[Federal Register Volume 75, Number 237 (Friday, December 10, 2010)]
[Rules and Regulations]
[Pages 77230-77303]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2010-29954]
[[Page 77229]]
-----------------------------------------------------------------------
Part III
Environmental Protection Agency
-----------------------------------------------------------------------
40 CFR Parts 124, 144, 145, et al.
Federal Requirements Under the Underground Injection Control (UIC)
Program for Carbon Dioxide (CO[bdi2]) Geologic Sequestration (GS)
Wells; Final Rule
Federal Register / Vol. 75 , No. 237 / Friday, December 10, 2010 /
Rules and Regulations
[[Page 77230]]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 124, 144, 145, 146, and 147
[EPA-HQ-OW-2008-0390 FRL-9232-7]
RIN 2040-AE98
Federal Requirements Under the Underground Injection Control
(UIC) Program for Carbon Dioxide (CO2) Geologic
Sequestration (GS) Wells
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: This action finalizes minimum Federal requirements under the
Safe Drinking Water Act (SDWA) for underground injection of carbon
dioxide (CO2) for the purpose of geologic sequestration
(GS). GS is one of a portfolio of options that could be deployed to
reduce CO2 emissions to the atmosphere and help to mitigate
climate change. This final rule applies to owners or operators of wells
that will be used to inject CO2 into the subsurface for the
purpose of long-term storage. It establishes a new class of well, Class
VI, and sets minimum technical criteria for the permitting, geologic
site characterization, area of review (AoR) and corrective action,
financial responsibility, well construction, operation, mechanical
integrity testing (MIT), monitoring, well plugging, post-injection site
care (PISC), and site closure of Class VI wells for the purposes of
protecting underground sources of drinking water (USDWs). The elements
of this rulemaking are based on the existing Underground Injection
Control (UIC) regulatory framework, with modifications to address the
unique nature of CO2 injection for GS. This rule will help
ensure consistency in permitting underground injection of
CO2 at GS operations across the United States and provide
requirements to prevent endangerment of USDWs in anticipation of the
eventual use of GS to reduce CO2 emissions to the atmosphere
and to mitigate climate change.
DATES: This regulation is effective January 10, 2011. For purposes of
judicial review, this final rule is promulgated as of 1 p.m., Eastern
time on December 24, 2010, as provided in 40 CFR 23.7.
ADDRESSES: EPA has established a docket for this action under Docket ID
No. EPA-HQ-OW-2008-0390. All documents in the docket are listed on the
http://www.regulations.gov Web site. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, is not placed on the Internet and will be
publicly available only in hard copy form. Publicly available docket
materials are available either electronically through http://www.regulations.gov or in hard copy at the OW Docket, EPA/DC, EPA West,
Room 3334, 1301 Constitution Ave., NW., Washington, DC. The Public
Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through
Friday, excluding legal holidays. The telephone number for the Public
Reading Room is (202) 566-1744, and the telephone number for the OW
Docket is (202) 566-2426.
FOR FURTHER INFORMATION CONTACT: Mary Rose (Molly) Bayer, Underground
Injection Control Program, Drinking Water Protection Division, Office
of Ground Water and Drinking Water (MC-4606M), Environmental Protection
Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460; telephone
number: (202) 564-1981; fax number: (202) 564-3756; e-mail address:
[email protected]. For general information, visit the Underground
Injection Control Geologic Sequestration Web site at http://www.epa.gov/safewater/uic/wells_sequestration.html.
SUPPLEMENTARY INFORMATION:
I. General Information
This regulation affects owners or operators of injection wells that
will be used to inject CO2 into the subsurface for the
purposes of GS. Regulated categories and entities include, but are not
limited to, the following:
------------------------------------------------------------------------
Category Examples of regulated entities
------------------------------------------------------------------------
Private........................... Owners or Operators of CO2 injection
wells used for Class VI GS.
Private........................... Owners or Operators of existing CO2
injection wells transitioning from
Class I, II, or Class V injection
activities to Class VI GS.
------------------------------------------------------------------------
This table is not intended to be an exhaustive list; rather it
provides a guide for readers regarding entities likely to be regulated
by this action. This table lists the types of entities that EPA is now
aware could potentially be regulated by this action. Other types of
entities not listed in the table could also be regulated. To determine
whether your facility is regulated by this action, you should carefully
examine the applicability criteria found at Sec. 146.81 in the rule
section of this action. If you have questions regarding the
applicability of this action to a particular entity, consult the person
listed in the preceding FOR FURTHER INFORMATION CONTACT section.
Abbreviations and Acronyms
AoR Area of Review
BLM United States Department of the Interior, Bureau of Land
Management
BOEMRE United States Department of the Interior, Bureau of Ocean
Energy Management, Regulation and Enforcement
CAA Clean Air Act
CBI Confidential Business Information
CCS Carbon Capture and Storage
CERCLA Comprehensive Environmental Response, Compensation, and
Liability Act
CO2 Carbon Dioxide
DOE United States Department of Energy
ECBM Enhanced Coal Bed Methane
EFAB Environmental Financial Advisory Board
EGR Enhanced Gas Recovery
EIS Environmental Impact Statement
EISA Energy Independence and Security Act of 2007
EO Executive Order
EOR Enhanced Oil Recovery
EPA United States Environmental Protection Agency
ER Enhanced Recovery
FPR Federally Permitted Releases
GAO General Accountability Office
GHG Greenhouse Gas
GS Geologic Sequestration
Gt CO2 Gigatons CO2
GWPC Ground Water Protection Council
HHS United States Department of Health and Human Services
ICR Information Collection Request
IOGCC Interstate Oil and Gas Compact Commission
IPCC Intergovernmental Panel on Climate Change
IRS United States Internal Revenue Service
LBNL Lawrence Berkeley National Laboratory
Mg/L Milligrams per liter
MI Mechanical Integrity
MIT Mechanical Integrity Test
MMS United States Department of the Interior, Minerals Management
Service
MPRSA Marine Protection, Research, and Sanctuaries Act of 1972
MRA Miscellaneous Receipts Act
MRR Mandatory Reporting Rule
MRV Monitoring, Reporting, and Verification
NAICS North American Industry Classification System
NASA National Aeronautics and Space Administration
NCER National Center for Environmental Research
NDWAC National Drinking Water Advisory Council
NEPA National Environmental Protection Act
NETL National Energy Technology Laboratory
NGO Non-Governmental Organization
NIWG National Indian Work Group
NOAA National Oceanic and Atmospheric Administration
NODA Notice of Data Availability
NOI Notice of Intent
[[Page 77231]]
NTC National Tribal Caucus
NTTAA National Technology Transfer and Advancement Act of 1995
NTWC National Tribal Water Council
O&M Operation and Maintenance
OAR Office of Air and Radiation
OCS Outer Continental Shelf
OCSLA Outer Continental Shelf Lands Act
OMB Office of Management and Budget
ORD Office of Research and Development
PBMS Performance Based Measurement System
Pg Petagram
PISC Post-Injection Site Care
PRA Paperwork Reduction Act
PWSS Public Water System Supervision
QASP Quality Assurance and Surveillance Plan
RA Regulatory Alternative
RCRA Resource Conservation and Recovery Act
RCSP Regional Carbon Sequestration Partnership
RFA Regulatory Flexibility Act
RIC Regional Indian Coordinators
SDWA Safe Drinking Water Act
STAR Science To Achieve Results
STC3 State-Tribal Climate Change Council
SWP Southwest Regional Partnership on Carbon Sequestration
TCLP Toxicity Characteristic Leaching Procedure
TDS Total Dissolved Solids
TNW Tangible Net Worth
UIC Underground Injection Control
UICPG83 Underground Injection Control Program Guidance
83
UMRA Unfunded Mandates Reform Act
USDW Underground Source of Drinking Water
USGS United States Department of the Interior, United States
Geological Survey
WRI World Resources Institute
Definitions
Annulus: The space between the well casing and the wall of the bore
hole; the space between concentric strings of casing; the space between
casing and tubing.
Area of review (AoR): The region surrounding the geologic
sequestration project where USDWs may be endangered by the injection
activity. The area of review is delineated using computational modeling
that accounts for the physical and chemical properties of all phases of
the injected carbon dioxide stream and displaced fluids, and is based
on available site characterization, monitoring, and operational data as
set forth in Sec. 146.84.
Automatic shut-off device: A valve which closes when a pre-
determined pressure or flow value is exceeded. Shut-off devices in
injection wells can automatically shut down injection activities
preventing an excursion outside of the permitted values.
Ball valve: A valve consisting of a hole drilled through a ball
placed in between two seals. The valve is closed when the ball is
rotated in the seals so the flow path no longer aligns and is blocked.
Biosphere: The part of the Earth's crust, waters, and atmosphere
that supports life.
Buoyancy: Upward force on one phase (e.g., a fluid) produced by the
surrounding fluid (e.g., a liquid or a gas) in which it is fully or
partially immersed, caused by differences in pressure or density.
Capillary force: Adhesive force that holds a fluid in a capillary
or a pore space. Capillary force is a function of the properties of the
fluid, and surface and dimensions of the space. If the attraction
between the fluid and surface is greater than the interaction of fluid
molecules, the fluid will be held in place.
Caprock: See confining zone.
Carbon dioxide plume: The extent underground, in three dimensions,
of an injected carbon dioxide stream.
Carbon dioxide (CO2) stream: Carbon dioxide that has
been captured from an emission source (e.g., a power plant), plus
incidental associated substances derived from the source materials and
the capture process, and any substances added to the stream to enable
or improve the injection process. This subpart does not apply to any
carbon dioxide stream that meets the definition of a hazardous waste
under 40 CFR part 261.
Casing: The pipe material placed inside a drilled hole to prevent
the hole from collapsing. The two types of casing in most injection
wells are (1) surface casing, the outermost casing that extends from
the surface to the base of the lowermost USDW and (2) long-string
casing, which extends from the surface to or through the injection
zone.
Cement: Material used to support and seal the well casing to the
rock formations exposed in the borehole. Cement also protects the
casing from corrosion and prevents movement of injectate up the
borehole. The composition of the cement may vary based on the well type
and purpose; cement may contain latex, mineral blends, or epoxy.
Confining zone: A geologic formation, group of formations, or part
of a formation stratigraphically overlying the injection zone(s) that
acts as barrier to fluid movement. For Class VI wells operating under
an injection depth waiver, confining zone means a geologic formation,
group of formations, or part of a formation stratigraphically overlying
and underlying the injection zone(s).
