with a packer that is set
opposite a cemented interval, at a location approved by the Director.
EPA seeks comment on the proposed GS well requirements for depth of
surface casing, the cementing of long-string casing, and construction
with a packer set opposite a cemented interval. EPA also seeks comment
on how the proposed grandfathering provisions for existing wells
(construction requirements) may affect compliance with the above,
proposed construction requirements.
    More information on well drilling may be found by consulting
various sources including the Department of Energy, the American
Petroleum Institute (API), and the Society of Petroleum Engineers
(SPE). Please consult information or links on EPA's Web site: http://
www.epa.gov/safewater/uic.html, or similar sources.
    Horizontal Well Construction: While horizontal well construction is
not typical in deep injection wells in the UIC program, there are
examples of horizontal well completions being used with success to
improve the production of EOR and ECBM operations (e.g., Westermark et
al., 2004; Sams et al., 2005). EPA understands that the In Salah
project in Algeria is using horizontal well construction for GS
purposes. Horizontal wells are constructed by use of a directional
drilling system, which generally consists of both a curve and lateral
drilling assembly. After the vertical portion of the well is
constructed, the curve drilling assembly is used to drill a curve of
prescribed radius to change the path from vertical to horizontal. The
lateral drilling assembly is then used to construct the horizontal
section, which can be lined or remain as an open hole. Importantly,
several horizontal sections can be completed stemming from a single
vertical completion.
    The use of horizontal wells for a GS project could provide several
benefits over vertical wells. Horizontal wells provide enhanced
connectivity with permeable sections of the formation, increasing
injectivity. The use of horizontal wells increases the sweep, or
formation contact area, of the injected CO2 plume, as
vertical channeling through high permeability regions is reduced.
Increasing the sweep results in enhanced residual-phase CO2
trapping and dissolution favorable for the purposes of permanent
storage. Horizontal wells also reduce the pressures needed to inject
any given volume of fluid. In addition, fewer vertical completions are
required with the use of horizontal wells, which reduces the number of
artificial penetrations in the formation through which fluid could
migrate, as well as reducing overall costs.
    EPA seeks comment on the merits of horizontal well drilling
techniques for GS wells and the applicability of well construction
requirements discussed in this proposal.
    Well Component Degradation: The potentially corrosive nature of the
injectate must be taken into consideration in the design and
construction of CO2 GS wells. The quality of the well
materials, proper well construction, composition and placement of
appropriate cement along the wellbore, and appropriate maintenance are
crucial, because a leaking annulus would be a significant route of
escape for CO2 (IPCC, 2005).
    CO2 mixed with water or impurities (NOX,
SOX and H2S) can be corrosive to well materials
and cements. Conventional cement formulations (e.g., Portland cement)
are potentially vulnerable to acid attack. Acid attack on the calcium
carbonate in cement can lead to altered permeability and mechanical
instability. Defects in the well cement, such as channels, cracks, and
microannuli (i.e., small spaces between the casing and cement) can
provide pathways for acid to migrate and accelerate degradation.
    Experience with CO2 injection for EOR includes the use
of acid-resistant cements. Cements with a reduced Portland content are
more resistant to acid because they contain less calcium carbonate
(CaCO3). Acid resistant cements can be formulated by adding
fly ash, silica fume (microsilica), latex, epoxy, or other substances.
Calcium phosphate cement is a blend of high-alumina cement, phosphate,
and fly ash that can retain integrity under conditions where other
cements lose a substantial portion of their weight, according to one
manufacturer (http://www.eandpnet.com/area/exp/153.htm).
    EPA examined available information to determine the rate at which
cement degrades in acidic environments. Laboratory studies provide
evidence of deterioration of cement and other well components due to
exposure to acid. For example, Duguid et al., (2004) performed a
laboratory study in which Portland cement experienced significant
damage within seven days. Similar experiments by Kutchko et al., (2007)
showed less cement alteration. Differences between these studies may be
due to different experimental conditions, such as temperature and
pressure.
    Limited results of field studies show clear evidence of reactions
between CO2 and well cement, but do not show such severe
corrosion. Cement samples from

a well at the Scurry Area Canyon Reef Operators Committee (SACROC) site
did not show serious degradation (Carey et al., 2007). In another
study, cement samples were collected and analyzed from a CO2
production well in a natural CO2 reservoir in Colorado
exposed to a CO2-water environment for 30 years (Crow et
al., 2008). The study found considerable reactions between the
CO2 and cement, and CO2 migration up the wellbore
along the cement-formation interface. However, the cement alteration
was not significant enough to enable CO2 migration through
the cement itself and the distance of CO2 migration along
the cement-formation interface was very limited. Although the field
corrosion looks surprisingly low, these are only limited examples.
Laboratory studies are conducted under aggressive chemical conditions
in an attempt to mimic the cumulative effects of long-term exposure to
CO2-rich formation fluids. Given the high injection rates,
long lifespan, and potential impurities in GS, careful selection of
acid-resistant materials and practices may be necessary.
    Metal components of the injection well, such as carbon steel, are
subject to corrosion. To minimize problems, Meyer (2007) recommends the
use of Grade 316 stainless steel. One company working on GS projects
indicates that they use stainless steel well casing to avoid corrosion
problems (Buller et al., 2004). Stainless steels consist of iron, small
amounts of carbon, and at least 10 percent chromium. Grade 316
stainless steel also contains molybdenum, which endows it with
corrosion resistance in a variety of corrosive media, although it is
subject to corrosion in warm chloride environments and to stress
corrosion cracking at warmer temperatures (above 60 degrees C).
According to the report, recovered CO2 injection well
components at the SACROC site in Texas were made of Grade 316 stainless
steel and did not exhibit signs of corrosion. Industry representatives
at the Technical Workshop on Well Construction and MIT noted that many
casing options (e.g., titanium and fiberglass casing) are available.
Useful packer products include swell-resistant elastomer materials such
as Buna-N and Nitrile rubbers (Meyer, 2007). Teflon and nylon are
options for anti-corrosion seals.
    The use of corrosion-resistant materials is crucial to the success
of long-term GS operations. UIC program experience, industry
experience, and stakeholder input suggest that appropriate materials
are available. Today's proposal does not specify materials that may be
used, rather, proposes providing the owner or operator with the
flexibility to choose, as long as the materials used in GS wells are
corrosion-resistant and meet or exceed standards developed for such
materials by API or ASTM International, or comparable standards
approved by the Director. Well materials must be compatible with
injected fluids, including any co-injected impurities or additives,
throughout the life of the project, and be appropriate for the well's
depth, the size of the well bore, and the lithology of injection and
confining zones.
    GS projects are anticipated to have long lifespans in comparison to
other types of deep injection wells. Not only must GS wells be able to
function safely and properly over the lifespan of the GS project, but
they must be constructed such that USDWs remain protected after well
plugging. Today's proposal would require that the cements and cement
additives used in GS wells be appropriate to address long-term
injection of CO2 and assure that the well can maintain
integrity throughout the proposed life span of the project, including
the post-injection site care period and beyond once the well is
permanently plugged. Owners or operators must use corrosion-resistant
cement approved by the Director and be able to verify the integrity of
the cement using logs or other acceptable methods.
    EPA seeks comment regarding requirements for degradation-resistant
well construction materials, such as acid-resistant cements and
corrosion resistant casing.
4. Proposed Injection Well Operating Requirements
    EPA's operating requirements for deep injection wells provide
multiple safeguards to ensure that injected fluids do not escape and
are confined within the injection zone and that the integrity of the
confining zone is not compromised by non sealing artificial
penetrations or geologic features. In today's proposal, some well
operating requirements are consistent with existing UIC well types and
some requirements are tailored specifically for CO2
injection.
    Injection Parameter Limitations: Limitations on injection
parameters are intended to prevent the movement of injected or other
fluids to USDWs via fractures in confining layers or vertical
migration. In order to drive the injected fluids away from the well and
into the formation, fluids must be injected at a higher pressure than
the pressure of fluids in the injection zone. However, the sustained
pressure should not be as high as fracture pressure, that is, high
enough to initiate or propagate fractures in the injection or confining
zone. If the pressure within the reservoir becomes high enough, induced
stresses may reactivate existing faults (Rutqvist et al., 2007), though
injection pressure limitations may be employed to prevent this (Li et
al., 2006). Several geomechanical methods are available to assess the
stability of faults and estimate maximum sustainable pore fluid
pressures for CO2 storage. For example, one way of deriving
these is to calculate the effective stresses on faults and reservoir
rocks based on fault orientations, pore fluid pressures, and in-situ
stresses (Streit and Hillis, 2004).
    Today's proposal would require an injection pressure limitation
similar to existing UIC Class I deep well requirements. Owners or
operators of GS wells must limit CO2 injection pressures,
except during well stimulation, so that injection does not initiate new
fractures, propagate existing fractures in the injection zone, or cause
movement of injection or formation fluids that endanger USDWs. Under
this proposal, during injection, the pressure in the injection zone
must not exceed 90 percent of the fracture pressure of the injection
zone. Calculation of fracture pressure is fundamental to evaluating the
appropriateness of the site. The 90 percent requirement, suggested by
permit writers and IOGCC, provides an added margin of safety in the
well operation.
    There are some circumstances, however, where fracturing of the
injection zone would be acceptable provided the integrity of the
confining system remains unaffected. For example, hydraulic fracturing
is a process where a fluid is injected under high pressure that exceeds
the rock strength, and the fluid opens or enlarges fractures in the
rock. EPA recognizes that there may be well completions which require
intermittent treatments, including hydraulic fracturing of the
injection zone, to improve wellbore injectivity. Such stimulation of
the injection zone during a well workover (as defined in 40 CFR
144.86(d)) approved by the Director would be permissible.
    Fracturing of the confining zone would be prohibited at all times
during injection and/or stimulation.
    It is also possible that CO2 GS may be associated with
ECBM, where more extensive hydraulic fracturing would be necessary to
open pre-existing fractures in the coal and provide additional surfaces
onto which CO2 may adsorb and to extract methane. These
hydraulic fracturing operations are used to

enhance oil and gas recovery and for ECBM recovery, and in general are
exceptions to the definition of underground injection under the SDWA.
    EPA is requesting comment on the extent and scope to which
hydraulic fracturing should be allowed during GS injection, and whether
the use of fracturing for the purposes of well stimulation is
appropriate. EPA is also requesting information to better qualify the
use of fracturing for GS injection in specific geologic settings and
rock formation lithologies.
    Continuous Monitoring: Monitoring within the injection well system
is important to assure that the injection project is operating within
permitted limits. It can also protect the owner or operator's
investment, as significant divergences in any of these parameters could
damage well components. Deep injection well owners or operators
typically monitor injection pressure, flow rate, temperature, and
volumes. Owners or operators usually choose to maintain pressure on the
annulus between the tubing and the long string casing and monitor this
pressure to ensure protection of USDWs from well leakage. Monitoring is
generally performed on a continuous basis, through the use of automated
equipment that typically takes readings several times per minute and
records them in a computer system.
    Alarms and automatic shut-off devices connected to the monitoring
equipment can engage if operational limits are exceeded. Available
computer-driven monitoring systems have the ability to continuously
monitor injection parameters and engage the shut-off devices. Though
these systems are not required for all UIC well classes, the complexity
of GS operations and the potential for movement of the CO2
in the event of a mechanical integrity loss makes a shut-off system an
important safety consideration for GS projects.
    Traditionally, owners or operators have installed monitoring and
shut-off equipment at the wellhead (i.e., at the surface), however,
down-hole devices have been used in offshore applications for several
years. Today's proposal requires that automatic shut-off valves be
installed down-hole in addition to at the surface. This requirement is
supported by many participants at the technical workshops and the
IOGCC's recommendations.
    The down-hole valves provide a safety backstop in case damage to
the wellhead prevents the proper operation of wellhead shut-off valves.
Direct pressure measurements used to trigger shut-off devices are more
accurate than wellhead calculations of down-hole pressure. The down-
hole valves are an integral part of the tubing string and can be
positioned anywhere along the tubing string. Gauges can be either
inside or outside of the casing; installation on the outside of the
casing may cause less interference with well maintenance. The down-hole
valves are kept in an open position by hydraulic pressure from a
connection to the surface. Damage to the wellhead or an upset in
operations causes the positive hydraulic pressure to fall, forcing the
valve into a ``failsafe'' closed position. In case of well failure, a
down-hole shut-off device would isolate the injectate below USDWs,
rather than just below the surface. By engaging near the injection
zone, they can prevent pressure-induced damage to the well casing. This
would also require less expensive repairs if pressure exceedances were
to occur.
    While there would be some cost and downtime associated with
replacing failed down-hole valves, such costs are considered small in
comparison to the costs if large amounts of CO2 should
escape into USDWs or to the surface. It is possible to place a new
valve down-hole without removing the existing valve, so downtime can be
minimized if an appropriate parts inventory is kept on hand. A
Norwegian study found that the failure rate of down-hole safety valves
was 2 failures per million operating hours (Norwegian Oil Industry
Association, 2001). This is a relatively low failure rate as the valves
are designed to withstand harsh conditions and operate well after years
of inactivity. Overall, it is likely that costs for replacing failed
valves would be insignificant in comparison with costs of a
CO2 leak.
    Several types of valves are available and in use, including
flappers and ball valves. The flapper types seem to be more reliable,
at least for oilfield applications (Garner et al., 2002). EPA seeks
comment on the merits of requiring down-hole shut-off valves in GS
wells.
    Corrosion Monitoring and Control: Existing UIC Class I deep well
operating requirements allow Director's discretion to require corrosion
monitoring and control in the case of corrosive fluids. Corrosion
monitoring can help avoid or provide early warning of corrosion of well
materials that could compromise the well's integrity. This is
accomplished by exposing ``coupons,'' or small samples of the well
material to the injection stream. The samples are periodically removed
from the flow line, cleaned and weighed; the weight is compared to
previous values to calculate a corrosion rate. Other methods of
corrosion monitoring/control include: The use of wireline enhanced
caliper or imaging logs to inspect the casing, the use of ultrasonic
and electromagnetic techniques in well pipes (Brondel et al., 1994),
the use of cathodic protection (where the casing would become the
cathode of an electrochemical cell), or the use of biocide/corrosion
inhibitor fluid in the annular space between the casing and tubing.
    CO2 reacts with water to become acidic, potentially
accelerating corrosion of well materials. The CO2 stream for
a GS project may also contain small volumes of impurities that could be
corrosive. Thus, EPA is proposing to require corrosion monitoring for
GS wells. Corrosion monitoring is further discussed in the monitoring
and testing section of this preamble.
    Injection Depth in Relation to USDWs: Today's proposal specifies a
requirement that such injection should be allowed only beneath the
lowermost formation containing a USDW. This is consistent with the
siting and operational requirements for all Class I hazardous injection
wells, and a very important protective component of the UIC program.
Placing distance between the point of injection and USDWs allows for
the necessary confining and buffer formations, and further provides for
opportunity for additional monitoring to detect any excursions from the
intended injection zone.
    However, EPA is not prescribing a minimum injection depth to keep
the CO2 in a supercritical, liquid state after it is
injected, as some well operators may choose to inject the
CO2 as a gas. If the trapping mechanism is sufficiently
protective, the injected CO2 should be contained regardless
of its phase.
    Some stakeholders and co-regulators have proposed other approaches
for specifying an injection depth and these merit consideration by EPA.
For example, one approach would be to require a minimum injection depth
of approximately 800 m (2,625 feet) for GS of CO2. The
geothermal gradient and weight of the fluid and rock layers above this
target depth would maintain CO2 at a sufficiently high
pressure to keep it in a supercritical, liquid state. Storing
CO2 at supercritical pressure would allow storage of greater
volumes and thereby increase available underground storage capacity.
Additionally, storing CO2 in a supercritical, liquid state
may prevent the frequency of well mechanical integrity failure. When
supercritical CO2 is injected into shallow formations where
pressures are not high enough to

maintain its supercritical state, it will revert to a gas. The
expansion of gaseous CO2 will cause a drop in temperature
(the Joule-Thomson effect), and if this temperature drop is large
enough, freezing and thermal shock may take place in the vicinity of
the well. Thermal shock is a common cause of cracking in many types of
pressure equipment, and repeated exposure to such stresses could
compromise the integrity of the injection well's tubular components.
Participants at the Technical Workshop on Well Construction and MIT
suggested that these phase changes (i.e., supercritical liquid to gas)
are potentially a greater mechanical integrity concern than
corrosivity. Modeling by Oldenburg (2007) shows that if the pressure
drop is not large (less than 10 bars), this effect will not be great
enough to cause significant problems. However, technical workshop
participants concluded that more research is needed on the effects of
phase changes on well mechanical integrity.
    EPA is aware that the proposed requirement of injecting
CO2 below the lowermost USDW may preclude injection into
certain targeted geologic formations, which may be storage sites
currently under consideration for GS. These formations may include
unmineable coal seams (those not being used for Class II enhanced coal
bed methane production), zones in between or above USDWs, and other
formations also under consideration. In areas of the country with very
deep USDWs, the need to construct GS wells beneath them may render GS
technically impractical. As a result, the Agency is considering and
requesting comment on alternative approaches that would allow injection
between and/or above the lowermost USDW, and thus potentially allow for
more areas to be available for GS while preventing USDW endangerment.
    One alternative under consideration is a provision for Director's
discretion to allow injection above or between USDWs in specific
geologic settings where the depth of the USDWs may preclude GS, make GS
technically challenging, or significantly limit CO2 storage
capacity. Such approval by the Director would allow injection between
USDWs (and thereby allowing injection above the lowermost USDW) in
circumstances in which it may be demonstrated that USDWs would not be
endangered. An example where such injection may be appropriate presents
itself in areas such as the Williston and Powder River Basins in
Wyoming, North Dakota, and South Dakota, where receiving formations
(formations with large CO2 storage capacity) for GS have
been identified above the lowermost USDW and where there may be
thousands of feet of rock strata between the injection zone and the
overlying and underlying USDWs. In these cases, injection above or
between USDWs may be appropriate, however, the Agency currently lacks
data to demonstrate that such practices are or are not protective of
USDWs.
    Also, EPA is considering allowing Directors to exempt all USDWs
below the injection zone. Currently, Directors may issue ``aquifer
exemptions'' which when approved, essentially determine that an aquifer
is no longer afforded protection as a USDW, in accordance with the
requirements of 40 CFR 144.7(b)(1). Aquifer exemptions are permitted
for mineral or hydrocarbon exploitation by Class III solution mining
wells, or by Class II oil and gas-related wells, respectively, and when
there is no reasonable expectation that the exempted aquifer will be
used as a drinking water supply (please see specific aquifer exemption
criteria at 40 CFR 146.4). When EPA exempts an aquifer, it is no longer
considered a USDW now or in the future. EPA limits aquifer exemptions
for injection operations to the circumstances where the necessary
criteria at 40 CFR 146.4 are met and not, in general, for the purpose
of creating additional capacity for the emplacement of fluids.
    EPA carefully considers all aspects of ensuring the protection of
USDWs before approving an aquifer exemption request for any injection
purpose in UIC programs which it implements. The Agency's
interpretation of the SDWA, and its own UIC regulations, currently
allows for aquifer exemptions sought for specific reasons (as outlined
above) and not solely for the purpose of relaxing well owner/operator
requirements, such as operating, monitoring, or testing. Therefore, in
general, the Agency does not consider aquifer exemption requests for
non-injection formations. It has also been EPA's long-standing policy
not to grant aquifer exemptions for the purpose of hazardous waste
disposal because of the infeasibility of meeting Class I hazardous
waste siting requirements (i.e., injection must be below the lowermost
USDW).
    However, aquifer exemptions could be issued for GS wells where
receiving formations are situated above the lowermost USDW and where
there are thousands of feet between the injection zone and the
overlying and underlying USDWs. In these circumstances, the permit
applicant would be required to meet all Class VI permit requirements.
    It is also anticipated that some aquifers previously exempted for
Class II injection operations may be appropriate formations for GS and
permit applicants may seek to use these formations. In such
circumstances, the permit applicant for a GS Class VI well would be
required to seek a new aquifer exemption for the purpose of GS, and
provide a non-endangerment demonstration that reflects the predicted
extent of the CO2 plume, the associated pressure front, and
the scope of the injection activities.
    Furthermore, there may be other geologic settings with formations
that could receive and store CO2 that are not below the
lowermost USDW. Such formations include deep, marginal USDWs directly
overlying crystalline basement rock and/or unmineable coal seams. Under
today's proposal, these formations would not qualify for GS without
aquifer exemptions. In these areas where USDWs directly overlie
crystalline basement rock, permit applicants may seek aquifer
exemptions and permits to inject CO2 for GS into these
exempted aquifers. In unmineable coal seams that are USDWs or contain
or are bounded by formations that are USDWs, permit applicants may also
seek aquifer exemptions and permits for GS.
    In summary, EPA is soliciting comment on whether CO2
injection should be allowed into an injection zone above the lowermost
USDW, when the Director determines that geologic conditions (e.g.,
thousands of feet of intervening formations between the injection zone
and the overlying and/or underlying USDWs) exist that will prevent
fluid movement into adjacent USDWs. EPA is also requesting comments on
whether aquifer exemptions should be allowed for the purpose of Class
VI injection, and under what conditions should such aquifer exemptions
be approved. Finally, EPA seeks comment on whether the Agency should
set a minimum injection depth requirement for CO2 GS, rather
than require that such injection take place below the lowermost USDW.
    Tracers: While the UIC Program's protective elements greatly reduce
the potential for leakage, leakage is a possibility in any underground
injection project. Tracers may help facilitate leak detection. Though
use of tracers is not required under existing deep well requirements,
the buoyancy of CO2 and the large volumes that are expected
to be injected may warrant improved leak detection for GS wells.
Detection of leakage of injected CO2 at the surface would
indicate potential endangerment to USDWs. Additionally, if tracers are