Corrective action: The use of Director-approved methods to ensure
that wells within the area of review do not serve as conduits for the
movement of fluids into USDWs.
Corrosive: Having the ability to wear away a material by chemical
action. Carbon dioxide mixed with water forms carbonic acid, which can
corrode well materials.
Dip: The angle between a planar feature, such as a sedimentary bed
or a fault, and the horizontal plane. The dip of subsurface rock layers
can provide clues as to whether injected fluids may be contained.
Director: The person responsible for permitting, implementation,
and compliance of the UIC program. For UIC programs administered by
EPA, the Director is the EPA Regional Administrator or his/her
delegatee; for UIC programs in Primacy States, the Director is the
person responsible for permitting, implementation, and compliance of
the State, Territorial, or Tribal UIC program.
Ductility: The ability of a material to sustain stress until it
fractures.
Enhanced Coal Bed Methane (ECBM) recovery: The process of injecting
a gas (e.g., CO2) into coal, where it is adsorbed to the
coal surface and methane is released. The methane can be captured and
produced for economic purposes; when CO2 is injected, it
adsorbs to the surface of the coal, where it remains trapped or
sequestered.
Enhanced Oil or Gas Recovery (EOR/EGR): Typically, the process of
injecting a fluid (e.g., water, brine, or CO2) into an oil
or gas bearing formation to recover residual oil or natural gas. The
injected fluid thins (decreases the viscosity) and/or displaces
extractable oil and gas, which is then available for recovery. This is
also used for secondary or tertiary recovery.
Flapper valve: A valve consisting of a hinged flapper that seals
the valve orifice. In Class VI wells, flapper valves can engage to shut
off the flow of the CO2 when acceptable operating parameters
are exceeded.
Formation or geological formation: A layer of rock that is made up
of a certain type of rock or a combination of types.
Geologic sequestration (GS): The long-term containment of a
gaseous, liquid or supercritical carbon dioxide stream in subsurface
geologic formations. This term does not apply to CO2 capture
or transport.
Geologic sequestration project: For the purpose of this regulation,
an injection well or wells used to emplace a carbon dioxide stream
beneath the lowermost formation containing a USDW; or, wells used for
geologic sequestration of carbon dioxide that have been granted a
waiver of the injection depth requirements pursuant to requirements
[[Page 77232]]
at Sec. 146.95; or, wells used for geologic sequestration of carbon
dioxide that have received an expansion to the areal extent of an
existing Class II EOR/EGR aquifer exemption pursuant to Sec. Sec.
146.4 and 144.7(d). It includes the subsurface three-dimensional extent
of the carbon dioxide plume, associated area of elevated pressure, and
displaced fluids, as well as the surface area above that delineated
region.
Geophysical surveys: The use of geophysical techniques (e.g.,
seismic, electrical, gravity, or electromagnetic surveys) to
characterize subsurface rock formations.
Injectate: The fluids injected. For the purposes of this rule, this
is also known as the CO2 stream.
Injection zone: A geologic formation, group of formations, or part
of a formation that is of sufficient areal extent, thickness, porosity,
and permeability to receive CO2 through a well or wells
associated with a geologic sequestration project.
Lithology: The description of rocks, based on color, mineral
composition and grain size.
Mechanical integrity (MI): The absence of significant leakage
within the injection tubing, casing, or packer (known as internal
mechanical integrity), or outside of the casing (known as external
mechanical integrity).
Mechanical Integrity Test: A test performed on a well to confirm
that a well maintains internal and external mechanical integrity. MITs
are a means of measuring the adequacy of the construction of an
injection well and a way to detect problems within the well system.
Model: A representation or simulation of a phenomenon or process
that is difficult to observe directly or that occurs over long time
frames. Models that support GS can predict the flow of CO2
within the subsurface, accounting for the properties and fluid content
of the subsurface formations and the effects of injection parameters.
Packer: A mechanical device that seals the outside of the tubing to
the inside of the long string casing, isolating an annular space.
Pinch-out: A situation where a formation thins to zero thickness.
Pore space: Open spaces in rock or soil. These are filled with
water or other fluids such as brine (i.e., salty fluid). CO2
injected into the subsurface can displace pre-existing fluids to occupy
some of the pore spaces of the rocks in the injection zone.
Post-injection site care: Appropriate monitoring and other actions
(including corrective action) needed following cessation of injection
to ensure that USDWs are not endangered, as required under Sec.
146.93.
Pressure front: The zone of elevated pressure that is created by
the injection of carbon dioxide into the subsurface. For GS projects,
the pressure front of a CO2 plume refers to the zone where
there is a pressure differential sufficient to cause the movement of
injected fluids or formation fluids into a USDW.
Saline formations: Subsurface geographically extensive sedimentary
rock layers saturated with waters or brines that have a high total
dissolved solids (TDS) content (i.e., over 10,000 mg/L TDS).
Site closure: The point/time, as determined by the Director
following the requirements under Sec. 146.93, at which the owner or
operator of a GS site is released from post-injection site care
responsibilities.
Sorption (absorption, adsorption): Absorption refers to gases or
liquids being incorporated into a material of a different state;
adsorption is the adhering of a molecule or molecules to the surface of
a different molecule.
Stratigraphic zone (unit): A layer of rock (or stratum) that is
recognized as a unit based on lithology, fossil content, age or other
properties.
Supercritical fluid: A fluid above its critical temperature
(31.1[deg]C for CO2) and critical pressure (73.8 bar for
CO2). Supercritical fluids have physical properties
intermediate to those of gases and liquids.
Total Dissolved Solids (TDS): The measurement, usually in mg/L, for
the amount of all inorganic and organic substances suspended in liquid
as molecules, ions, or granules. For injection operations, TDS
typically refers to the saline (i.e., salt) content of water-saturated
underground formations.
Transmissive fault or fracture: A fault or fracture that has
sufficient permeability and vertical extent to allow fluids to move
between formations.
Trapping: The physical and geochemical processes by which injected
CO2 is sequestered in the subsurface. Physical trapping
occurs when buoyant CO2 rises in the formation until it
reaches a layer that inhibits further upward migration or is
immobilized in pore spaces due to capillary forces. Geochemical
trapping occurs when chemical reactions between dissolved
CO2 and minerals in the formation lead to the precipitation
of solid carbonate minerals.
Underground Source of Drinking Water (USDW): An aquifer or portion
of an aquifer that supplies any public water system or that contains a
sufficient quantity of ground water to supply a public water system,
and currently supplies drinking water for human consumption, or that
contains fewer than 10,000 mg/l total dissolved solids and is not an
exempted aquifer.
Viscosity: The property of a fluid or semi-fluid that offers
resistance to flow. As a supercritical fluid, CO2 is less
viscous than water and brine.
Table of Contents
I. General Information
II. Background
A. Why is EPA taking this regulatory action?
1. What is GS?
2. Why is GS under consideration as a climate change mitigation
technology?
3. What are the unique risks to USDWs associated with GS?
B. Under what authority is this rulemaking promulgated?
C. How does this rulemaking relate to the greenhouse gas (GHG)
reporting program?
D. How does this rulemaking relate to other federal authorities
and GS and CCS activities?
E. What steps did EPA take to develop this rulemaking?
1. Developing Guidance for Experimental GS Projects
2. Conducting Research
a. Tracking the Results of CO2 GS Research Projects
b. Tracking State Regulatory Efforts
c. Conducting Technical Workshops on Issues Associated with
CO2 GS
3. Conducting Stakeholder Coordination and Outreach
4. Proposed Rulemaking
5. Notice of Data Availability and Request for Comment
F. How Will EPA's Adaptive Rulemaking Approach Incorporate
Future Information and Research?
G. How Does This Action Affect UIC Program Implementation?
H. How Does This Rule Affect Existing Injection Wells Under the
UIC Program?
III. What is EPA's Final Regulatory Approach?
A. Site Characterization
B. Area of Review (AoR) and Corrective Action
1. AoR Requirements
2. Corrective Action Requirements
C. Injection Well Construction
D. Class VI Injection Depth Waivers and Use of Aquifer
Exemptions for GS
1. Proposed Rule
2. Notice of Data Availability and Request for Comment
3. Final Approach
E. Injection Well Operation
F. Testing and Monitoring
1. Testing and Monitoring Plan
2. CO2 Stream Analysis
3. Mechanical Integrity Testing (MIT)
4. Corrosion Monitoring
5. Ground Water/Geochemical Monitoring
6. Pressure Fall-Off Testing
7. CO2 Plume and Pressure Front Monitoring/Tracking
[[Page 77233]]
8. Surface Air/Soil Gas Monitoring
9. Additional Requirements
G. Recordkeeping and Reporting
1. What Information Must Be Provided by the Owner or Operator?
2. How Must Information Be Submitted?
3. What are the Recordkeeping Requirements under This Rule?
H. Well Plugging, Post-Injection Site Care (PISC), and Site
Closure
1. Injection Well Plugging
2. Post-Injection Site Care (PISC)
3. Site Closure
I. Financial Responsibility
J. Emergency and Remedial Response
K. Involving the Public in Permitting Decisions
L. Duration of a Class VI Permit
IV. Cost Analysis
A. National Benefits and Costs of the Rule
1. National Benefits Summary
a. Relative Risk Framework--Qualitative Analysis
b. Other Nonquantified Benefits
2. National Cost Summary
a. Cost of the Selected RA
b. Nonquantified Costs and Uncertainties in Cost Estimates
c. Supplementary Costs and Uncertainties in Cost Estimates
B. Comparison of Benefits and Costs of RAs Considered
1. Costs Relative to Benefits; Maximizing Net Social Benefits
2. Cost Effectiveness and Incremental Net Benefits
C. Conclusions
V. Statutory and Executive Order Review
VI. References
II. Background
Today's action finalizes minimum Federal requirements under SDWA
for injection of CO2 for the purpose of GS. The purpose of
the rulemaking is to ensure that GS is conducted in a manner that
protects USDWs from endangerment. GS refers to a suite of technologies
that can be deployed to reduce CO2 emissions to the
atmosphere and help mitigate climate change. Due to the large
CO2 injection volumes anticipated at GS projects, the
relative buoyancy of CO2, its mobility within subsurface
geologic formations, its corrosivity in the presence of water, and the
potential presence of impurities in the captured CO2 stream,
the Agency has determined that tailored requirements, modeled on the
existing UIC regulatory framework, are necessary to manage the unique
nature of CO2 injection for GS. This final rule applies to
owners or operators of wells that will be used to inject CO2
into the subsurface for the purpose of GS.