used for CO2 GS projects, they may also help owners or
operators to infer geochemical processes caused by CO2
(e.g., dissolution or precipitation of calcium carbonate) that may pose
risks.
    Gaseous CO2 is odorless and invisible. Tracers can be
odorants, such as those added to domestic natural gas, in order to
serve as a warning of a natural gas leak. Mercaptans are the most
effective odorants, however, they are not generally suitable for GS
because they are degraded by oxygen, even at very low concentrations.
The experience from the natural gas storage industry is that they are
scrubbed from the gas by adsorption to the formation in the subsurface.
Disulphides, thioethers and ring compounds containing sulfur are
options for CO2 GS odorants (IPCC, 2005). However, there has
been no testing of these substances for GS, and it is unknown whether
using them for GS would be effective.
    Participants at the technical workshop on monitoring, measurement,
and verification (MMV) discussed the use of tracers in monitoring.
Measurement of stable isotopes of carbon (i.e., C12/C13 ratio) can
serve as tracers and may be useful for identifying the source of
CO2 (e.g., anthropogenic or biological). Panelists also
addressed the potential utility of perfluorocarbon (PFC) and other
inert tracers in detecting CO2 leakage. According to some
researchers, PFCs are conservative and will remain with the
CO2. Unique suites (or batches) of PFCs can be created using
different combinations of PFCs. Different PFC suites can be used to
establish unique signatures for different time periods of prolonged
injection or for multiple CO2 injections, making it feasible
to detect if a leak is transient versus long-term in nature.
    There may be potential benefits of tracers for CO2 GS
operations, though tracers' effectiveness and cost-effectiveness are
debated. There are also technical challenges, such as false positives,
associated with their use that will vary on a case-by-case basis. In
addition, in the case of PFCs, which have a global warming potential
many orders of magnitude higher than CO2, there may be
concerns about the consequences of potential releases to the
atmosphere. Today's proposal allows Directors' discretion on whether to
require the use of tracers, and if so, what types of tracers. EPA seeks
comment on the use of tracers in CO2 GS operations, and any
potential impact of tracers on human health or ecosystems as they
relate to USDWs.
5. Proposed Mechanical Integrity Testing Requirements
    Injection well mechanical integrity testing (MIT) is a critical
component of the UIC Program's goal to protect USDWs. Testing and
monitoring the integrity of an injection well, at the appropriate
frequency, can verify that the injection activity is operating as
intended and does not endanger USDWs. MIT requirements for GS wells
should be tailored to address the unique properties of CO2,
specifically its buoyancy and potential corrosivity, so that owners or
operators of GS projects will be able to detect defects within the
well, and between the well and the borehole, before these defects could
allow GS-related fluids to move into unintended formations or toward
USDWs.
    Currently, all UIC injection well owners or operators must
demonstrate that their wells have both internal and external mechanical
integrity (MI) (40 CFR 146.8). An injection well has internal MI if
there is an absence of leakage in the injection tubing, casing, or
packer. Typically, internal mechanical integrity testing is
accomplished with a periodic pressure test of the annular space between
the injection tubing and long string casing of this annual space.
Usually, loss of internal MI is due to corrosion or mechanical failure
of the injection well's components. Rarely, because of the multiple-
barrier nature of injection well construction, do internal MI losses
result in leakage outside of the well and present an endangerment to a
USDW.
    Injection well external integrity is demonstrated by establishing
the absence of fluid flow along the outside of the casing, generally
between the cement and the well structure, although such flow may also
occur between the cement and the well bore itself. This is typically
accomplished through the use of down-hole geophysical logs or surveys
designed to detect such leaks, once every five years. Failure of an
external MIT can indicate improper cementing or degradation of the
cement that was emplaced to fill and seal the annular space between the
outside of the casing and the well borehole. This type of failure can
lead to movement of injected fluids out of intended injection zones and
toward USDWs. As with internal MI failure, temporary loss of external
MI rarely results in endangerment to USDWs.
    Failure of either external or internal mechanical integrity may
mean that one of the multiple protective layers in an injection well is
not operating as intended. Proper testing can serve as an early warning
to owners or operators that the well is not performing optimally and
that maintenance or repair of a component of the well is needed before
the injectate moves to unintended zones or a USDW is impacted.
    The decades of State and EPA experience with Class I and Class II
mechanical integrity testing requirements provides the best knowledge
base for identifying appropriate MIT requirements for GS projects. This
is supported by findings from technical workshops, conferences, and
research. However, because of the buoyant and corrosive properties of a
GS stream, current deep well internal and external MIT requirements
will need to be tailored in order to ensure the protection of USDWs.
    As previously discussed, internal MI testing is designed to
evaluate the condition of internal well components. The evaluation is
typically accomplished with an annual pressure test. However, due to
the nature of the GS injection stream, corrosivity must be considered
when planning for MITs in GS projects. Studies conducted by EPA of
previous MIT results suggest that wells injecting corrosive fluids fail
MITs at rates 2 to 3 times higher than those that inject non-corrosive
fluids. Thus, a more corrosive injectate is a potential risk factor for
MIT failure.
    Therefore, today's proposal would require owners or operators of
Class VI GS projects to monitor internal mechanical integrity of their
injection wells by continuously monitoring injection pressure, flow
rate, and injected volumes, as well as the annular pressure and fluid
volume to assure that no anomalies occur that may indicate an internal
leak. EPA requests comment on the practicability of this requirement.
    Continuous internal mechanical integrity monitoring of GS project
injection wells, instead of periodic testing (which is required for
most other types of deep injection wells) is important because the
corrosive nature of GS waste streams makes immediate identification of
corrosion-related well integrity loss critical. Today's proposal would
also require automatic down-hole shut-off mechanisms (see proposed
injection well operating requirements section) in the event of an MI
loss. Continuous computer-driven monitoring of internal MI would need
to be performed in order for automatic shut-off systems to be
activated. This combination of computer-driven continuous internal
monitoring linked to an automatic down-hole injection shut-off provides
the maximum protection to USDWs and the earliest

warning to owners or operators that repairs need to be performed.
    This proposed requirement would eliminate the necessity of
conducting other periodic internal MITs. However, today's proposal
would provide the Director with the discretion to request any other
additional tests necessary to ensure the protection of USDWs.
    As mentioned above, external mechanical integrity testing is used
to determine the absence of fluid leaks behind the long string casing.
Instead of requiring external MI to be demonstrated every five years
(which is typical for other types of deep injection wells), today's
proposal would require owners or operators of CO2 wells to
demonstrate injection well external mechanical integrity at least once
annually. This increase in testing frequency (from once every five
years to once a year) is justifiable for the protection of USDWs given
the potential corrosive effects on injection well components (steel
casing and cement) that are exposed to the GS stream and the buoyant
nature of the injected fluid that tends to force it upward toward
USDWs.
    Today's proposal does not change the existing allowable methods for
demonstrating external MI in deep injection wells. They would include
the use of a tracer survey, a temperature or noise log, a casing
inspection log if required by the Director, or an alternative approved
by the Administrator and, subsequently, the Director. Today's proposal
would also provide the Director with the discretion to request
additional tests.
    EPA proposes that owners or operators report semi-annually on the
injection pressure, flow rate, temperature, volume and annular
pressure, and on the results of MITs. This reporting frequency, which
is the same as for other deep injection well classes, has proven to be
timely for notification to permitting authorities on the status of the
operation.
    EPA seeks comment on the appropriate frequency of internal and
external MITs for GS injection wells, the appropriate types of MITs,
and how to optimize MIT methods for GS.
6. Proposed Plume and Pressure Front Monitoring Requirements
    Monitoring associated with UIC injection wells is required to
ensure that the injectate is safely confined in the intended subsurface
geologic formations and USDWs are not endangered. Certain existing UIC
program monitoring requirements apply to all wells, while others are
based on site-specific information and Director's discretion.
Information obtained through monitoring may be used to maintain the
efficiency of the storage operation, minimize costs, and confirm that
injection zone pressure decline follows predictions. Monitoring results
of GS wells would also be used as data inputs for reevaluation of the
site computational model and AoR and corrective action.
    EPA considers CO2 plume and associated pressure front
monitoring to be necessary for verification of model predictions. An
integrated monitoring and modeling strategy should be used to track the
evolution of the CO2 plume and associated pressure front.
Monitoring may be conducted with a combination of direct and indirect
techniques appropriate for the conditions of specific GS projects.
Monitoring is necessary to verify initial model predictions given the
uncertainty of CO2 fate and transport; because large volumes
of CO2 will be injected during GS operations; and because of
the challenges of comprehensive site characterization in large
formations that may be used for GS projects. Monitoring results should
be used to assess CO2 movement through high-permeability
regions (i.e., faults, fractures) not detected in site characterization
and included in initial site modeling. Early pilot-projects have
indicated that the most complete understanding of the site-specific
behavior of CO2 will result from monitoring the movement of
CO2 itself (e.g., Doughty et al., 2007).
    EPA seeks comment on the requirement for monitoring of GS sites for
the purpose of tracking the location of the CO2 plume and
associated pressure front over time.
    Testing and Monitoring Plan: A monitoring program for a GS project
should be designed to detect changes in ground water quality and track
the extent of the CO2 plume and area of elevated pressure.
Today, EPA is proposing that owners or operators of Class VI wells
would submit, with their permit application, a testing and monitoring
plan to verify that the GS project is operating as intended and is not
endangering USDWs. This plan would be implemented upon Director
approval and would include, at a minimum, analysis of the chemical and
physical characteristics of the CO2 stream; monitoring of
injection pressure, rate, and volume; monitoring of annular pressure
and fluid volume; corrosion monitoring; a demonstration of external
mechanical integrity (see proposed mechanical integrity testing
requirements section of the preamble); a determination of the position
of the CO2 plume and area of elevated pressure; monitoring
of geochemical changes in the subsurface; and, at the discretion of the
Director, monitoring for CO2 fluxes in surface air and soil
gas, and any additional tests requested by the Director.
    Monitoring within multiple layers (i.e., in the primary confining
system; in USDWs and other shallow layers; and, at the surface)
supports a multi-barrier approach to protecting USDWs. Surface air and/
or soil gas monitoring may be used as the last line of monitoring to
ensure that there has not been vertical CO2 leakage, which
could endanger USDWs. The program should also be site-specific, based
on the identification and assessment of potential CO2
leakage routes complemented by computational modeling of the site.
    Under today's proposal, owners or operators would be required to
analyze the CO2 stream at a frequency sufficient to yield
data representative of its chemical and physical characteristics. This
analysis will provide information on the content and corrosivity of the
injected stream, which in turn will support improvements in well
construction and optimization of well operating parameters. EPA also
proposes that owners or operators would monitor well materials for
signs of corrosion, such as loss of mass, thickness, cracking, or
pitting. The proposed requirements are critical to address the
potential well integrity concerns associated with the corrosive nature
of the CO2 stream, to avoid (or provide early warning of)
corrosion of well materials, and to protect the integrity of GS wells.
Today's proposal would also require continuous monitoring of the
injection pressure, rate and volume, as well as annular pressure and
fluid volume discussed in the well construction and operation section
of the preamble.
    Monitoring CO2 Movement and Reservoir Pressure:
Monitoring subsurface geochemistry and the position of the
CO2 plume and pressure front are necessary to verify
predictions of plume movement, provide inputs for modeling, identify
needed corrective actions, and target geochemical and surface
monitoring activities.
    Under today's proposal, owners or operators would be required to
track the subsurface extent of the CO2 plume and pressure
front using pressure gauges in the first formation overlying the
confining zone or using indirect geophysical techniques (e.g., seismic,
electrical, gravity, or electromagnetic surveys) or other down-hole
CO2 detection tools, monitor for geochemical changes in
subsurface formations, and if directed, monitor at the surface. Today's