To support today's final regulatory action, EPA proposed Federal
Requirements Under the Underground Injection Control (UIC) Program for
Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells (73
FR 43492) on July 25, 2008; and the Agency published a supplemental
publication, Federal Requirements Under the Underground Injection
Control (UIC) Program for Carbon Dioxide (CO2) Geologic
Sequestration (GS) Wells; Notice of Data Availability and Request for
Comment (74 FR 44802) on August 31, 2009. Final Class VI requirements
are informed, in part, by comments and information submitted in
response to these publications.
Today's rule defines a new class of injection well (Class VI),
along with technical criteria that tailor the existing UIC regulatory
framework to address the unique nature of CO2 injection for
GS. It sets minimum technical criteria for Class VI wells to protect
USDWs from endangerment, including:
Site characterization that includes an assessment of the
geologic, hydrogeologic, geochemical, and geomechanical properties of
the proposed GS site to ensure that Class VI wells are located in
suitable formations.
Computational modeling of the AoR for GS projects that
accounts for the physical and chemical properties of the injected
CO2 and is based on available site characterization,
monitoring, and operational data.
Periodic reevaluation of the AoR to incorporate monitoring
and operational data and verify that the CO2 plume and the
associated area of elevated pressure are moving as predicted within the
subsurface.
Well construction using materials that can withstand
contact with CO2 over the life of the GS project.
Robust monitoring of the CO2 stream, injection
pressures, integrity of the injection well, ground water quality and
geochemistry, and monitoring of the CO2 plume and position
of the pressure front throughout injection.
Comprehensive post-injection monitoring and site care
following cessation of injection to show the position of the
CO2 plume and the associated area of elevated pressure to
demonstrate that neither pose an endangerment to USDWs.
Financial responsibility requirements to ensure that funds
will be available for all corrective action, injection well plugging,
post-injection site care (PISC), site closure, and emergency and
remedial response.
Today's rule will help ensure consistency in permitting underground
injection of CO2 at GS operations across the United States
(US) and provide requirements to prevent endangerment of USDWs in
anticipation of the potential role of carbon capture and storage (CCS)
in mitigating climate change. Today's action also briefly discusses the
relationship between today's rule and other Federal and State
activities related to GS and CCS in Sections II.C and D, and E.2.b, and
III.F.2.
A. Why is EPA taking this regulatory action?
1. What is GS?
GS is the process of injecting CO2 into deep subsurface
rock formations for long-term storage. It is part of the process known
as CCS.
CO2 is first captured from fossil-fueled power plants or
other emission sources. To transport captured CO2 for GS,
operators typically compress CO2 to convert it from a
gaseous state to a supercritical state (IPCC, 2005; IEA, 2008).
CO2 exists as a supercritical fluid at high pressures, and
in this state it exhibits properties of both a liquid and a gas. After
capture and compression, the CO2 is delivered to the
sequestration site, frequently by pipeline, or alternatively using
tanker trucks or ships (WRI, 2007; IEA, 2008).
At the GS site, the CO2 is injected into deep subsurface
rock formations through one or more wells, using technologies developed
and refined by the oil, gas, and chemical manufacturing industries over
the past several decades. EPA believes that many owners or operators
will inject CO2 in a supercritical state to depths greater
than 800 meters (2,645 feet) for the purpose of maximizing capacity and
storage.
When injected into an appropriate receiving formation,
CO2 is sequestered by a combination of trapping mechanisms,
including physical and geochemical processes (Benson, 2008). Physical
trapping occurs when the relatively buoyant CO2 rises in the
formation until it reaches a stratigraphic zone with low permeability
(i.e., geologic confining system) that inhibits further upward
migration. Physical trapping can also occur as residual CO2
is immobilized in formation pore spaces as disconnected droplets or
bubbles at the trailing edge of the plume due to capillary forces. A
portion of the CO2 will dissolve from the pure fluid phase
into native ground water and hydrocarbons. Preferential sorption occurs
when CO2 molecules attach to the surfaces of coal and
certain organic-rich shales, displacing other molecules such as
methane. Geochemical trapping occurs when chemical reactions between
the dissolved CO2 and minerals in the formation lead to the
precipitation of solid carbonate minerals (IPCC, 2005). The timeframe
over which CO2 will be trapped by these mechanisms depends
on properties of
[[Page 77234]]
the receiving formation and the injected CO2 stream.
The effectiveness of physical CO2 trapping is
demonstrated by natural analogs in a range of geologic settings where
CO2 has remained trapped for millions of years (Holloway et
al., 2007). For example, CO2 has been trapped for more than
65 million years under the Pisgah Anticline, northeast of the Jackson
Dome in Mississippi and Louisiana (IPCC, 2005). Other natural
CO2 sources include the following geologic domes: McElmo
Dome, Sheep Mountain, and Bravo Dome in Colorado and New Mexico.
Many of the injection and monitoring technologies that may be
applicable to GS are commercially available today and will be more
widely demonstrated over the next 10 to 15 years (Dooley et al., 2009).
The oil and natural gas industry in the United States has over 35 years
of experience of injection and monitoring of CO2 in the deep
subsurface for the purposes of enhancing oil and natural gas
production. This experience provides a strong foundation for the
injection and monitoring technologies that will be needed for
commercial-scale CCS. US and international experience with enhanced
recovery (ER) and commercial CCS projects, as well as ongoing research,
demonstration, and deployment programs throughout the world, provide
critical experience and information to inform the safe injection of
CO2. For additional information about these projects, see
section II.E.
Although CCS is occurring now on a relatively small scale, it could
play a larger role in mitigating greenhouse gas (GHG) emissions from a
wide variety of stationary sources. According to the Inventory of US
Greenhouse Gas Emissions and Sinks: 1990-2007, stationary sources
contributed 67 percent of the total CO2 emissions from
fossil fuel combustion in 2007 (USEPA, 2008a). These sources represent
a wide variety of sectors amenable to CO2 capture: electric
power plants (existing and new), natural gas processing facilities,
petroleum refineries, iron and steel foundries, ethylene plants,
hydrogen production facilities, ammonia refineries, ethanol production
facilities, ethylene oxide plants, and cement kilns. Furthermore, 95
percent of the 500 largest stationary sources are within 50 miles of a
candidate GS reservoir (Dooley et al., 2008). Estimated GS capacity in
the United States is over 3,500 Gigatons CO2 (Gt
CO2) (DOE NETL, 2007), although the actual capacity may be
lower once site-specific technical and economic considerations are
addressed. Even if only a fraction of that geologic capacity is used,
CCS would play a sizeable role in mitigating US GHG emissions.
2. Why is GS under consideration as a climate change mitigation
technology?
Climate change is happening now, and the effects can be seen on
every continent and in every ocean. While certain effects of climate
change can be beneficial, particularly in the short term, current and
future effects of climate change pose considerable risks to human
health and the environment. There is now clear evidence that the
Earth's climate is warming (USEPA, 2010):
Global surface temperatures have risen by 1.3 degrees
Fahrenheit ([ordm]F) over the last 100 years.
Worldwide, the last decade has been the warmest on record.
The rate of warming across the globe over the last 50
years (0.24[ordm]F per decade) is almost double the rate of warming
over the last 100 years (0.13[ordm]F per decade).
Most of this recent warming is very likely the result of human
activities. Many human activities release greenhouse gases into the
atmosphere (such as the combustion of fossil fuels). The levels of
these gases are increasing at a faster rate than at any time in
hundreds of thousands of years.
Fossil fuels are expected to remain the mainstay of energy
production well into the 21st century, and increased concentrations of
CO2 are expected unless energy producers reduce
CO2 emissions to the atmosphere. For example, CCS would
enable the continued use of coal in a manner that greatly reduces the
associated CO2 emissions while other safe and affordable
alternative energy sources are developed in the coming decades. The
development and deployment of clean coal technologies including CCS
will be a key to achieving domestic emissions reductions.
GS is one of a portfolio of options that could be deployed to
reduce CO2 emissions to the atmosphere and help to mitigate
climate change. Other options include energy conservation, efficiency
improvements, and the use of alternative fuels and renewable energy
sources. Ensuring that GS is done in a manner that is protective of
USDWs will ensure the safety and efficacy of CO2 injection
for GS.
While predictions about large-scale availability and the rate of
CCS project deployment are subject to uncertainty, EPA analyses of
Congressional climate change legislative proposals (the American Power
Act of 2010 and the American Clean Energy and Security Act H.R. 2454 of
2009, both in the 111th Congress) indicate that CCS has the potential
to play a significant role in climate change mitigation scenarios. For
example, analysis of the American Power Act indicates that CCS
technology could account for 10 percent of CO2 emission
reductions in 2050 (USEPA, 2010f). These results indicate that CCS
could play an important role in achieving national greenhouse gas
reduction goals.
Today's final rule provides minimum Federal requirements for the
injection of CO2 to protect USDWs from endangerment as this
key climate mitigation technology is developed and deployed. It
clarifies requirements that apply to CO2 injection for GS,
provides consistency in requirements across the US, and affords
transparency about what requirements apply to owners or operators.
3. What are the unique risks to USDWs associated with GS?
Large CO2 injection volumes associated with GS, the
buoyant and mobile nature of the injectate, the potential presence of
impurities in the CO2 stream, and its corrosivity in the
presence of water could pose risks to USDWs. The purpose of today's
Class VI requirements for GS is to ensure the protection of USDWs,
recognizing that an improperly managed GS project has the potential to
endanger USDWs. Proper siting, well construction, operation, and
monitoring of GS projects are therefore necessary to reduce the risk of
USDW contamination.
It is expected that GS projects will inject large volumes of
CO2. These volumes will be much larger than are typically
injected in other well classes regulated through the UIC program, and
could cause significant pressure increases in the subsurface.
Supercritical or gaseous CO2 in the subsurface is buoyant,
and thus would tend to flow upwards if it were to come into contact
with a migration pathway, such as a fault, fracture, or improperly
constructed or plugged well. However, the pressures induced by
injection will also influence CO2 and mobilized fluids to
flow away from the injection well in all directions, including
laterally, upwards and downwards. When CO2 mixes with
formation fluids, a percentage of it will dissolve. The resulting
aqueous mixture of CO2 and water will sink due to a density
differential between the mixture and the surrounding fluids.
CO2 is also highly mobile in the subsurface (i.e., has a
very low viscosity), and, in the presence of water, CO2 can
be corrosive. These properties (of CO2), as well as the
large
[[Page 77235]]
volumes that may be injected for GS result in several unique challenges
for protection of USDWs in the vicinity of GS sites from endangerment.
While CO2 itself is not a drinking water contaminant,
CO2 in the presence of water forms a weak acid, known as
carbonic acid, that, in some instances, could cause leaching and
mobilization of naturally-occurring metals or other contaminants from
geologic formations into ground water (e.g., arsenic, lead, and organic
compounds). Another potential risk to USDWs is the presence of
impurities in the captured CO2 stream, which may include
drinking water contaminants such as hydrogen sulfide or mercury.
Additionally, pressures induced by injection may force native brines
(naturally occurring salty water) into USDWs, causing degradation of
water quality and affecting drinking water treatment processes.
Research studies have shown that the potential migration of injected
CO2 or formation fluids into a USDW could cause impairment
through one or several of these processes (e.g., Birkholzer et al.,
2008a).
Today's action addresses endangerment to USDWs by establishing new
minimum Federal requirements for the proper management of
CO2 injection and storage in several program areas,
including permitting, site characterization, AoR and corrective action,
well construction, mechanical integrity testing (MIT), financial
responsibility, monitoring, well plugging, PISC, and site closure. EPA
believes that proper GS project management will appropriately mitigate
potential risks of endangerment to USDWs posed by injection activities.
B. Under what authority is this rulemaking promulgated?
Today's rule is focused on USDW protection under the authority of
Part C of SDWA (SDWA, section 1421 et seq., 42 U.S.C. 300h et seq.).
Part C of the SDWA requires EPA to establish minimum requirements for
State\1\ UIC programs that regulate the subsurface injection of fluids
onshore and offshore under submerged lands within the territorial
jurisdiction of States\2\.
---------------------------------------------------------------------------
\1\ Reference to ``States'' includes Tribes and Territories
pursuant to 40 CFR 144.3.
\2\ The Submerged Lands Act and Territorial Submerged Lands Act
define the scope of territorial jurisdiction of States and
Territories respectively.
---------------------------------------------------------------------------
SDWA is designed to protect the quality of drinking water sources
in the US and prescribes that EPA issue regulations for State UIC
programs that contain ``minimum requirements for effective programs to
prevent underground injection which endangers drinking water sources''
(42 U.S.C. 300h et seq.). Congress further defined endangerment as
follows:
Underground injection endangers drinking water sources if such
injection may result in the presence in underground water which
supplies or can reasonably be expected to supply any public water
system of any contaminant, and if the presence of such contaminant
may result in such system's not complying with any national primary
drinking water regulation or may otherwise adversely affect the
health of persons (SDWA, section 1421(d)(2)).
Under this authority, the Agency promulgated a series of UIC
regulations at 40 CFR parts 144 through 148 for federally approved UIC
programs. The chief goal of any Federally approved UIC program (whether
administered by a State, Territory, Tribe or EPA) is the protection of
USDWs. This includes not only those formations that are presently being
used for drinking water, but also those that can reasonably be expected
to be used in the future. EPA has defined through its UIC regulations
that USDWs are underground aquifers with less than 10,000 milligrams
per liter (mg/L) total dissolved solids (TDS) and which contain a
sufficient quantity of ground water to supply a public water system (40
CFR 144.3). Section 1421(b)(3)(A) of the SDWA also provides that EPA's
UIC regulations shall ``permit or provide for consideration of varying
geologic, hydrological, or historical conditions in different States
and in different areas within a State.''
EPA promulgated administrative and permitting regulations, now
codified in 40 CFR parts 144 and 146, on May 19, 1980 (45 FR 33290),
and technical requirements, in 40 CFR part 146, on June 24, 1980 (45 FR
42472). The regulations were subsequently amended on August 27, 1981
(46 FR 43156), February 3, 1982 (47 FR 4992), January 21, 1983 (48 FR
2938), April 1, 1983 (48 FR 14146), May 11, 1984 (49 FR 20138), July
26, 1988 (53 FR 28118), December 3, 1993 (58 FR 63890), June 10, 1994
(59 FR 29958), December 14, 1994 (59 FR 64339), June 29, 1995 (60 FR
33926), December 7, 1999 (64 FR 68546), May 15, 2000 (65 FR 30886),
June 7, 2002 (67 FR 39583), and November 22, 2005 (70 FR 70513).
Under the SDWA, the injection of any ``fluid'' must meet the
requirements of the UIC program. A ``fluid'' is defined under 40 CFR
144.3 as any material or substance which flows or moves whether in a
semisolid, liquid, sludge, gas or other form or state, and includes the
injection of liquids, gases, and semisolids (i.e., slurries) into the
subsurface. The types of fluids currently injected into wells subject
to UIC requirements include: CO2 for the purposes of
enhancing recovery of oil and natural gas, water that is stored to meet
water supply demands in dry seasons, and wastes generated by industrial
users. CO2 injected for the purpose of GS is subject to the
SDWA.
C. How does this rulemaking relate to the greenhouse gas (GHG)
reporting program?
Today's rulemaking under SDWA authority complements the
CO2 Injection and GS Reporting rulemaking (subparts RR and
UU) under the Greenhouse Gas Reporting Program's Clean Air Act (CAA)
authority developed by EPA's Office of Air and Radiation (OAR).
The CAA defines EPA's responsibilities for protecting and improving
the nation's air quality and the stratospheric ozone layer. The GHG
Reporting Program requires reporting of GHG emissions and other
relevant information from certain source categories in the U.S. The GHG
Reporting Program, which became effective on December 29, 2009,
includes reporting requirements for facilities and suppliers in 32
subparts. For more detailed background information on the GHG Reporting
Program, see the preamble to the final rule establishing the GHG
Reporting Program (74 FR 56260, October 30, 2009).
In a separate action being finalized concurrently with this UIC
Class VI rulemaking, EPA is amending 40 CFR part 98, which provides the
regulatory framework for the GHG Reporting Program, to add reporting
requirements covering facilities that conduct GS (subpart RR) and all
other facilities that inject CO2 underground (subpart UU).
This data will inform Agency policy decisions under CAA sections 111
and 112 related to the use of CCS for mitigating GHG emissions. In
combination with data from other subparts of the GHG Reporting Program,
data from subpart UU and subpart RR will allow EPA to track the flow of
CO2 across the CCS system. EPA will be able to reconcile
subpart RR data on CO2 received with CO2 supply
data in order to understand the quantity of CO2 supply that
is geologically sequestered.
Owners or operators subject to today's rule are required to report
under subpart RR. Subpart RR establishes reporting requirements for
facilities that inject a CO2 stream for long-term
containment into a subsurface geologic formation, including sub-seabed
offshore formations. These facilities are required to develop and
implement a site-specific
[[Page 77236]]
Monitoring, Reporting, and Verification (MRV) plan which, once approved
by EPA (in a process separate from the UIC permitting process), would
be used to verify the amount of CO2 sequestered and to
quantify emissions in the event that injected CO2 leaks to
the surface. For more information on subpart RR, see http://www.epa.gov/climatechange/emissions/ghgrulemaking.html.
UIC requirements and Subpart RR requirements: EPA designed the
reporting requirements under subpart RR with consideration of the
requirements for Class VI well owners or operators in subpart H of part
146 of today's rule. Subpart RR builds on the Class VI requirements
outlined in today's rule with the additional goals of verifying the
amount of CO2 sequestered and collecting data on any
CO2 surface emissions from GS facilities as identified under
subpart RR of part 98.
The Agency acknowledges that there are similar data elements that
must be reported pursuant to requirements in this action and those
required to be reported under subpart RR. Specifically, owners or
operators subject to both regulations must report the amount (flow
rate) of injected CO2. The Class VI and subpart RR rules
differ, not only in purpose but in the specific requirements for the
measurement unit and collection/reporting frequency. The UIC program
Class VI rule requires that owners or operators report information on
the CO2 stream to ensure appropriate well siting,
construction, operation, monitoring, post-injection site care, site
closure, and financial responsibility to ensure protection of USDWS.
Under subpart RR, owners or operators must report the amount (flow
rate) of injected CO2 for the mass balance equation that
will be used to quantify the amount of CO2 sequestered by a
facility.
Table II-1--Comparison of Reporting Requirements Under Subpart RR and
Select UIC Class VI Requirements
------------------------------------------------------------------------
Reporting requirement Subpart RR UIC Class VI
------------------------------------------------------------------------
Quantity of CO2 transferred Yes................. N/A.
onsite.
Quantity (flow rate) of CO2 Yes................. Yes.
injected.
Fugitive and vented Yes................. N/A.
emissions from surface
equipment.
Quantity of CO2 produced Yes................. N/A.
with oil or natural gas
(ER).
Percent of CO2 estimated to Yes................. N/A.
remain with the oil and gas
(ER).
Quantity of CO2 emitted from Yes................. N/A.
the subsurface.
Quantity of CO2 sequestered Yes................. N/A.
in the subsurface.
Cumulative mass of CO2 Yes................. N/A.
sequestered in the
subsurface.
Monitoring plan for Yes................. Yes.\1\
detecting air emissions.
Monitoring plan for Yes................. N/A.
quantifying air emissions.
------------------------------------------------------------------------
(1) UIC Class VI rule allows for surface air/soil gas monitoring for
USDW protection at the discretion of the UIC Director.
EPA requires reporting of other data to satisfy various
programmatic needs. See section III of this preamble and associated
requirements in subpart H of part 146 and the preamble to subpart RR
for additional information on these specific requirements and their
purpose. Table II-1 provides a comparison of the major reporting
requirements in subpart RR and the extent to which there is overlap
with Class VI requirements. For the monitoring plan listed in Table II-
1, EPA will accept a UIC Class VI permit to satisfy certain subpart RR
MRV plan requirements. However, the reporter must include additional
information to outline how monitoring will achieve surface detection
and quantification of CO2. EPA is pursuing ways to better
integrate data management between the UIC and GHG Reporting Programs to
ensure that data needs are harmonized and the burden to regulated
entities is minimized.
D. How does this rulemaking relate to other federal authorities and GS
and CCS activities?
While the SDWA provides EPA with the authority to develop
regulations to protect USDWs from endangerment, it does not provide
authority to develop regulations for all areas related to GS. EPA
received a number of public comments on the proposal (73 FR 43492, July
25, 2008) indicating that the Agency should further explore
environmental and regulatory issues beyond the scope of the proposed
SDWA requirements for underground injection of CO2 for GS.