proposal would also require owners or operators to monitor ground water
quality and geochemical changes above the confining system. The results
of this monitoring would be compared to baseline geochemical data to
identify changes that may indicate unacceptable movement of
CO2 or formation fluids.
    In order to provide guidance related to monitoring of GS sites, EPA
invited expert advice and reviewed technical documentation. EPA held a
technical workshop on measurement, monitoring, and verification focused
on the availability and utility of various subsurface and near-surface
monitoring techniques that may be applicable to GS projects. This
workshop, co-sponsored by the Ground Water Protection Council (GWPC),
took place in New Orleans, LA, on January 16, 2008.
    Monitoring within the confining zone for pressure, pH, salinity, or
the presence of dissolved minerals, heavy metals, or organic
contaminants requires direct access to the subsurface via monitoring
wells. Wells installed for this purpose would be strategically placed
in areas predicted to overlie the eventual CO2 plume and
area of elevated pressure. Well number and placement would be based on
project specific information such as injection rate and volume, site
specific geology, baseline geochemical data, and the presence of
artificial penetrations. Predictive models of the extent and direction
of plume movement can support decisions about monitoring well
placement. This has the dual benefit of targeting resources associated
with what is an expensive monitoring activity and minimizing the number
of artificial penetrations near the injection well, which could
potentially become conduits for fluid movement into USDWs.
    Today's proposal would require that owners or operators perform a
pressure fall-off test at least once every five years. Pressure fall-
off tests are designed to ensure that reservoir injection pressures are
tracking to predicted pressures and modeling input. They may be used in
project siting and AoR calculations. Results of pressure fall-off tests
may indicate mischaracterization of the site specific geology and
potentially unidentified leakage pathways. EPA seeks comment on the use
and frequency of pressure fall-off testing for GS wells.
    Pressure monitoring, both at the surface and in the formation, is a
routine part of CO2 injection projects that serves several
purposes. For instance, monitoring pressure in injection wells allows
for use of shut-off valves in the event that injection pressure exceeds
the formation fracture pressure, or pressure drop-offs indicate a
subsurface leak (IPCC, 2005). Pressure monitoring in monitoring wells
provides an indication of whether there is potential for brine
intrusion into USDWs and CO2 leakage. When combined with
information on temperature, pressure data provide an indication of the
phase (e.g., gas, supercritical) and amount of the injected
CO2.
    Various pressure sensors are available, and monitoring can be
conducted continuously. Conventional sensor types include piezo-
electric transducers, strain gauges, diaphragms, and capacitance gauges
(Burton et al., 2007). Fiber optic pressure and temperature sensors are
also now commercially available and can be installed down-hole and
connected to the surface through fiber optic cables. According to
Burton et al. (2007), current monitoring technologies are more than
adequate for monitoring pressure in a GS project.
    Direct geochemical monitoring is an important part of a monitoring
program. Temperature, salinity, and pH should be monitored, as these
parameters provide basic information for understanding water and gas
geochemistry. Additionally, obtaining ground water samples via
monitoring wells allows direct measurement of aqueous and pure-phase
CO2. By studying the interactions between brine and
CO2, it can be determined whether precipitation and/or
dissolution of minerals is occurring (Nicot and Hovorka, 2008). These
analyses will also indicate the rate of CO2 trapping
mechanisms, and whether mineral dissolution may be causing permeability
changes in the formation or impacting USDWs. Geochemical monitoring may
also be conducted for heavy metals and organic contaminants that may
potentially be mobilized in the formation due to injection.
    Information and discussions from EPA technical and public workshops
indicate that the collection of adequate baseline (pre-injection) data
is critical for planning monitoring and for detecting CO2
movement and leakage during and after injection.
    While the use of tracers is not a specific monitoring requirement
in today's proposal (per III.A.4), some Directors may require owners or
operators to use them. EPA has considered the merits of tracers for
CO2 monitoring and recognizes that they may also be
voluntarily employed by owners or operators. Tracers can also be
measured through direct geochemical sampling to indicate the speed and
direction of movement of CO2 after injection. Naturally
occurring tracers include stable isotopes (atoms of a particular
element with different numbers of neutrons) of carbon and oxygen.
Analyses of the amounts of carbon-13 and oxygen-18 isotopes in water
are commonly used to track movement through the environment and to
elucidate geochemical processes. It is also possible to include
tracers, such as perfluorocarbons or noble gases, with the injected
CO2 (Nimz and Hudson, 2005). Loss of tracers between the
injection well and monitoring well may indicate diffusion into low-
permeability materials, sorption, partitioning into non-aqueous phase
liquids, partitioning into trapped gas phases, or leakage of
CO2 (Nicot and Hovorka, 2008). Tracers were more fully
discussed in the well construction and operation section of the
preamble.
    There are several technical challenges associated with in-situ
monitoring of formation fluids via wells. In the course of sample
retrieval, there will be pressure changes, causing changes in
CO2 solubility and pH. To address this, LBNL developed a
``U-tube'' sampling apparatus to enable collection of fluid and gas
samples at in-situ pressure conditions. Also, samples collected from
monitoring wells are point measurements that may not fully represent
the entire reservoir, especially if there are extensive physical
heterogeneities.
    Geophysical Methods for Plume Tracking: Various non-invasive deep
subsurface monitoring techniques are available to track the movement of
the CO2 plume. Many of these methods have been developed for
use in the oil and gas industry, and some may also support certain
aspects of baseline geologic characterization. Seismic and electrical
techniques have been used to gather data related to rock composition,
porosity, fluid content, and in-situ stress state.
    In seismic surveying, a controlled source of seismic energy is used
to send vibrations through the ground. The time it takes for the
seismic waves to reflect off of a subsurface feature and reach a
receiver at the surface provides information about the depth of the
feature. By using an array of receivers, possible plume and leakage
flowpaths may be discerned. Seismic surveys may also be useful for
monitoring how rock properties change with time during injection and
for mapping of the CO2 plume. This method has been used to
study the subsurface in the area near the injection well for the
CO2-SINK project in Germany (Juhlin et al., 2006) and at the
Sleipner and In Salah sites. Seismic

studies can also be done in a crosswell arrangement by placing an array
of receivers in one borehole and drawing a seismic source upwards in
another borehole, firing at periodic intervals. Current crosswell
experience relevant to CO2 sequestration includes successful
imaging of CO2 saturation and pressure effects in a
carbonate reservoir in West Texas (Harris and Langan, 2001). Vertical
seismic profiling (VSP), conducted by placing geophones in a vertical
array inside a borehole and measuring sound sources originating at the
surface, is another promising technology for plume detection and
monitoring.
    Electrical methods rely on the electrical properties of the medium
being studied and offer promise for CO2 plume monitoring.
Electromagnetic (EM) surveys induce a current in subsurface materials,
and conductivity meters detect areas with increased conductivity. Near
the surface, EM can detect buried metal objects and contaminated soils.
In the deeper subsurface, EM surveys can be used to detect certain
contaminant plumes. EM surveys can also be done in crosswell fashion.
At Lawrence Livermore National Laboratory, researchers are conducting a
long-term study using time-lapse multiple frequency EM survey
characterization to image CO2 injected as part of an EOR
operation (Kirkendall and Roberts, 2001).
    Electrical resistance tomography (ERT) measures electrical
resistance by means of electrodes that may be placed at the surface,
but are more commonly arrayed down boreholes in a crosswell
configuration. Because the electrical properties of a medium are
sensitive to fluid chemistry, ERT can be used for monitoring fluid
migration in the subsurface. The oil industry has used ERT, and it has
been also used for environmental applications such as detection of
contaminant plumes at waste sites. Newmark (2003) reported preliminary
data on the use of crosswell ERT at an EOR site to monitor for
CO2.
    Microgravity surveys detect density variations in the subsurface
using sensitive gravity measurements made at the (ground) surface.
Microgravity surveys have been used to characterize subsurface
formations, and given the density differences between CO2
and formation brines, may be useful for tracking a CO2
plume. Nooner et al. (2003) discuss use of microgravity surveys at the
Sleipner CO2 GS project in Norway.
    GEO-SEQ (2004) discusses the capabilities of seismic and electrical
crosswell methods for CO2 GS. The authors note the high
spatial resolution of these methods and state that they can image leaks
and fluid saturation within a reservoir. Simulations discussed in the
manual confirm that seismic and electrical conductivity crosswell
methods could provide information on the saturation of CO2
within the reservoir between wells. The authors note that seismic
crosswell methods could also be used to detect CO2 phase
changes. Although these methods are costly and time consuming, they may
prove useful at GS sites in the future. To fully implement these
technologies, additional research is needed regarding the electrical
and seismic properties of subsurface media containing CO2.
    Some stakeholders expressed concerns about the usefulness of
seismic surveys as a CO2 tracking tool under certain
geologic conditions, particularly given the cost of specific
technologies. Based on information evaluated to date, EPA believes that
tracking the plume and pressure front is an important companion step to
address any uncertainties associated with initial AoR modeling and
requests comment on this approach and more efficient alternatives that
may be used to track the plume and pressure front.
    As such, allowing flexibility in choosing the plume tracking
methods and other monitoring technologies may provide an appropriate
balance between the protective nature of indirect monitoring and cost
considerations, as well as allowing for the adoption of continuously
advancing technology.
    Surface Air and Soil Gas Monitoring: Surface air measurements can
be used to monitor the flux of CO2 out of the deep
subsurface, with deviations from background levels representing
potential leakage. If deviation in the flux of CO2 is
detected, it may indicate potential endangerment of USDWs. While
subsurface monitoring forms the primary basis for protecting USDWs,
near-surface and surface techniques could be the last line of
monitoring. Under today's proposal, owners or operators could, at the
Director's discretion, be required to conduct surface air monitoring
and/or soil gas monitoring in the AoR. Knowledge of leaks to shallow
USDWs is of critical importance since these USDWs are more likely to
serve public water supplies than deeper formations. If leakage to a
USDW should occur, near-surface and surface monitoring can identify the
general location of the leak.
    A range of techniques employed at varied monitoring frequencies are
available for implementation. Optimal spacing of monitoring wells, eddy
covariance towers, or soil gas chambers would need to be selected, and
may be based on the outcome of other monitoring techniques such as
seismic or Electrical Resistance Tomography (ERT).
    For surface air monitoring, chambers can be placed directly on the
soil and trapped gases are passed through an infrared gas analyzer to
determine CO2 content (GEO-SEQ, 2004). Changes in
CO2 concentration and air flow rates are used to calculate a
flux. Measurements using chambers are typically conducted along a grid,
which has the benefit of defining spatial and temporal variations in
CO2 flux that could be used for pinpointing and quantifying
any leaks. Chamber measurements, however, are labor-intensive and are
not efficient for sampling over large areas. For each of these methods,
baseline (pre-injection) monitoring is very important in order to
establish conditions for future comparison. There are natural sources
of CO2 that can have wide variability and thus could mask
leakage from a GS operation.
    Eddy covariance techniques have been used for ecological
applications to measure carbon fluxes from vegetated areas, and show
promise for CO2 monitoring for GS operations (Miles et al.,
2005). The equipment is installed on a tower and CO2 is
measured with an infrared gas analyzer (GEO-SEQ, 2004). Wind velocity,
relative humidity, and temperature are also measured and the
information is integrated to calculate a CO2 flux. The
height of the tower controls the aerial coverage, with higher towers
averaging over larger areas. Because of the large coverage, the exact
location of a leak would be difficult to pinpoint, and this method may
be better for detecting slow, diffuse leaks. Eddy covariance also
assumes a horizontal and homogeneous land surface, which may not hold
true for all GS locations. It does have the advantage of being
automated, greatly reducing the labor involved.
    Hyperspectral image analysis is a form of remote sensing that has
been used, among other applications, for mapping vegetation habitat
boundaries and for differentiating species types. Scanners collect
images of a given feature using a number of relatively small wavelength
bands, including the visible and infrared portions of the spectrum.
Because different elements have different spectral signatures, a
hyperspectral image can convey information about composition. The
potential utility for CO2 monitoring would be the ability to
map the response of vegetation to elevated soil CO2
concentrations (Pickles and Cover, 2005).