In response to comments and as a result of the presidential memo
``A Comprehensive Strategy on Carbon Capture and Storage'' (http://www.whitehouse.gov/the-press-office/presidential-memorandum-a-comprehensive-Federal-strategy-carbon-capture-and-storage), the Agency
continues to evaluate areas of potential applicability of other Federal
environmental statutes including, but not limited to, the CAA
(discussed in section II.C), the Resource Conservation and Recovery Act
(RCRA; discussed in section III.F.2), the Comprehensive Environmental
Response, Compensation, and Liability Act (CERCLA; discussed in section
III.F.2), and the Marine Protection, Research and Sanctuaries Act
(MPRSA; discussed in this section) to various aspects of GS and CCS.
Additionally, EPA and the US Department of Energy (DOE) co-chaired
the Interagency Task Force on Carbon Capture and Storage to develop a
plan to overcome the barriers to the widespread, cost-effective
deployment of CCS within 10 years, with a goal of bringing five to 10
commercial demonstration projects online by 2016. The Task Force's
report is available at http://www.whitehouse.gov/administration/eop/ceq/initiatives/ccs.
This section clarifies the distinction between today's rulemaking
and a number of other Federal rulemakings and initiatives.
National Environmental Protection Act (NEPA): The SDWA UIC program
is exempt from performing an Environmental Impact Statement (EIS) under
section 101(2)(C) and an alternatives analysis under section 101(2)(E)
of NEPA under a functional equivalence analysis. See Western Nebraska
Resources Council v. US EPA, 943 F.2d 867, 871-72 (8th Cir. 1991) and
EPA Associate General Counsel Opinion (August 20, 1979).
Marine Protection, Research, and Sanctuaries Act (MPRSA) and London
Protocol Implementation: Sub-seabed CO2 injection for GS
may, in certain circumstances, be defined as ocean dumping and subject
to regulation under the MPRSA. Application of the MPRSA would entail
coordination of the permitting processes under the SDWA and MPRSA,
pursuant to MPRSA sections 106(a) and (d). The substantive
environmental protection requirements of both statutes would need to be
satisfied prior to the
[[Page 77237]]
commencement of GS. The MPRSA was enacted in 1972 and implements the
London Convention on the Prevention of Marine Pollution by Dumping of
Wastes and Other Matter (the ``London Convention''). In 1996, the
Protocol to the London Convention (the ``London Protocol'') was
established. The Protocol stipulates that sub-seabed GS may be approved
provided that: (1) Disposal is into a sub-seabed geologic formation;
(2) the CO2 stream consists overwhelmingly of
CO2, with only incidental associated substances derived from
the source material and capture and sequestration process used; and,
(3) no wastes or other matter are added for the purpose of disposal.
The US has signed, but has not yet ratified, the Protocol. If the
Protocol is ratified, and implementing legislation is enacted, EPA, in
conjunction with other Federal agencies, will develop any necessary
regulations for implementing the provisions relevant to sub-seabed GS.
Bureau of Ocean Energy Management, Regulation, and Enforcement
(BOEMRE) Outer Continental Shelf Lands Act (OCSLA): BOEMRE, formerly
the Minerals Management Service (MMS), an agency within the Department
of the Interior, administers the OCSLA. As a result of recent OCSLA
amendments by the Energy Policy Act of 2005, the OCSLA provides for the
grant of leases, easements, or rights-of-way on the outer continental
shelf to the extent that an activity ``supports production,
transportation, or transmission of energy from sources other than oil
and gas'' and complies with the other provisions of OCSLA section 8(p).
Offshore geologic sequestration of CO2 on the outer
continental shelf may be subject to requirements under the OCSLA.
As indicated in the Report of the Interagency Task Force on Carbon
Capture and Storage (2010), ratification of the London Protocol and
associated amendment of the MPRSA as well as amendment of the Outer
Continental Shelf Lands Act (OCSLA) will ensure a comprehensive
statutory framework for the storage of CO2 on the outer
continental shelf.
Bureau of Land Management (BLM) Report to Congress: The BLM,
another agency within the Department of Interior, was required by
Section 714 of the Energy Independence and Security Act (EISA) of 2007
(Pub. L. 110-140, HR 6) to prepare a report outlining a regulatory
framework that could be applied to lands managed by the Bureau for
natural resource development, chiefly oil and gas. With assistance from
both EPA and the DOE, BLM submitted a Report to Congress titled
``Framework for Geological Carbon Sequestration on Public Land'' (BLM,
2009). This report affirms BLM's role in appropriately managing Federal
lands where GS injection projects may be sited. Additionally, the
report makes recommendations regarding approaches for effective
regulation of such activities under existing Federal authorities
including the SDWA and UIC program requirements.
United States Geological Survey (USGS) GS Capacity Methodology:
USGS, another agency within the Department of Interior and the primary
Federal agency responsible for national geological research, has been
an active participant with DOE and EPA at conferences and workshops on
CCS. In 2008, in response to the EISA, USGS initiated development of a
methodology for estimating the capacity to store CO2 in
geologic formations of the U.S. While previous capacity estimates
published by DOE/National Energy Technology Laboratory (NETL) have been
broad in scope (i.e., geologic basin-wide), the USGS is focusing on
small-scale, refined estimates. In 2009, USGS published a proposed,
risk-based methodology for GS capacity estimation. After input from
other agencies and stakeholders, USGS released a final report: A
Probabilistic Assessment Methodology for the Evaluation of Geologic
Carbon Dioxide Storage (USGS, 2010). The report is available at http://pubs.usgs.gov/of/2010/1127/. USGS continues to work on capacity
estimation as required under the EISA.
Internal Revenue Service (IRS) Guidance for Tax Incentives for GS
Projects: In response to the Energy Improvement and Extension Act of
2008, IRS, in consultation with EPA and DOE, issued guidance 2009-44
IRB (IRS, 2009) for taxpayers seeking to claim tax credits for
capturing and sequestering CO2 from a qualified facility in
the U.S. Under section 45Q of the Internal Revenue Code, a taxpayer who
stores CO2 under the predetermined conditions may qualify
for the tax credit ($10 per metric ton of qualified CO2 at
ER projects; $20 per metric ton of qualified CO2 for non-ER
projects). The taxpayer will be responsible for maintaining records for
inspection by the IRS and tax credit amounts will be adjusted for
inflation for any taxable year beginning after 2009. The Internal
Revenue Service published IRS Notice 2009-83 (available at: http://www.irs.gov/irb/2009-44_IRB/ar11.html#d0e1860) to provide guidance
regarding eligibility for the section 45Q tax credit, computation of
the section 45Q tax credit, reporting requirements for taxpayers
claiming the section 45Q tax credit, and rules regarding adequate
security measures for ``secure geological storage of CO2.''
Following publication of today's final Class VI requirements, and
as clarified in the guidance, taxpayers claiming the section 45Q tax
credit must follow the appropriate UIC requirements (e.g., Class II or
Class VI). The guidance also clarifies that taxpayers claiming section
45Q tax credit must follow the GS monitoring, reporting, and
verification procedures finalized in the CO2 Injection and
GS Reporting Rule that is part of the GHG Reporting Program.
General Accountability Office Reports on GS and CCS: The United
States General Accountability Office (GAO) has prepared, or is in the
process of preparing, several reports for Congressional requestors
related to the GS of CO2. In September 2008, GAO (GAO-08-
1080) completed a report related to assessing the application of CCS
technologies entitled: Climate Change--Federal Actions Will Greatly
Affect the Viability of Carbon Capture and Storage as a Key Mitigation
Option (GAO, 2008). In September 2010, GAO released a report entitled:
Climate Change, A Coordinated Strategy Could Focus Federal
Geoengineering Research and Inform Governance Efforts (GAO-10-903)
which describes innovative technologies that may alter climate change,
details current research activities, and clarifies how coordination
could inform subsequent climate science efforts. GAO initiated another
report (GAO-10-675) focused on the methods by which coal-fired power
plants may capture carbon emissions. The draft title of that study is:
Coal Power Plants--Opportunities Exist for DOE to Provide Better
Information on the Maturity of Key Technologies to Reduce Carbon
Emissions (GAO, 2010).
EPA will continue to coordinate internally and with other Federal
agencies to promote consistency in existing and future GS and CCS
initiatives.
E. What steps did EPA take to develop this rulemaking?
Today's final rule builds upon longstanding programmatic
requirements for underground injection that have been in place since
the 1980s and that are used to manage over 800,000 injection wells
nationwide. These programmatic requirements are designed to prevent
fluid movement into USDWs by addressing the potential pathways through
which injected fluids can migrate into USDWs and cause endangerment.
EPA coordinated with Federal and non-Federal entities on GS and CCS
to
[[Page 77238]]
determine how best to tailor existing UIC requirements to
CO2 for GS.
EPA has taken a number of steps in advance of today's action
including: (1) Developing guidance for experimental GS projects; (2)
conducting research; (3) conducting stakeholder coordination and
outreach; (4) issuing a proposed rulemaking and soliciting and
reviewing public comment; and, (5) publishing a Notice of Data
Availability (NODA) and Request for Comment to seek additional input on
the rulemaking.
1. Developing Guidance for Experimental GS Projects
In 2007, EPA issued technical guidance to assist State and EPA
Regional UIC programs in processing permit applications for pilot and
other small scale experimental GS projects. The guidance was developed
in cooperation with DOE and States, the Ground Water Protection Council
(GWPC), the Interstate Oil and Gas Compact Commission (IOGCC), and
other stakeholders. UIC Program Guidance #83: Using the Class V
Experimental Technology Well Classification for Pilot Carbon GS
Projects (USEPA, 2007) provides recommendations for permit writers
regarding the use of the UIC Class V experimental technology well
classification at demonstration GS projects while ensuring USDW
protection. Program guidance 83 is available at: http://www.epa.gov/safewater/uic/wells_sequestration.html. EPA is preparing
additional guidance for owners or operators and Directors regarding the
use of Class V experimental technology wells for GS following
promulgation of today's rule.
2. Conducting Research
EPA participated in and supported research to inform today's
rulemaking including: Supporting and tracking the development and
results of national and international CO2 GS field and
research projects; tracking GS-related State regulatory and legislative
efforts; and conducting technical workshops on issues associated with
CO2 GS. EPA described these research activities in detail in
the proposed rule (July 2008) and the NODA and Request for Comment
(August 2009). Additional information pertaining to these activities,
which are summarized below, may be found in the rulemaking docket.
a. Tracking the Results of CO2 GS Research Projects
To inform today's rulemaking, EPA tracked the progress and results
of national and international GS research projects. DOE leads field
research on GS in the U.S. in conjunction with the Regional Carbon
Sequestration Partnerships (RCSPs). Currently, DOE's NETL is developing
and/or operating GS projects, a number of which have either completed
injection or are in the process of injecting CO2. The seven
RCSPs are conducting pilot and demonstration projects to study site
characterization (including injection and confining formation
information, core data and site selection information); well
construction (well depth, construction materials, and proximity to
USDWs); frequency and types of tests and monitoring conducted (on the
well and on the project site); modeling and monitoring results; and
injection operation (injection rates, pressures, and volumes,
CO2 source and co-injectates). See section II.E.5 for more
information on the status of these projects.
Lawrence Berkeley National Laboratory (LBNL) research: EPA and DOE
are jointly funding work by the LBNL to study potential impacts of
CO2 injection on ground water aquifers and drinking water
sources. The preliminary results have been used to inform today's
rulemaking and are described in detail in section II.E.5.
In addition, EPA is funding an analysis by LBNL to integrate
experimental and modeling information. LBNL will characterize ground
water samples and aquifer mineralogies from select sites in the U.S.
and conduct controlled laboratory experiments to assess the potential
mobilization of hazardous constituents by dissolved CO2.
These experiments will provide data that will be used to validate
previous predictive modeling studies (of aquifer vulnerabilities to
potential CO2 leaks) which may be applied to other GS sites
in the future to assess the fate and migration of CO2-
mobilized constituents in ground water.
EPA's Office of Research and Development (ORD) GS research: EPA's
ORD engages Agency scientists and engineers in targeted research to
provide information to stakeholders and policy makers focused on areas
of national environmental concern, including climate change and GS. In
addition, ORD's National Center for Environmental Research (NCER)
provides extramural research grants for similar investigations through
a competitive solicitation process. In the fall of 2009, NCER awarded
six Science To Achieve Results (STAR) grants to recipients from major
universities and institutions. The awards were granted to projects
focused on Integrated Design, Modeling and Monitoring of GS of
Anthropogenic CO4 to Safeguard Sources of Drinking Water.
Work under the grants began in late 2009 and includes: Evaluating
potential impacts on drinking water aquifers of CO2-rich
dissolved brines (Clemson University); reducing the hydrologic and
geochemical uncertainties associated with CO2 sequestration
in deep, saline reservoirs (University of Illinois-Urbana); assessing
appropriate monitoring approaches at GS sites (University of Texas at
Austin); integrating design, monitoring, and modeling of GS to assist
in developing a practical methodology for characterizing risks to USDWs
(University of Utah); conducting laboratory experiments on shallow
aquifer systems to improve our understanding of geochemical and
microbiological reactions under low pH/high CO2 stress
(Columbia University); and, developing a set of computational tools to
model CO2 and brine movement associated with GS (Princeton
University).
International projects: EPA is tracking the progress of
international GS efforts. The largest and longest-running commercial,
large-scale projects in operation today include: The Sleipner Project
in the Norwegian North Sea (operating since 1996); the Weyburn enhanced
oil recovery (EOR) project in Saskatchewan, Canada (operating since
2000); the In Salah Gas Project in Algeria (operating since 2004); and
Snohvit, also in offshore Norway in the Barents Sea (operating since
2008). Other projects EPA is tracking include Otway in Australia
(operating since 2008); Ketzin in Germany (operating since 2008); and
Lacq in France (operating since 2009). EPA is also tracking two
projects that are anticipated to begin injection in the near future:
CarbFix in Iceland (anticipated to commence injection in 2010) and
Gorgon in Australia (anticipated to start in 2014). EPA evaluated
available information and experiences gained from these international
projects to inform today's action, as appropriate. Additional
information on how these and other international projects informed the
GS rulemaking is contained in the rulemaking docket (USEPA, 2010a).
b. Tracking State Regulatory Efforts
EPA has made it a priority to engage States and State organizations
throughout the rulemaking effort. EPA recognizes the complexity and
importance of the States' approaches to managing GS and is aware that
States are in various stages of developing statutory frameworks,
regulations,
[[Page 77239]]
technical guidance, and strategies for addressing CCS and GS.
Throughout the regulatory development process for the Class VI
regulation, EPA monitored States' regulatory efforts and approaches and
sought input on State activities related to addressing GS in the
proposed rule and NODA. At present, several States have published GS
regulations, while others are investigating and developing strategies
to address GS issues (e.g., management of multi-purpose injection wells
in oil and gas reservoirs). EPA is tracking regulatory efforts in 18
States: Colorado, Illinois, Kansas, Kentucky, Louisiana, Michigan,
Mississippi, Montana, New Mexico, New York, North Dakota, Oklahoma,
Pennsylvania, Texas, Utah, Washington, West Virginia, and Wyoming. EPA
is considering this information as it develops guidance on the primacy
application and approval process for Class VI wells. Information about
these State activities may be found in the docket for today's
rulemaking.
c. Conducting Technical Workshops on Issues Associated With
CO2 GS
EPA conducted a series of technical workshops with regulators,
industry, utilities, and technical experts to identify and discuss
questions relevant to the effective management of CO2 GS.
The workshops included the following: Measurement, Monitoring, and
Verification (in New Orleans, Louisiana on January 16, 2008);
Geological Setting and AoR Considerations for CO2 GS (in
Washington, DC on July 10-11, 2007); Well Construction and MIT (in
Albuquerque, New Mexico on March 14, 2007); a State Regulators'
Workshop on GS of CO2 (in collaboration with DOE in San
Antonio, Texas on January 24, 2007); an International Symposium on Site
Characterization for CO2 Geological Storage (co-sponsored
with LBNL in Berkeley, California on March 20-22, 2006); Risk
Assessment for Geologic CO2 Storage (co-sponsored with the
Ground Water Protection Council (GWPC) in Portland, Oregon on September
28-29, 2005); and Modeling and Reservoir Simulation for Geologic Carbon
Storage (in Houston, Texas on April 6-7, 2005). Summaries of these
workshops are available on EPA's Web site, at http://www.epa.gov/safewater/uic/wells_sequestration.html.
3. Conducting Stakeholder Coordination and Outreach
Throughout the rulemaking process, the Agency conducted public
workshops and public hearings and consulted with specific groups. EPA
representatives also attended meetings to explain the GS rulemaking
effort to interested members of the public and stakeholder groups.
Meeting information, notes, and summaries are available in the docket
for this rulemaking.
Public stakeholder coordination: EPA held public meetings to
discuss EPA's rulemaking approach, and consulted with other stakeholder
groups including non-governmental organizations (NGOs) to gain an
understanding of stakeholder interests and concerns. As part of this
outreach, EPA conducted two public stakeholder workshops with
participants from industry, environmental groups, utilities, academia,
States, and the general public. These workshops were held in December
2007 and February 2008. Workshop summaries are available on EPA's Web
site, at http://www.epa.gov/safewater/uic/wells_sequestration.html.
EPA also coordinated with GWPC, a State association that focuses on
ensuring safe application of injection well technology and protecting
ground water resources, and IOGCC, a chartered State association
representing oil and gas producing States throughout the rulemaking
process. Members of GWPC and IOGCC have specific expertise regulating
the injection of CO2 for the ER of oil and gas. EPA staff
attended national meetings and calls of these organizations, as well as
those held by technical and trade organizations, NGOs, States, and
Tribal organizations to discuss the rulemaking process and GS-specific
technical issues.
Consultation with the National Drinking Water Advisory Council
(NDWAC): In November 2008, during the public comment period for the
proposed rule, EPA met with NDWAC to discuss the proposed rule. At the
meeting, EPA presented information about the rulemaking and responded
to NDWAC questions and comments. NDWAC members indicated that they
understood the role of GS as a climate mitigation tool and encouraged
the Agency to continue to ensure the protection of USDWs. Since
proposal publication, EPA has met with NDWAC to discuss the status of
the rule and answer questions from NDWAC members. The notes of these
meetings are in the rulemaking docket.
Consultations with States, Tribes, and Territories: EPA engaged
States, Tribes, and Territories early and throughout the rulemaking
process to promote open communication and solicit input and feedback on
all aspects of the rule.
In April of 2008, prior to publication of the proposed rule, the
Agency sent background information about the rulemaking to all
Federally-recognized Indian Tribes and invited participation in a
dedicated GS consultation effort. EPA Regional Indian Coordinators
(RICs), the National Indian Workgroup (NIWG), the National Tribal
Caucus (NTC) and the National Tribal Water Council (NTWC) contacts were
also invited to participate in the consultation. EPA provided
additional rulemaking updates after publication of the proposal with
the above-mentioned groups as well as the National Water Program State-
Tribal Climate Change Council (STC3). The Fort Peck Assiniboine and
Sioux Tribes and the Navajo Nation received UIC program primacy for the
Class II program (under section 1425 of the SDWA) during the proposal
period for this rule (73 FR 65556; 73 FR 63639). Therefore, the Agency
initiated an additional consultation effort with these Tribal co-
regulators post-proposal. Summaries of the Tribal consultation
conference calls are included in the docket for today's rulemaking.
To ensure that States were consulted, the Agency also sent
background information about the rulemaking to States and State
organizations including the National Governors' Association, National
Conference of State Legislatures, Council of State Governments, and the
National League of Cities, among others, and held a dedicated
conference call on GS for interested State representatives in April
2008. Additionally, the Agency participated in rulemaking updates, as
appropriate, during national meetings and conferences, and gave
presentations to State organizations throughout development of the
rule. A summary of these efforts is included in the docket for today's
rulemaking.
Consultation with the United States Department of Health and Human
Services (HHS): Pursuant to SDWA section 1421, EPA consulted with the
U.S. Department of Health and Human Services during the rulemaking
process. Prior to proposal publication and rule finalization, the
Agency provided background information to HHS on the purpose and scope
of the rule. In June of 2010, EPA met with HHS to discuss the GS
rulemaking process as well as key elements of the proposed rule, the
Notice of Data Availability and Request for Comment, and the final
rule. During the June 2010 briefing, HHS participants asked about
technical criteria for Class VI wells and monitoring technologies
applicable to GS projects. The Agency addressed questions and comments
and HHS certified that the EPA satisfied consultation obligations under
the SDWA. The memo certifying this consultation is available in the
docket for today's rulemaking.
[[Page 77240]]
4. Proposed Rulemaking
On July 25, 2008, EPA published the proposed Federal Requirements
Under the Underground Injection Control (UIC) Program for Carbon
Dioxide (CO2) Geologic Sequestration (GS) Wells (73 FR 43492). The
Agency proposed a new class of injection well (Class VI), along with
technical criteria for permitting Class VI wells that tailored the
existing UIC regulatory framework to address the unique nature of
CO2 injection for GS, including:
Site characterization requirements that would apply to
owners or operators of Class VI wells and require submission of
extensive geologic, hydrogeologic, and geomechanical information on the
proposed GS site to ensure that Class VI wells are located in suitable
formations. EPA also proposed that owners or operators identify
additional containment/confining zones, if required by the Director, to
improve USDW protection.