    LIDAR (light detection and ranging) is a remote sensing method that
is used extensively in atmospheric science, and is currently under
investigation as an option for CO2 detection to monitor GS
sites (Benson and Myer, 2002). Similar in principle to RADAR, LIDAR
uses light instead of radio waves, permitting resolution of very small
features, such as aerosols. Light is pulsed from a laser and various
constituents in the atmosphere reflect back some of the light. A number
of properties of the backscattered light allow one to infer the
atmospheric composition, including concentrations of CO2.
Currently, differential absorption LIDAR (DIAL) is being studied by
researchers at Montana State University for detecting CO2
leaks in pipelines.
    EPA proposes that owners and operators report semi-annually on the
characteristics of injection fluids, injection pressure, flow rate,
temperature, volume and annular pressure, and on the results of MITs,
ground water monitoring, and any required atmospheric/soil gas
monitoring.
    EPA seeks comment on the appropriate amount and types of monitoring
that should be conducted at a GS site. Specifically, EPA seeks comment
regarding the usefulness of indirect geophysical monitoring and surface
air and soil gas monitoring. In addition, EPA seeks comment regarding
the use of a Director-approved monitoring plan for GS sites.
7. Proposed Recordkeeping and Reporting Requirements
    Submissions Required for Consideration of Permit Applications:
Today's proposal would require that owners and operators submit
relevant site information to the permitting authority for consideration
of permit applications. This information includes maps of the injection
wells, the AoR as determined through computational modeling, all
artificial penetrations within the AoR, maps of the general vertical
and lateral limits of USDWs, maps of the geologic cross sections of the
local area, the proposed operating data and injection procedures,
proposed formation testing program, and stimulation program, well
schematics and construction procedures, and contingency plans for shut-
ins or well failures. EPA is also proposing that permit applicants
submit a demonstration of financial responsibility to plug the well, to
provide for post-injection site care, and site closure.
    EPA is proposing today that permit applications for GS sites
include several plans not currently required under existing UIC
regulations. These plans include a monitoring and testing plan, an AoR
and corrective action plan, and a post-injection site care and site
closure plan. The requirement for additional plans is intended to
provide the Director the opportunity to assess proposed project
operating procedures, and addresses GS requirements that are seen to be
site-specific (e.g., what monitoring techniques will be used). In
addition, these plans are intended to establish an ongoing dialogue
between the operator and the permitting authority which is more
substantial than that required for other classes of injection wells.
EPA seeks comment on the merits of requiring plans for monitoring, AoR,
and post-injection site care as part of a permit application.
    Operational Recordkeeping and Reporting Requirements: Under current
UIC requirements, operators must report on a regular basis to the
permitting authority, the physical and chemical characteristics of the
injected fluids, as well as other operational data. For Class I
industrial and Class I hazardous waste wells and Class III wells,
operators must submit this information on a quarterly basis. For Class
II wells, operators must submit this information on an annual basis.
Today's proposal would require that owners or operators of Class VI
wells report semi-annually to the permitting authority, on the physical
and chemical characteristics of injection fluids, injection pressure,
flow rate, temperature, volume and annular pressure, annulus fluid
volume added, and the results of MITs, plume tracking, and atmospheric/
soil gas monitoring. Additionally, owners and operators will be
required to submit the results of AoR modeling revisions; any updates
to the information on the type, number, and location of all wells
within the site AoR; and information on additional corrective action
performed or planned based on AoR reevaluations. EPA considers a less
frequent reporting requirement for Class VI wells compared to Class I
wells appropriate considering the ongoing dialogue for Class VI wells
established by multiple plans as discussed above.
    Under today's proposal, owners and operators would also be required
to maintain recordkeeping and reporting information for the duration of
the project, as well as three years after site closure (following the
post-injection site care period); and to keep their most recent
plugging and abandonment report for one year following site closure.
    Reporting Associated with Well Plugging, Post-injection Site Care,
and Site Closure: EPA proposes that owners or operators notify the
Director at least 60 days prior, or at a Director-determined time, of
their intent to plug the well and of any updates to the post-injection
site care and site closure plan. After the well is plugged, owners and
operators would submit a well plugging report stating that the well was
plugged in accordance with the approved post-injection site care and
site closure plan or specify the differences between the plan and the
actual well plugging. During the post-injection site care (monitoring)
period, owners or operators would report periodically on the results of
monitoring. At the end of the post-injection site care period, owners
or operators would submit a site closure report, along with a non-
endangerment demonstration showing that conditions within the
subsurface indicate that no additional monitoring is necessary to
assure that there is no endangerment to USDWs associated with the
injection.
    EPA seeks comment on the frequency of all proposed reporting
requirements.
    Electronic Reporting and Recordkeeping: Under today's proposal, EPA
would require owners or operators to report data specified in section
146.91 in an electronic format acceptable to the Director for site,
facility, and monitoring information. At the discretion of the
Director, formats other than electronic may be accepted after a
determination has been made that the entity does not have the
capability to use the required format. Long-term retention of records
in an electronic format may also be required at the Director's
discretion. If records are stored in an electronic format, information
should be maintained digitally in multiple locations (i.e., backed-up)
in accordance with best practices for electronic data.
    EPA has previously required electronic reporting of monitoring data
in the program implemented under the Unregulated Contaminant Monitoring
Rule (64 FR 50611, September 17, 1999, 40 CFR 141.35(e)). EPA believes
that the permit applicants will have the resources to provide
electronic data to the permit authority and that electronic reporting
will reduce future burden related to recordkeeping. In addition,
electronic data submissions will facilitate the application review
process and make it easier to track progress of GS projects. EPA is
committed to providing resources to States to develop the capability to
exchange data electronically. Several States have received grants to
develop electronic data exchange capability for their current UIC
programs.

    EPA seeks comment on the requirement for electronic reporting in
today's proposed rule. In addition to the above recordkeeping and
reporting requirements, EPA considered a requirement for owners or
operators of GS sites to provide an annual report during the lifetime
of the project, including the post-injection period, regarding the GS
operation. This report would describe the status of the operation, any
new data about the site including operational and monitoring data, new
GS operations, or other activities that may affect the plume movement,
any non-compliance, and knowledge gained on GS technology that could
contribute to the state of the science on GS. This requirement would
address the unique and large-scale nature of CO2 GS
operations, provide the public with information regarding the
operation, and facilitate information transfer about GS technology.
Although EPA has not included a requirement for this report in today's
proposal, EPA seeks comment regarding the necessity for such an annual
report.
8. Proposed Well Plugging, Post-Injection Site Care, and Site Closure
Requirements
    Today's proposal outlines well plugging and post injection site
care requirements for CO2 injection sites after injection
activities end. If finalized, these new requirements at 40 CFR 146.92-
146.93 would ensure that owners or operators plug wells and manage
sites in a manner so that wells do not serve as a conduit for escape of
stored CO2 through unexpected migration from the injection
site after injection ends, preventing endangerment of USDWs. EPA is
proposing to give owners or operators flexibility in meeting the well
plugging requirements by allowing the owner or operator to choose from
available materials and tests to carry out the proposed requirements.
EPA is not specifying the types of materials or tests that must be used
during well plugging because there are a variety of methods that are
appropriate and new materials and tests may become available in the
future. EPA is also proposing that a combination of a fixed timeframe
and performance standard be used to determine the duration of the post-
injection site care period.
    Steps in Injection Well Plugging: EPA is proposing that owners or
operators develop a well plugging plan, and conduct several activities
associated with the plugging of GS wells. Injection well plugging must
comply with requirements of 40 CFR 144.12(a). The plan includes: (1)
Providing notice of intent to plug a well at least 60 days prior to
well plugging, (2) flushing each well to be plugged with a buffer
fluid, (3) testing the mechanical integrity of each well, (4) plugging
each well in a manner that will prevent the movement of fluid that may
endanger USDWs, and (5) submitting a plugging report within 60 days
after plugging the well or at the time of the next semi-annual report
(whichever is less).
    Notice of intent to plug: The notice of intent to plug provides a
60-day advance notice to the Director that the owner or operator
intends to close the well. If circumstances warrant a shorter time
period for giving notice of intent to plug, the Director may approve a
shorter notice period.
    Well Flushing: Flushing removes fluids remaining in the long string
casing that could react with the well components over time. Fluids used
for flushing may vary, but must provide sufficient buffering ability to
avoid the possibility of reactions due to residual CO2 or
other contaminants in the fluid.
    Mechanical Integrity Testing: Mechanical integrity testing allows
owners or operators to ensure that the long string casing and cement
that are left in the ground after well plugging and site closure
maintain integrity over time. For GS wells, there are a number of
methods that can be used to test mechanical integrity, including
pressure tests with liquid or gas, radioactive tracer surveys, and
noise, temperature, pipe evaluation, or cement bond logs.
    Well Plugging: The Agency is proposing that owners or operators
plug wells in a manner that does not endanger USDWs. This may be
accomplished in a number of ways using a number of different types of
materials. In the case of GS wells, the plugging materials must be
compatible with the fluids with which the materials may be expected to
come into contact and plugged to prevent the movement of fluids either
into or between USDWs.
    Plugging Report: The owner or operator would be required to submit
a report which includes information on the implementation of the
plugging plan, including the date the well was plugged, the activities
conducted to prepare the well for plugging, the materials used for
plugging, and the location of the well. The owner or operator may
either submit the plugging report as a separate report within 60 days
after the plugging activity, or update the semi-annual report required
at 40 CFR 146.92 of this proposed rule to include plugging information
and submit the updated report within 60 days after the plugging
activity. EPA is proposing that the owner or operator must certify that
the plugging report is accurate. If the well was plugged by an entity
other than the owner or operator, that entity must also certify that
the plugging report is accurate.
    In addition, EPA is proposing the owners or operators prepare for
eventual site closure in advance of the time when well plugging
activities take place to ensure that a plan is in place in the event of
an unexpected need to plug a well or close the site. Today's proposal
would require owners or operators to submit a well plugging plan at the
same time the permit application is submitted and to have this plan
approved by the Director. As part of the well plugging plan, the owner/
operator would be required to conduct certain activities related to
well plugging, and provide the information related to well plugging,
including the following: (1) Testing methods used to determine that the
components of the well will maintain mechanical integrity over time;
(2) type and number of plugs to be used; (3) placement of each plug,
including the elevation of the top and bottom of each plug; (4) type,
grade, and quantity of material to be used in plugging; and (5) method
used to put plugs in place. In addition, if for any reason the well
plugging activities stated in the plan no longer reflect what is likely
to occur upon plugging of the well, the owner or operator would be
required to make changes to the plan and submit to the Director for
approval before notifying the Director of intent to plug the well.
    Post-Injection Site Care: Today's proposal would also require that
owners or operators (1) develop a post-injection site care and closure
plan, (2) monitor the site following cessation of the injection
activity, and (3) plug all monitoring wells in a manner which prevents
movement of injection or formation fluids that could endanger a USDW.
    The post-injection site care and site closure plan would be
required to be submitted as part of the permit application and approved
by the Director. It describes several activities associated with the
post-injection site care and site closure of GS sites. Activities that
would be required in the post-injection site care and site closure plan
include: (1) Record of the pressure differential between pre-injection
and anticipated post-injection pressures in the injection zone; (2)
predicted position of the plume and associated pressure front at the
time the site is closed; (3) description of post-injection monitoring
location(s), methods, and proposed frequency of monitoring; and (4)
schedule for submitting post-injection site care and monitoring

results to the Director. In addition, if for any reason the post-
injection site care and site closure activities stated in the plan no
longer reflect what is likely to occur upon closing the site, the owner
or operator would be required to make changes to the plan and submit
the plan to the Director for approval within 30 days of such change.
Examples of factors which may require a modified post-injection site
care and site closure plan would include changes in injection
procedures or volumes or plume movement in an unanticipated direction.
    Upon permanent cessation of injection, the owner or operator would
either submit an amended post-injection site care and site closure or
demonstrate to the Director through monitoring and modeling results
that no amendment to the plan is needed. Owners or operators would also
be required to use any other information deemed necessary by the
Director to make this demonstration.
    The post-injection site care and site closure plan would include a
description of the monitoring that will occur after injection ceases.
The owner or operator would monitor the site to show the position of
the CO2 plume and pressure front and demonstrate that USDWs
are not being endangered. A record of the pressures in the injection
formation and surrounding areas as well as the pressure decay rate can
help the owner or operator determine that the injected fluid does not
pose endangerment to USDWs.
    Post-Injection Site Care Timeframe: Current UIC regulations do not
limit the duration of the post-injection site care period; however,
many environmental programs use a 30-year period as a frame of
reference. In many cases, a 30-year timeframe has been sufficient to
determine that remaining pressure in plugged wells containing liquids
will not lift fluid to overlying strata (53 FR 28143, July 26, 1988).
However, characterizing post-injection site care timeframes for GS is
more challenging. Given the buoyancy of CO2, viscosity, and
large injection volumes associated with GS, the area over which
CO2 will spread in the subsurface is likely to be larger
than for existing well classes and therefore, the area over which there
is potential for endangerment of USDWs is likely to be greater. The
presence of physical and geochemical trapping mechanisms is likely to
reduce the mobility of CO2 over time and research also
suggests that pressure within the storage system will drop
significantly when injection ceases, thus decreasing the risks of
induced seismic activity, and faulting and fracturing and making
storage more secure over longer timeframes. However, the timeframe over
which this happens is difficult to define because it is based on site-
specific considerations.
    EPA considered three distinct alternatives for determining post-
injection site care and monitoring timeframes (1) establishing a fixed
timeframe for post-injection site care; (2) allowing a performance-
based approach to the post-injection site care time period; and (3) a
combination of fixed timeframe and performance standard.
    EPA considered the approach of specifying a fixed duration of time
after which the post-injection site care ends. As part of this
approach, EPA evaluated four different timeframes: 10, 30, 50, and 100
years.
    EPA reviewed studies, industry reports and environmental programs
to determine appropriate post-injection site care timeframes. Studies
reviewed included those done by: Flett M., Gurton R., and G. Weir.
2007; Obi E.I., and M.J. Blunt. 2006; and Doughty, C. 2007 (see USEPA,
2008d). A review of these studies suggests that the actual time for
CO2 plume stabilization (i.e., slowing down or cessation of
plume movement, and/or immobilization of most of the CO2
mass through various trapping mechanisms) will be very site specific,
being influenced by geologic factors such as formation permeability,
geochemistry, and the degree of capillary trapping. In addition,
predicted results will depend on several modeling considerations and
assumptions, and thus will be to some degree model specific. Based on a
review of the three studies used for this preliminary analysis,
modeling results indicate that the CO2 plume stabilized on
the time frame of 10-100 years after the cessation of injection (USEPA,
2008d).
    EPA also reviewed an IOGCC Task Force report which suggests a 10-
year time frame for the post-injection site care period which commences
when injection ceases until the release of the operator from liability.
Alternatively, some environmental programs--including the UIC Program--
use a 30-year period as a frame of reference.
    While 10 years may be within the timeframe suggested in some
studies, there are circumstances under which the potential risks of
endangering USDWs will not decline within that timeframe given that
stabilization may continue for several decades (USEPA, 2008d). Also, a
30-year timeframe can be appropriate for the types of fluids typically
injected under the UIC Program (i.e., fluids that are liquids at
standard pressure and temperature). Longer timeframes may be more
appropriate for GS wells, because the fluid is likely to be stored in a
supercritical phase, the plume for a full-scale GS project will likely
be large, and substantial pressure increases will likely be observed
during operation. However, once injection ceases, pressure will likely
begin to dissipate and 30 years may be enough time for the plume and
pressure front to stabilize.
    Another option considered by the Agency is to apply a performance
standard, i.e., that post-injection site care will continue until the
plume is stabilized and cannot endanger USDWs. Current UIC regulations
at 40 CFR 146.71 utilize a performance type approach by requiring that
the owner or operator of a Class I hazardous well observe and record
pressure decay for a time specified by the Director. A similar
performance standard could be considered for GS wells. Pressure decay
data help to define the appropriate period of regulatory concern,
because the likelihood that the injected fluid will migrate into USDWs
above or adjacent to the injection zone decreases as injection-induced
pressures in the formation decay. The post-injection site care period
ends when the models predicting CO2 movement are consistent
with monitoring results demonstrating that there is no potential threat
of endangerment to USDWs.
    Combination of Fixed Timeframe and Performance Standard: EPA is
proposing using a combination of fixed timeframe and a performance
standard as described above. EPA is tentatively proposing a post-
injection site care (monitoring) period of 50 years with Director's
discretion to change that period to lengthen or shorten the 50-year
period if appropriate. The default timeframe could be lengthened by the
Director if potential for endangerment to USDWs still exists after 50
years or if modeling and monitoring results demonstrate that the plume
and pressure front have not stabilized in this period. Conversely, the
Director could reduce the 50-year time period if data on pressure,
fluid movement, mineralization, and/or dissolution reactions support a
determination that movement of the plume and pressure front have ceased
and the injectate does not pose a risk to USDWs. EPA requests comment
on the proposed use of a tentative 50-year fixed timeframe that could
be modified at the Director's discretion based on monitoring and
modeling data.
    To ensure that the post-injection site care monitoring timeframe is
long enough to determine that there is no threat of endangerment to
USDWs from injection activities, EPA is proposing a

default post-injection site care period of 50 years. During this 50-
year period, the owner or operator would be required to submit periodic
reports providing monitoring results and updated modeling results as
appropriate until a demonstration of non-endangerment to USDWs can be
made. Once the owners or operators provide documentation that
demonstrates that the models predicting CO2 movement are
consistent with monitoring results and that there are no longer risks
of endangerment to USDWs, they could request that the Director
authorize site closure.
    EPA is also proposing to allow the Director to shorten or lengthen
the 50-year timeframe based on performance of the site. The Director
may require that the post-injection site care period extend beyond the
50-year time frame if a demonstration of non-endangerment to USDWs
cannot be made. Alternately, if the owner or operator can demonstrate
that the remaining pressure front and plume will not endanger USDWs,
then owners or operators may request a decreased post-injection site
care period.
    While EPA considered the 10-year, 30-year, and 100-year timeframes,
the Agency is proposing a 50-year timeframe because there are
circumstances under which the potential risks of endangerment to USDWs
will not decline within 10 years. Furthermore, the time needed to allow
pressures to equalize within the subsurface because of the higher
levels of mobility of injected CO2 may exceed 30 years, and
EPA wishes to emphasize that site closure cannot occur until monitoring
and modeling data establish to the Director's satisfaction that
potential risks of endangerment to USDWs have ceased. EPA is not
proposing 100 years as the default because EPA believes that in general
plume stabilization will occur before this time. However post-injection
site care requirements could be extended for 100 years (or longer) if
monitoring and modeling information suggest that the plume may still
endanger USDWs throughout this period. EPA considers that a 50-year
timeframe represents a reasonable mid-point for the default time frame,
which may be modified with the approval of the Director based on a
demonstration (by the owner or operator) using monitoring and modeling,
that the injected CO2 will not endanger USDWs.
    Site Closure: The Director would determine that the post-injection
site care period has ended and authorize site closure when the
following have occurred:
     The Director receives all information required of the
post-injection site care and site closure plan;
     The data demonstrate to the satisfaction of the Director
that there is no threat of endangerment to USDWs.
    Once the Director approves site closure, the owner or operator is
required to submit a site closure report within 90 days. The report
would provide documentation of injection and monitoring well plugging;
copies of notifications to State and local authorities that may have
authority over future drilling activities in the region; and records
reflecting the nature, composition, and volume of the injected carbon
dioxide stream. The purpose of this report would be to provide
information to potential users and authorities of the land surface and
subsurface pore space regarding the operation. In addition, the owner
or operator of the injection site must record a notation on the deed to
the facility property or any other document that is normally examined
during title search that will, in perpetuity, provide notification to
any potential purchaser of the property information that the land has
been used to sequester CO2.
    EPA is requesting comments on the proposed requirements for well
plugging, post-injection site care, and site closure, including the
proposed requirements for the post-injection time period. In addition,
EPA seeks comment on whether the Director should be allowed to shorten
the timeframe based on performance information, and whether EPA should
require a shorter or longer post-injection period if data suggests the
time frame should be adjusted.
9. Proposed Financial Responsibility and Long-Term Care Requirements
    Today's proposal would require that owners or operators demonstrate
and maintain financial responsibility, and have the resources for
activities related to closing and remediating GS sites. EPA is
proposing that the rule only specify a general duty to obtain financial
responsibility acceptable to the Director, and will provide guidance to
be developed at a later date that describes recommended types of
financial mechanisms that owners or operators can use to meet this
requirement.
    Although the SDWA does not have explicit provisions for financial
responsibility, as included in RCRA, EPA believes that the general
authorities provided under the SDWA authority to prevent endangerment
of USDWs include the authority to set standards for financial
responsibility to prevent endangerment of USDWs from improper plugging,
remediation, and management of wells after site closure. The SDWA
authority does not extend to financial responsibility for activities
unrelated to protection of USDWs (e.g., coverage of risks to air,
ecosystems, or public health unrelated to USDW endangerment). It also
does not cover transfer of owner or operator financial responsibility
to other entities, or creation of a third party financial mechanism
where EPA is the trustee.
    Today's proposal would require owners or operators to demonstrate
financial responsibility for corrective action described in 40 CFR
146.84 of this notice, including injection well plugging, post-
injection site care and site closure, and emergency and remedial
response using a financial mechanism acceptable to the Director. The
Director would determine whether the mechanism the owner or operator
submits is adequate to pay for well plugging, post-injection site care,
site closure, and remediation that may be needed to prevent
endangerment of underground sources of drinking water.
    Owners or operators would no longer need to demonstrate that they
have financial assurance after the post-injection site care period has
ended. This generally occurs when the Director approves the completed
post-injection site care and site closure plan and then determines that
the injected fluid no longer poses a threat of endangerment to USDWs
(e.g., the fluid no longer exhibits a propensity to move or migrate out
of the injection zone to any point where it could endanger a USDW).
    The Agency is proposing that the owner or operator periodically
update the cost estimate for well plugging, post-injection site care
and site closure, and remediation to account for any amendments to the
area of review and corrective action plan (40 CFR 146.84), the plugging
and abandonment plan, and the post-injection site care and site closure
plan (40 CFR 146.93). EPA is also proposing that the owner or operator
submit an adjusted cost estimate to the Director if the original
demonstration is no longer adequate to cover the cost of the injection
well plugging, post-injection site care, and site closure. As proposed,
the Director would set the frequency for owner or operator re-
demonstration of financial responsibility and resources. It may be
appropriate to re-demonstrate financial responsibility on a periodic
basis. Such re-demonstration would take into account any amendments to
the area of review and corrective action plan (40 CFR 146.84) and
adjustments for inflation. It may also be necessary to

adjust cost estimates if the Director has reason to believe that the
original demonstration is no longer adequate to cover the cost of the
well plugging and post-injection site care and site closure. EPA is
also proposing that the owner or operator notify the Director of
adverse financial conditions, including but not limited to bankruptcy
proceedings, which name the owner or operator as debtor, within 10
business days after the commencement of the proceeding.
    EPA plans to develop guidance that is similar to current UIC
financial responsibility guidance for Class II owners or operators.
Currently, EPA guidance (USEPA, 1990) describes several options owners
or operators can use to meet the requirements to demonstrate financial
responsibility for well plugging. Financial assurance is typically
demonstrated through two broad categories of financial instruments: (1)
Third party instruments, including surety bond, financial guarantee
bond or performance bond, letters of credit (the above third party
instruments must also establish a trust fund), and an irrevocable trust
fund; (2) self-insurance instruments, including the corporate financial
test and the corporate guarantee.
    Supplemental Information: In recent years, the EPA's Office of the
Inspector General (OIG) and the U.S. Government Accountability Office
(GAO) have raised issues regarding the use of financial responsibility
instruments applicable to site closure for several EPA programs.
Information regarding these reviews and EPA's responses are available
at http://www.gao.gov/new.items/d03761.pdf; http://www.epa.gov/oig/
reports/2001/finalreport330.pdf; http://www.epa.gov/oig/reports/2005/
20050926-2005-P-00026.pdf. The OIG and GAO recommendations suggest that
EPA may need to update or provide additional guidance in the following
areas: Cost estimation methodology; pay-in period for trust funds; the
type of insurance provider that may be used; requirements for
acceptable surety bonds and/or their providers; and the way by which
corporations demonstrate financial strength/credit worthiness.
    In response to evaluations of financial responsibility instruments,
EPA's RCRA program has issued a comprehensive financial responsibility
strategy to improve the implementation of the financial responsibility
requirements, as well as assess whether regulatory changes to certain
mechanisms and financial responsibility requirements are warranted. EPA
has begun implementing this strategy by providing additional guidance
to support implementation and oversight of RCRA financial
responsibility programs, providing training to EPA Regions and states,
and developing tools (e.g., cost-estimating software) to assist staff
in performing reviews of complex cost information.
    In addition, EPA's RCRA program has enlisted the experience and
expertise of the Environmental Finance Advisory Board (EFAB) to
evaluate specific issues related to financial responsibility. EFAB has
completed assessments of the corporate financial test and captive
insurance, and is currently in the process of undertaking analyses of
third-party insurance and uncertainties associated with estimating
costs that must be covered by the financial assurance requirements. In
January 2006, the EFAB summarized its findings and recommendations on
the corporate financial test, as a means of demonstrating financial
assurance. EFAB's recommendations in this area were not based on
specific failures of the test, but on their ``knowledge of prudent
financial practices and the availability of existing expertise in the
financial services sector.'' In March 2007, the EFAB summarized its
preliminary findings and conclusions on its review of insurance,
specifically captive insurance, as a means of demonstrating financial
assurance. The Agency plans to continue to track these efforts by the
EFAB, because they may provide key directions for future GS
requirements with respect to financial responsibility.
    EPA is considering updating mechanisms for demonstrating financial
responsibility for GS projects. EPA is evaluating revising guidance to
address the current financial responsibility requirements on the
following topics: Cost estimation for plugging, pay-in period for trust
funds, insurance providers, surety bonds and/or their providers, and
corporate demonstration of financial strength/credit worthiness.
    Cost estimation for plugging: One of the most critical aspects to
ensuring that owners or operators have the resources to pay for
injection well plugging is cost estimation. Sound cost estimation
requirements ensure that sufficient funds are set aside in the
financial assurance instrument to properly undertake covered activities
(e.g., plugging and post-injection site care) at any time during the
operating life of the facility and during the post-injection site care
period.
    EPA is assessing whether the cost estimate underpinning financial
assurance should be based on the cost of retaining an independent,
third party to conduct covered activities, such as well plugging. EPA
also is considering provisions for annual inflationary adjustments and
is weighing the inclusion of a third-party certification requirement,
or provisions for a third-party audit, in cases where the owner or
operator self-prepares its cost estimate. Revision in this area will
reduce the possibility of undervalued cost estimates. EPA will also
consider EFAB's findings on this issue when they become available.
    Pay-in period for trust funds: Current UIC guidance describes trust
funds as a form of financial assurance. The owner or operator may
deposit funds into the trust fund in phases; that is, either over the
term of the initial permit or over the remaining operating life of the
injection well, as estimated in the well plugging plan, whichever
period is shorter. Because of the possibility that the owner or
operator may face financial distress prior to the trust being fully
funded, EPA is considering a guidance approach that would recommend
adopting a pay in period of three years for GS projects, consistent
with other similar programs in the Agency.
    Insurance providers: Current UIC regulations for Class I hazardous
waste injection allow for the use of insurance for purposes of
demonstrating financial responsibility. However, insurance was not
included as part of the guidance provided for Class II injection
because this insurance mechanism was and still is, rarely used for the
purpose of demonstrating financial assurance for injection wells. EPA
is assessing whether to provide guidance on the use of insurance
providers and, if so, whether to update eligibility requirements for
insurers for GS wells consistent with other current Federal agency
practices.
    In addition, EPA is evaluating recommendations from the Office of
the Inspector General (OIG), the Government Accountability Office
(GAO), and EFAB on the use of insurance as a financial responsibility
mechanism. EPA will also consider any additional recommendations EFAB
may have on the use of third party insurance.
    Surety bonds and/or their providers: Current UIC guidance describes
several options for using surety bonds for purposes of demonstrating
financial responsibility. The regulations at 40 CFR 144 for Class I
wells stipulate that eligible surety bond providers must be listed by
the U.S. Department of Treasury on its Circular 570. Because surety
bonds are a specialized line of insurance, EPA is assessing whether
additional eligibility requirements for sureties, similar to those
under consideration for insurers, are necessary for GS wells.