Enhanced AoR and corrective action requirements (e.g.,
plugging abandoned wells) to delineate the AoR for GS projects using
computational modeling that accounts for the physical and chemical
properties of all phases of the injected CO2 stream. EPA
also proposed that owners or operators periodically reevaluate the AoR
around the injection well to incorporate monitoring and operational
data and verify that the CO2 is moving as predicted within
the subsurface.
Well construction using materials that are compatible with
and can withstand contact with CO2 over the life of the GS
project.
Multi-faceted monitoring of the CO2 stream,
injection pressures, the integrity of the injection well, groundwater
quality above the confining zone(s), and the position of the
CO2 plume and the pressure front throughout injection.
Comprehensive post-injection monitoring and site care
until it can be demonstrated that movement of the plume and pressure
front have ceased and the injectate does not pose a risk to USDWs.
Financial responsibility requirements to ensure that
financial resources would be available for corrective action, injection
well plugging, post-injection site care, and site closure, and
emergency and remedial response.
Following publication of the proposed rule, EPA initiated a 120-day
public comment period, which the Agency extended by 30 days to
accommodate requests from interested parties. The public comment period
for the proposed rule closed on December 24, 2008. EPA received
approximately 400 unique submittals from 190 commenters, including late
submissions. Commenters represented States; industry (including the oil
and gas industry, electric utilities, and energy companies);
environmental groups; and associations (including water organizations
and CCS associations).
During the public comment period, the Agency held public hearings
on the proposed rule in Chicago, IL on September 30, 2008 and in
Denver, CO on October 2, 2008. The two hearings collectively drew
approximately 100 people representing non-governmental organizations,
academia, industry, and other organizations. At the hearings, 29 people
submitted oral comments. Transcripts of the public hearings are in the
rulemaking docket (Docket ID Nos. EPA-HQ-OW-2008-0390-0185 and EPA-HQ-
OW-2008-0390-0256).
5. Notice of Data Availability and Request for Comment
Based on public comments received on the proposed rule, the Agency
identified several topics on which it needed additional public comment.
EPA published Federal Requirements Under the Underground Injection
Control (UIC) Program for Carbon Dioxide (CO2) Geologic
Sequestration (GS) Wells; Notice of Data Availability and Request for
Comment (74 FR 44802) on August 31, 2009, to describe additional topics
and request comment.
The NODA and Request for Comment presented new data and information
from three DOE-sponsored RCSP projects including: (1) The Escatawpa,
Mississippi project; (2) the Aneth Field, Paradox Basin project in
Southeast Utah; and, (3) the Pump Canyon Site project in New Mexico.
Additional information on these projects and responses to comments
received on the NODA and Request for Comment are available in the
docket for this rulemaking.
The NODA and Request for Comment also provided results of two GS-
related modeling studies conducted by the LBNL. The first study
(Birkholzer et al., 2008a) focused on the potential for GS to cause
changes in ground water quality as a result of potential CO2
leakage and subsequent mobilization of trace elements such as arsenic,
barium, cadmium, mercury, lead, antimony, selenium, zinc, and uranium.
Results from this model simulation suggest that if CO2 were
to leak into a shallow aquifer, mobilization of lead and arsenic could
occur, causing increases in the concentration of these trace elements
in ground water and potential for drinking water standard exceedances.
The second study modeled a theoretical scenario of GS in a
sedimentary basin to demonstrate the potential for basin-scale
hydrologic impacts of CO2 storage (Birkholzer et al.,
2008b). Model results indicate that basin-wide pressure influences may
be large and that predicted pressure changes could move saline water
upward into overlying aquifers if localized pathways, such as
conductive faults, are present. This example illustrates the importance
of basin-scale evaluation of reservoir pressures and far-field
pressures resulting from CO2 injection.
Additional information on LBNL's research and responses to comments
received on the NODA and Request for Comment are available in the
docket for this rulemaking.
The full publications on the LBNL research are also available on
LBNL's Web site at http://esd.lbl.gov/GCS/projects/CO2/index_CO2.html.
Lastly, the NODA and Request for Comment presented an alternative
to address public comments and concerns about the proposed injection
depth requirements for Class VI wells. Section III.D of today's action
contains more information on this subject.
Following publication of the NODA and Request for Comment, EPA
initiated a 45-day public comment period, which closed on October 15,
2009. EPA received 67 unique submittals from 64 commenters, many of
whom commented on the proposed rule. The Agency also held a public
hearing in Chicago, IL on September 17, 2009. Six people, representing
the oil and gas industry, electric utilities, water associations, and
academia attended the hearing. Two attendees submitted oral comments at
the hearing. A transcript of the public hearing is in the rulemaking
docket (EPA-HQ-OW-2008-0390-391).
F. How will EPA's adaptive rulemaking approach incorporate future
information and research?
In the preamble to the proposed rule (73 FR 43492), EPA explained
the need for and merits of using an adaptive approach to regulating
injection of CO2 for GS at 40 CFR parts 144 through 146. The
Agency indicated that this approach would provide regulatory certainty
to owners or operators, promote consistent permitting approaches, and
ensure that Class VI permitting Agencies are able to meet current and
future demand for Class VI permits. The proposal also clarified that,
as the Agency reviewed public comments, it would continue to evaluate
ongoing research and demonstration projects and gather other
[[Page 77241]]
relevant information as needed to make refinements to the rulemaking
process.
Many commenters strongly supported an adaptive, flexible approach
and suggested that the Agency initially take a conservative approach in
developing the UIC-GS requirements, with a provision for periodic
review of the rule to allow EPA to incorporate operational experience
as it is gained. These commenters also urged EPA not to wait until the
completion of DOE's pilot projects before finalizing the GS rule,
expressing a need for early regulatory certainty.
Some commenters expressed concerns about an adaptive approach,
stating that it could lead to regulatory uncertainty because
modifications could be made after the initial regulations are
promulgated. One commenter said that GS will not scale-up rapidly,
leaving ample time to study and assess possible regulatory approaches.
EPA agrees with commenters who supported an adaptive approach to
the UIC rulemaking for GS. Additionally, the Agency believes that there
is a need to have regulations in place during the earliest phases of GS
deployment. Finalizing today's requirements will allow early Class VI
wells to be permitted in a manner that addresses the unique
characteristics of CO2 injection for GS and allow early
projects to demonstrate successful confinement of CO2 in a
manner that is protective of USDWs. EPA also believes that an adaptive
approach enables the Agency to make changes to the program as necessary
to incorporate new research, data, and information about GS and
associated technologies (e.g., modeling and well construction). This
new information may increase protectiveness, streamline implementation,
reduce costs, or otherwise inform the requirements for GS injection of
CO2. The Agency plans, every six years, to review the
rulemaking and data on GS projects to determine whether the appropriate
amount and types of information and appropriate documentation are being
collected, and to determine if modifications to the Class VI UIC
requirements are appropriate or necessary. This time period is
consistent with the periodic review of National Primary Drinking Water
Standards under Section 1412 of SDWA.
G. How does this action affect UIC program implementation?
Under section 1421(b), the SDWA mandates that EPA develop minimum
Federal requirements for State UIC primary enforcement responsibility,
or primacy, to ensure protection of USDWs. In order to implement the
UIC program, States must apply to EPA for primacy approval. In the
primacy application, States must demonstrate: (1) State jurisdiction
over underground injection projects; (2) that their State regulations
are at least as stringent as those promulgated by EPA (e.g.,
permitting, inspection, operation, monitoring, and recordkeeping
requirements); and (3) that the State has the necessary administrative,
civil, and criminal enforcement penalty remedies pursuant to 40 CFR
145.13 authorities.
Once an application for primacy is received, the EPA Administrator
must review and approve or disapprove the State's primacy application.
EPA may also choose to approve or disapprove part of the application.
This determination is based on EPA's mandate under the SDWA as
implemented by UIC regulations established in 40 CFR part 144 through
146, and must be made by a rulemaking. Most States were authorized with
full or partial primacy for the UIC program in the early 1980s;
recently, two Tribes received primacy for the Class II program under
section 1425 of the SDWA. EPA directly implements the UIC program in
States that have not applied for primacy and States that have primacy
for part of the UIC program. A complete list of the primacy agencies in
each State is available at http://www.epa.gov/safewater/uic/primacy.html.
EPA may approve primacy for States as authorized by sections 1422
and 1425 of the SDWA. There are fundamental differences between how
these two statutory provisions are applied. Under section 1422, States
must demonstrate that their proposed UIC program meets the statutory
requirements under section 1421 and that their program contains
requirements that are at least as stringent as the minimum Federal
requirements provided for in the UIC regulations to ensure protection
of USDWs. Alternatively, States seeking primacy under section 1425 have
the option to demonstrate that their Class II program is an
``effective'' program to prevent underground injection that endangers
USDWs. Typically, these States follow the broader elements of a State
program submission established by EPA in 40 CFR part 145, subpart C. In
today's final rule, and in accordance with the SDWA section 1422, all
Class VI State programs must be at least as stringent as the minimum
Federal requirements finalized in today's rule.
UIC program implementation: Authority to administer a State UIC
program may be granted to one or more State agencies. States may choose
to include in their UIC primacy application a program that is
administered by multiple agencies. Under 40 CFR 145.23, in order for
more than one agency to be responsible for administration of the
program, each agency must have Statewide jurisdiction over the class of
injection activities for which they are responsible. Some States
administer their program for all injection well classes through a
single agency, whereas other States elect to divide the program between
agencies. For example, in most States, the Class II program is run by
an oil and gas agency and other well classes are run by a State
environmental agency (e.g., the Oklahoma Corporation Commission
oversees Class II wells in the State, and the Oklahoma Department of
Environmental Quality oversees other well classes). Additionally,
several States allow their oil and gas agencies to administer their UIC
program for specific well classes or subclasses provided they meet all
minimum Federal requirements (e.g., the Railroad Commission of Texas
oversees Class III brine-mining wells and Class V geothermal wells in
Texas). EPA believes that retaining this flexibility for States to
identify the appropriate agency to oversee Class VI wells will address
commenters' concerns that States should be afforded the opportunity to
determine which agency should oversee Class VI wells, and recognizes
the existing expertise of both State oil and gas agencies and deep well
injection programs, generally overseen by State environmental agencies.