    Corporate demonstration of financial strength/credit worthiness:
UIC program guidance also describes options for owners or operators to
self-assure their obligations to plug the well. To be approved by the
Director, the owner or operator would likely need to self-assure in the
form of either a corporate financial test filed by the owner or
operator of the injection well, or a corporate guarantee (including a
corporate financial test) filed by the parent corporation of the owner
or operator of the injection well. A corporate guarantee may also be
provided by a ``sibling'' corporation (that is a company that shares
the same higher-tier parent) or a company with whom they have a
substantial business relationship. The guidance explains that
demonstrating self-assurance typically includes either use of a bond
rating or a series of financial ratios. Both the UIC financial
responsibility provisions for Class I hazardous waste injection and the
RCRA subtitle C provisions allow the use of self-assurance through a
financial test or corporate guarantee.
    EPA is assessing whether a financial ratings threshold for all
companies using a self-guarantee, similar to those used by other
Federal agencies, is appropriate. The Agency also is considering what
constitutes an appropriate financial rating threshold, and whether a
financial rating greater than BBB or Baa (i.e., the current rating
threshold established under the UIC regulations) is appropriate for GS
wells.
    In addition, EPA is considering whether adjustments should be made
to the absolute net worth threshold of $10 million currently required
under the UIC regulations. Specifically, EPA is assessing the net worth
requirements of other Federal agencies and EPA programs to determine
whether to make adjustments. For example, the Minerals Management
Service within the Department of the Interior, requires a net worth
threshold at least 10 times the amount of the obligations being assured
(see 30 CFR 253.25). Additionally, the Agency is in the process of
evaluating potential changes to the RCRA subtitle C financial test
requirements, including an option recommended by EFAB to require a
financial ratings threshold for all companies using a financial test to
self-assure their environmental obligations. EPA will consider the
outcome of that process for possible application to GS wells guidance.
    EPA is requesting comments on whether financial responsibility
mechanisms to be recommended in EPA guidance should be adjusted in the
manner described, whether additional instruments should be included,
and whether other adjustments to the financial responsibility
mechanisms should be considered, all subject to EPA's authority under
the SDWA. The Agency is also requesting comment on allowing separate
financial demonstrations to be submitted for the plugging of the
injection well and for the post-injection site care requirements. Since
post-injection site care has the potential to extend many years into
the future, subsequent to the time a permit is issued, the Agency
believes that it may be advantageous to require the approval of the
well plugging financial demonstration at permit issuance and the post-
injection site care financial demonstration at a later time (e.g.,
within 180 days of notifying the Director that the well will be plugged
and abandoned). Trying to determine the cost for post-injection site
care, possibly 30 to 50 years in the future, could be difficult, as
could the approval of a financial demonstration.
    Considerations for Long-term Care: While EPA has authority to
require financial responsibility for well plugging and post-injection
site care (e.g., monitoring, remediation) to ensure the protection of
USDWs, the SDWA does not provide authority under financial
responsibility or other provisions for coverage of risks to air,
ecosystems, or public health. Thus, while obligation for financial
responsibility ends for owners or operators after the post-injection
site care period has ended and the Director has authorized site
closure, owners or operators may still be held responsible after the
post-injection site care period has ended (e.g., for unanticipated
migration that endangers a USDW). In addition, the SDWA does not
provide EPA with the authority to transfer liability from one entity to
another. Trust responsibility for potential impacts to USDWs remains
with the owner or operator indefinitely under current SDWA provisions.
    Responsibility for long-term care is often considered an important
topic related to GS because of cost implications of indefinite
responsibility for GS sites. Because of the focus of the SDWA on
endangerment to USDWs and the absence of provisions to allow transfer
of liability, stakeholders have expressed interest in alternative
instruments for addressing financial responsibility after the post
injection care period has ended. As a result of the interest in
alternative instruments, including indemnity programs, EPA has compiled
information on a variety of alternative instruments not currently
available under the SDWA. This discussion is in Approaches to GS Site
Stewardship After Site Closure in the docket for this proposed rule.
EPA has not determined whether any of the models are appropriate for GS
wells, however, EPA is aware that these models may contain important
concepts that may become the model for future strategies for long-term
care.

B. Adaptive Approach

    To meet the potentially fast pace of implementation of GS, EPA is
using an adaptive approach to regulating CO2 injection for
GS. In 2007, EPA issued UIC Program Guidance 83, which allows
limited-scale experimental GS projects to proceed under the Class V
experimental technology well classification. An adaptive approach
allows regulatory development to move ahead in time to meet the future
demand for permits, while recognizing the need to continue to gather
data from pilot projects and other research as it becomes available.
    EPA will continue to evaluate ongoing research and demonstration
projects, review input received on this proposal, and gather other
relevant information, as needed, to make refinements to the rulemaking
process. If appropriate, EPA will publish notices to collect new data
before issuing a final rule on CO2 injection for GS. EPA
plans to issue a final rule in advance of full-scale deployment of GS.
EPA will track implementation of the final GS rule to determine whether
these requirements continue to meet SDWA objectives and, if not, revise
them as needed. If new information gathered during implementation
suggests the requirements need revisions, EPA will initiate the
appropriate procedure, including public notice and comment.

IV. How Should UIC Program Directors Involve the Public in Permitting
Decisions for GS Projects?

    Public participation has been an important part of the UIC Program
since its inception. Public participation has a number of benefits,
including (1) providing citizens with access to decision-making
processes that may affect them; (2) enabling the owner/operator and the
permit writer to educate the community about the project; (3) ensuring
that the public receives adequate information about the proposed
injection; (4) allowing the permitting authority to become aware of
public viewpoints, preferences and environmental justice concerns; and
(5) ensuring that public viewpoints, preferences and concerns have been
considered by the decision-making officials.

    GS of CO2 is a new technology that is unfamiliar to most
people, and maximizing the public's understanding of the technology can
result in more meaningful public input and constructive participation
as new GS projects are proposed and developed. Critical to the success
of GS is early and frequent involvement through education and
information exchange. Such exchange can provide early insight into how
the local community and surrounding communities perceive potential
environmental, economic or health effects.
    Owners or operators and permitting authorities can maximize the
public participation process, thereby increasing the likelihood of
success, by integrating social, economic, and cultural concerns of the
community into the permit decision making process.
    EPA examined existing requirements for public participation across
the Agency's environmental programs. EPA is proposing to adopt the
requirements at 40 CFR Part 25 and the permit procedures at 40 CFR Part
124 for long-term storage of CO2. Under today's proposal,
the permitting authority would be required to provide public notice and
opportunity for public input. This includes providing public notice of
pending actions via newspaper advertisements, postings, or mailings to
interested parties and providing a fact sheet or statement of basis
that describes the planned injection operation and the principal facts
and issues considered in preparing the draft permit. Under today's
proposal, permitting authorities would provide a 30-day comment period
during which public hearings may be held. At the conclusion of the
comment period, the permitting authority would be required to prepare a
responsiveness summary that becomes part of the public record.
    EPA recognizes that advances in information technology and the
available avenues for communication have changed the way that people
receive news and information and that new means of engaging
stakeholders are now available. Roundtables, constituency meetings,
charrettes (workshops designed to involve the public in a planning or
design process), information gathering sessions, cable TV, and the
Internet are just a few tools the Agency has come to rely upon over the
past decade to ensure more effective stakeholder involvement and public
participation. These technologies provide a host of opportunities to
educate the public about and involve them in GS technology and pending
decisions.
    In addition, electronic information technology has become widely
available to inform and involve the public. Web pages, discussion
boards, list serves, and broadcast text messages via cell phones are
all available to keep the public informed.
    EPA encourages permit applicants and permit writers to use the
Internet and other available tools to explain potential GS projects;
describe the technology; and post information on the latest
developments including schedules for hearings, briefings, and other
opportunities for involvement.
    EPA requests comment on adopting the existing requirements for
public participation at 40 CFR Part 25 and 40 CFR Part 124 and whether
additional requirements should be included to reflect the availability
of new tools for disseminating and gathering information. Such tools
include cable networks, the Internet, and other new technology. EPA
also requests comment on ways to enhance the public participation
process, including engaging communities in the site characterization
process as soon as candidate locations are identified.

V. How Will States, Territories, and Tribes Obtain UIC Program Primacy
for Class VI Wells?

    As described in section II.C above, EPA may approve primary
enforcement authority for States, Territories, and Tribes that wish to
implement the UIC Program. To gain authority for Class VI wells,
States, Territories, and Tribes will be required to show that their
regulations are at least as stringent as, and may be more stringent
than, the proposed minimum Federal requirements (e.g., inspection,
operation, monitoring, and recordkeeping requirements that well owners
or operators must meet). Such Primacy States, Territories, and Tribes
are authorized under section 1422 of the SDWA.
    Historically, EPA has approved State and Territorial UIC Program
primacy in whole or in part as follows: (1) For all five classes of
wells under section 1422 of SDWA; (2) for Classes, I, III, IV, and V
under Section 1422 of SDWA; or for (3) Class II wells only under
section 1425 of SDWA. Several States with large Class II inventories
may have primacy for a combination of wells, i.e., authority under
section 1425 for their Class II wells and 1422 authority for other well
classes.
    EPA is aware that some States may wish to obtain primacy for only
Class VI wells. Section 1422 does not explicitly allow for approval of
State UIC programs for individual well classes, however there appears
to be no express prohibition.
    There may be benefits to parsing out primacy for Class VI wells,
however EPA has not made a decision on this. Allowing States,
Territories, and Tribes to acquire primacy for only Class VI wells may
encourage them to assume the responsibility of implementation and
provide for a more comprehensive approach to managing CCS projects
(e.g., capture, transportation, and geologic sequestration). EPA is
seeking comment on the merits and possible disadvantages of allowing
primacy approval for Class VI wells independent of other well classes.

VI. What Is the Proposed Duration of a Class VI Injection Permit?

    Existing UIC regulations allow injection wells to be permitted
individually or as part of an area permit. Because GS projects would
likely use multiple injection wells per project, the Agency anticipates
that most owners or operators would seek area permits for their
injection wells.
    Additionally, 40 CFR 144.36 sets forth the permit duration for the
current classes of injection wells. Permits for Class I and Class V
wells are effective for up to 10 years. Permits for Class II and III
wells may be issued for the operating life of the facility; however
they are subject to a review by the permitting authority at least once
every 5 years.
    Implementation of the AoR and corrective action plan as described
in today's proposal would involve periodic re-evaluation of site data,
status of corrective action, monitoring results and modification of
operating parameters, as needed. These periodic evaluations would
provide the same effect and assurances obtained through the permit
renewal process without the associated administrative burden.
Additionally, the frequent level of ongoing interaction between the
owner or operator and the Director as required by the AoR and
corrective action plan is more substantial than that required for other
classes of injection wells. The periodic evaluations and revisions
driven by the various rule-required plans and the underlying
computational model should provide abundant opportunities for technical
reassessment by operators and regulators, and through permit amendments
and modifications.
    Therefore, EPA proposes that Class VI injection well permits would
be issued for the operating life of the GS project including the post-
injection site care period. EPA seeks comment on the merits of this
approach.

VII. Cost Analysis

    While today's proposed rulemaking proposes regulations for the
protection of USDWs, it does not require entities to sequester
CO2. Thus, the costs and benefits associated with protection
of USDWs is the focus of this proposed rule and the costs associated
with the mitigation of climate change are not directly attributable to
this proposed rulemaking.
    To calculate the costs and benefits of compliance for today's
proposal, EPA selected the existing UIC program Class I industrial
waste disposal well category as the baseline for costs and benefits.
EPA used this baseline to determine the incremental costs of today's
proposal.
    The incremental costs of the proposed rule include elements such as
geologic characterization, well construction and operation, monitoring
equipment and procedures, well plugging, and post-injection site care
(monitoring). The benefits of this proposed rulemaking could include
the decreased risk of endangerment to USDWs and the decreased potential
for health-related risks associated with contaminated USDWs.
    The scope of the Cost Analysis includes the full range of an
injection project, from the end of the CO2 pipeline at the
GS site, to the underground injection and monitoring, as it occurs
during the time frame of the analysis. The scope does not include
capturing or purifying the CO2, nor does it include
transporting the CO2 to the GS site.
    The 25-year timeframe of the Cost Analysis is comparable to the
timeframes used in recent drinking water-related economic analyses.
Costs attributed to the proposed rule are inclusive of geologic
sequestration projects begun during the 25 years of the analysis and
all cost elements that occur during the 25-year timeframe are
discounted to present year values. EPA recognizes the need to revisit
the Cost Analysis prior to the promulgation of a final rule as new data
become available. The number of GS projects projected over the
timeframe of the Cost Analysis includes pilot projects and other
projects driven by regulations that are in place today. Projections of
GS projects may need to be revisited in light of any new climate change
legislation prior to promulgation of a final rule. However, it is
important to note that the proposed rule does not require anyone to
inject CO2.

A. National Benefits and Costs of the Proposed Rule \1\
---------------------------------------------------------------------------

    \1\ Although both estimated costs and benefits are discussed in
detail, the final policy decisions regarding this rulemaking are not
premised solely on a cost/benefit basis.
---------------------------------------------------------------------------

1. National Benefits Summary
    This section summarizes the risk (and benefit) tradeoffs between
compliance with existing requirements and the preferred regulatory
alternative (RA) selected during the regulatory development process.
Evaluations in the Cost Analysis include a non-quantitative analysis of
the relative risks of contamination to USDWs for the regulatory
alternatives under consideration. The expected change in risk based on
promulgation of the preferred RA and the potential nonquantified
benefits of compliance with this RA are also discussed.
a. Relative Risk Framework--Qualitative Analysis
    Table VII-1 below presents the estimated relative risks of the
preferred regulatory alternative selected for compliance with the
proposed rule relative to the baseline. The term ``baseline'' in the
exhibit refers to risks as they exist under current UIC Program
regulations for Class I industrial wells. The term ``decrease''
indicates the change in risk relative to this baseline. The Agency has
used best professional judgment to qualitatively estimate the relative
risk of each regulatory alternative. This assessment was made with
contributions from a wide range of injection well and hydrogeological
experts, ranging from scientists and well owners or operators to
administrators and regulatory experts.

   Table VII-1.--Relative Risk of Regulatory Components for Preferred
     Proposed Regulatory Alternative Versus the Current Regulations
------------------------------------------------------------------------
                                            Direction of change  in risk
                 Baseline                      (relative to baseline)
------------------------------------------------------------------------
1. Geologic Characterization
    Geologic system consisting of a        Decrease.
     receiving zone; trapping mechanism;
     and confining system to allow
     injection at proposed rates and
     volumes.
    Operators provide maps and cross
     sections of local and regional
     geology, AoR, and USDWs;
     characterize the overburden and
     subsurface; and provide information
     on fractures, stress, rock strength,
     and in situ fluid pressures within
     cap rock.
2. Area of Review (AoR) Study and
 Corrective Action
    The AoR determined as either a \1/4\   Decrease.
     mile radius or by mathematical
     formula. Identify all wells in the
     AoR that penetrate the injection
     zone and provide a description of
     each; identify the status of
     corrective action for wells in the
     AoR; and remediate those posing the
     greatest risk to USDWs.
3. Injection Well Construction
    The well must be cased and cemented    Decrease.
     to prevent movement of fluids into
     or between USDWs and to withstand
     the injected materials at the
     anticipated pressure, temperature
     and other operational conditions.
4. Well Operation
    Limit injection pressure to avoid      Decrease.
     initiating new fractures or
     propagate existing fractures in the
     confining zone adjacent to the USDWs.
5. Mechanical Integrity Testing (MIT)
    Demonstrate internal and external      Decrease.
     mechanical integrity, conduct a
     radioactive tracer survey of the
     bottom-hole cement, and conduct a
     pressure fall-off test every 5 years.
6. Monitoring
    Monitor the nature of injected fluids  Decrease.
     at a frequency sufficient to yield
     data representative of their
     characteristics; Conduct ground
     water monitoring within the AoR.
     Report semi-annually on the
     characteristics of injection fluids,
     injection pressure, flow rate,
     volume and annular pressure, and on
     the results of MITs, and ground
     water and atmospheric monitoring.
7. Well Plugging

    Ensure that the well is in a state of  Decrease.
     static equilibrium and plugged using
     approved methods. Plugs shall be
     tagged and tested. Conduct post-
     injection site care monitoring to
     confirm that CO2 movement is limited
     to intended zones.
8. Financial Responsibility
    Demonstrate and maintain financial     Decrease.
     responsibility and resources to plug
     the injection well and for post-
     injection site care.
Overall..................................  Decrease.
------------------------------------------------------------------------
Note: See Chapter 2 of the GS proposed rule Cost Analysis for a detailed
  description of the components for each regulatory alternative.

    In the consideration of benefits of the proposed GS rule, the
direction of change in risk mitigation compared to the baseline
regulatory scenario was assessed for each component of the four
regulatory alternatives considered. An overall assessment for each
alternative as a whole requires consideration of the relative
importance of risk being mitigated by each component of the proposed
rule.
    As shown in Table VII-1, EPA estimates that under the Preferred
Alternative, RA3, risk will decrease relative to the baseline for each
of the eight components assessed.
b. Other Nonquantified Benefits
    Promulgation of the proposed rule will result in direct benefits,
that is, protection of the USDWs which EPA is required by statute to
protect; and indirect benefits, which are those protections afforded to
entities as a by-product of protecting USDWs. Indirect benefits are
described in the Risk and Occurrence Document for Geologic
Sequestration Proposed Rulemaking (USEPA, 2008e) and summarized in
Chapter 4 of the GS Rule Cost Analysis. They include mitigation of
potential risk to surface ecology and to human health through exposure
to elevated concentrations of CO2. Potential benefits from
potential climate change mitigation are not included in the assessment.
2. National Cost Summary
a. Cost of Preferred Regulatory Alternative
    EPA estimated the incremental, one-time, capital, and operation and
maintenance (O&M) costs associated with today's proposed rulemaking. As
Table VII-2 shows, the total incremental cost associated with the
Preferred Alternative is $15.0 million and $15.6 million, using a 3
percent and 7 percent discount rate, respectively. These costs are in
addition to the baseline costs that would be incurred if CO2
sequestration was instead subject to the current rules for UIC Class I
industrial wells. As can be seen from Table VII-2, today's proposed
rule would increase the costs of complying with UIC regulations for
these wells from approximately a baseline of $32.3 million to $47.3
million using a 3 percent discount rate, which is an increase of 46%.
EPA believes these increased costs are needed to address the unique
issues associated with CO2 geological sequestration. The
costs of the other regulatory alternatives considered are detailed in
the Cost Analysis, along with a discussion of how EPA derived these
estimates.

               Table VII-2.--Incremental Costs of Preferred Regulatory Alternative for 22 Projects
                                                [2007$, $million]
----------------------------------------------------------------------------------------------------------------
                                                                   One-time     Capital
                     Regulatory alternative                          costs       costs     O&M costs     Total
----------------------------------------------------------------------------------------------------------------
                                                                              3 Percent Discount Rate
                                                                 -----------------------------------------------
Baseline........................................................        $2.5       $10.6       $19.2       $32.3
Alternative 3...................................................         3.8        15.5        28.1        47.3
Alt 3--Incremental..............................................         1.3         4.9         8.8        15.0
                                                                 -----------------------------------------------
                                                                              7 Percent Discount Rate
                                                                 -----------------------------------------------
Baseline........................................................        $2.9       $12.7       $18.0       $33.6
Alternative 3...................................................         4.2        18.6        26.4        49.2
Alt 3--Incremental..............................................         1.3         5.9         8.4        15.6
----------------------------------------------------------------------------------------------------------------

    Table VII-3 presents a breakout of the incremental costs of the
Preferred Alternative by rule component.
     Monitoring activities account for 60 percent of the
incremental regulatory costs. Most of this cost is for the
construction, operation, and maintenance of corrosion-resistant
monitoring wells. This cost also includes tracking of the plume and
pressure front as well as the cost of incorporating monitoring results
into fluid flow models that are used to reevaluate the AoR. These
activities are a key component of decreasing risk associated with GS
because they facilitate early detection of unacceptable movement of
CO2 or formation fluids.
     The next largest cost component of the Preferred
Alternative is injection well operation, accounting for 22 percent of
the total incremental cost. This component ensures that the wells
operate within safety parameters and the injection does not cause
unacceptable fluid movement.
     Well plugging and post-injection site care activities,
which ensure that the injection well is properly closed in a way that
addresses the corrosive

nature of the CO2 and does not allow it to serve as a
conduit for fluid movement, account for 5 percent of the total
incremental cost of RA 3.
     Mechanical Integrity Testing, including continuous
pressure monitoring, which can provide timely warning that
CO2 may have compromised the well, accounts for an
additional 4 percent of the cost.
     Construction of GS wells using the corrosion resistant
design and materials necessary to withstand exposure to CO2
accounts for 4 percent of the incremental cost of the Preferred
Alternative.

                                           Table VII-3.--Incremental Rule Costs of Preferred Regulatory Alternative for 22 Projects by Rule Component
                                                                                [2007$, $million]
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Rule component
                                                                  ------------------------------------------------------------------------------------------------------------------------------
                                                                                Well
                     Regulatory  alternative                                                       Injection                                     plugging     Financial    Permitting