Proposed approach for Class VI primacy and public comment: In the
proposed rule, EPA emphasized that States, Territories, and Tribes
seeking primacy for Class VI wells would be required to demonstrate
that their regulations are at least as stringent as the proposed
minimum Federal requirements. Recognizing that some States may wish to
obtain primacy for only Class VI wells, the Agency requested comment on
the merits and possible disadvantages of allowing primacy approval for
Class VI wells independent of other well classes.
Commenters representing States, industry, various trade
associations, and electric utilities supported the concept of allowing
independent primacy for Class VI wells. Commenters asserted that States
have the best knowledge of regional geology and areas in need of
special protection, along with necessary pre-existing relationships
with the regulated community. Commenters also agreed with EPA's
statement in the proposal that independent primacy would encourage
States to develop a
[[Page 77242]]
comprehensive regulatory program for all aspects of CCS (noting that
some States have already begun legislative efforts that are wider in
scope than the proposed Federal rule) and facilitate the rapid
deployment of commercial-scale CCS projects. They also asserted that
this approach is acceptable under the UIC program's statutory
authority.
Independent primacy for Class VI wells: Historically, EPA has not
accepted independent UIC primacy applications from States for
individual well classes under section 1422 of SDWA, as a matter of
policy. For example, if a State wanted primacy for Class I wells, the
State would also need to accept primacy for all other well classes
under section 1422 of SDWA (See section II.H for a description of well
classifications). This policy has been in place since the initiation of
the Federal UIC program and was intended to encourage States to take
full primacy for UIC programs, avoid Federal duplication of efforts,
and provide for administrative efficiencies.
However, based on comments on the UIC-GS proposed rule and
discussions with States and stakeholders, the Agency will allow
independent primacy for Class VI wells under Sec. 145.1(i) of today's
rule, and will accept applications from States for independent primacy
under section 1422 of the SDWA for managing UIC-GS projects under Class
VI. EPA believes that States are in the best position to implement UIC-
GS programs, and by allowing for independent Class VI primacy, EPA
encourages States to take responsibility for implementation of Class VI
regulations. The Agency's UIC program believes that this may, in turn,
help provide for a more comprehensive approach to managing GS projects
by promoting the integration of GS activities under SDWA into a broader
framework for States managing issues related to CCS that may lie
outside the scope of the UIC program or other EPA programs. This would
harness the unique efficiencies States can offer to promote adoption of
GS technology that incorporates issues in the broader scope of CCS,
while ensuring that USDWs are protected through the UIC regulatory
framework. Allowing States to apply only for Class VI primacy will also
shorten the primacy approval process.
EPA's willingness to accept independent primacy applications for
Class VI wells applies only to Class VI well primacy and does not apply
to any other well class under SDWA section 1422 (i.e., I, III, IV, and
V). EPA believes that this shift in its longstanding policy of
discouraging ``partial'' or ``independent'' primacy is warranted to
encourage States to seek primacy for Class VI wells and allow States to
address the unique challenges that would otherwise be barriers to
comprehensive and seamless management of GS projects.
The Agency recognizes that some States are currently addressing
off-facility surface access for corrective action and monitoring, pore
space ownership and trespass issues, and amalgamation of correlative
rights in depleted reservoirs for GS. Additionally, because GS
technologies are an important component of CCS, the Agency considers
the allowance for independent Class VI primacy important and unique to
this well class. This decision is expected to ensure that the Class VI
primacy application process does not serve as a barrier to GS and CCS
deployment. EPA will not consider applications for independent primacy
for any other injection well class under SDWA section 1422 other than
Class VI, nor will the Agency accept the return of portions of existing
1422 programs. EPA will continue to process primacy applications for
Class II injection wells under the authority of section 1425 of the
SDWA.
Today's final rule includes a new subparagraph Sec. 145.1(i) that
establishes EPA's intention to allow for independent primacy for Class
VI wells. The Agency is developing implementation materials to provide
guidance to States applying for Class VI primacy under section 1422 of
SDWA and to assist UIC Directors evaluating permit applications.
Effective date of the GS rule and Class VI primacy application and
approval timeframe: Today's rule, at Sec. 145.21(h), establishes a
Federal Class VI primacy program in States that choose not to seek
primacy for the Class VI portion of the UIC program within the approval
timeframe established under section 1422(b)(1)(B) of the SDWA. Under
Sec. 145.21(h), States will have 270 days following final promulgation
of the GS rule September 6, 2011 to submit a complete primacy
application that meets the requirements of Sec. Sec. 145.22 or 145.32.
Pursuant to the SDWA, this 270-day timeframe allows States that seek
primacy for the new Class VI wells a reasonable amount of time to
develop and submit their application to EPA for approval. EPA will
assist States in meeting the 270-day deadline by developing
implementation materials for States and conducting training on the
process of applying for and receiving primacy for Class VI wells under
section 1422 of SDWA. EPA will also assist States as they develop GS
regulations that are the equivalent of minimum Federal requirements and
plans to use an expedited process for approving primacy.
Although the SDWA allows the Administrator to extend the date for
submission of an application for up to 270 additional days for good
cause, the Agency has determined that it will not provide for an
extension for States applying for Class VI primacy. Instead, EPA
believes that, in light of national priorities for promoting climate
change mitigation strategies and Administration priorities for
developing and deploying CCS projects in the next few years, it is
important to have enforceable Class VI regulations in place nationwide
as soon as possible.
If a State does not submit a complete application during the 270-
day period, or EPA has not approved a State's Class VI program
submission, then EPA will establish a Federal UIC Class VI program in
that State after the 270-day application period closes. This will
ensure that tailored State- or Federally-enforceable requirements
applicable to GS projects will be in place nationwide as soon as
possible after rule finalization. Further, a clear, nationally-
consistent deadline will avoid potential confusion that may arise if
some States have approved Class VI programs and others do not. EPA will
publish a list of the States where the Federal Class VI requirements
have become applicable in the Federal Register and update 40 CFR part
147. It is important to note that, although the Agency is not accepting
extension requests, a State may, at any time in the future, apply for
primacy for the new GS requirements following establishment of a
Federal Class VI UIC program. If a State receives approval after the
270-day deadline (for a primacy application submitted either before or
after the deadline), EPA will publish a subsequent notice of the
approval as required by the SDWA; at that point, the State, rather than
EPA, will implement the Class VI program.
The Agency clarifies that States may not issue Class VI UIC permits
until their Class VI UIC programs are approved. During the first 270-
days and prior to EPA approval of a Class VI primacy application,
States without existing SDWA section 1422 primacy programs must direct
all Class VI GS permit applications to the appropriate EPA Region. EPA
Regions will issue permits using existing authorities and well
classifications (e.g., Class I or Class V), as appropriate.
States with existing UIC primacy for all non-Class VI well classes
under section 1422 that receive Class VI permit applications within the
first 270
[[Page 77243]]
days after promulgation of the final rule may consider using existing
authorities (e.g., Class I or Class V), as appropriate, to issue
permits for CO2 injection for GS while EPA is evaluating
their Class VI primacy application. EPA encourages States to issue
permits that meet the requirements for Class VI wells to ensure that
Class V and Class I wells previously used for GS can be re-permitted as
Class VI wells that meet the protective requirements of today's final
rule within one year of promulgation of the Class VI regulation,
pursuant to requirements at Sec. 146.81(c), with minimal additional
effort on the part of the owner or operator or the Director.
After the 270-day deadline, and until a State has an approved Class
VI program, EPA will establish and implement a Class VI program.
Therefore, all permit applications in States without Class VI programs
must be directed to the appropriate EPA Region in order for a Class VI
permit to be issued. In States where EPA directly implements the Class
VI program, Class I permits for CO2 injection for GS may no
longer be issued and Class V permits may only be issued to projects
eligible for such permits (see discussion of the relationship between
Class V and Class VI permits in Section II.H).
Streamlining the primacy approval process: In an effort to support
States with the Class VI primacy application process and respond to
comments received during the rulemaking process, today's rule includes
new regulatory language at Sec. Sec. 145.22 and 145.23 to streamline
and clarify the process for submission of Class VI primacy applications
and address the unique aspect of Class VI injection operations. For
example, EPA is allowing the electronic submission of required primacy
application information (e.g., letter from the Governor, program
description, Attorney General's statement, or Memorandum of Agreement).
The Agency is also allowing the use of existing reporting form(s),
e.g., existing UIC program forms or State equivalents, for Class VI
wells, as appropriate.
EPA will evaluate the efficiency and effectiveness of electronic
submittals as part of the adaptive approach to the GS rulemaking and
determine whether electronic submittal may be applicable to other UIC
primacy applications submitted to EPA for review and approval under
sections 1422 and 1425 of SDWA. Additionally, the Agency is developing
a Class VI Program Primacy Application and Implementation Manual that
describes, for States, the process of applying for and receiving
primacy for Class VI wells under section 1422 of SDWA. The Manual will
also provide tools designed to assist States with the development of
their primacy application and UIC Directors with evaluating permit
application information.
Unique requirements for Class VI permit applications: To address
the unique nature of Class VI injection operations, today's rule at
Sec. 145.23(f) includes new language describing the requirements for
Class VI State program descriptions. Specifically, Sec. 145.23(f)(1)
requires States to include a schedule for issuing Class VI permits for
wells within the State that require them within two years after
receiving program approval from EPA, and Sec. 145.23(f)(2) requires
States to include their permitting priorities, as well as the number of
permits to be issued during the first two years of program operation.
In addition, today's rule at Sec. 145.23(f)(4) requires the Director
of Class VI programs approved before December 10, 2011, to provide a
description of the process for notifying owners or operators of any
Class I wells previously permitted for the purpose of geologic
sequestration or Class V experimental technology wells no longer being
used for experimental purposes that will continue injection of carbon
dioxide for the purpose of GS that they must apply for a Class VI
permit pursuant to requirements at Sec. 146.81(c) within one year of
December 10, 2011. Sec. 145.23(f)(4) also requires the Director of a
Class VI Program approved after December 10, 2011, to provide a
description of the process for notifying owners or operators of any
Class I wells previously permitted for the purpose of geologic
sequestration or Class V experimental technology wells no longer being
used for experimental purposes that will continue injection of carbon
dioxide for the purpose of GS or Class VI wells permitted by EPA that
they must apply to the State program for a Class VI permit pursuant to
requirements at Sec. 146.81(c) within one year of Class VI program
approval. EPA is committed to working closely with and receiving input
from States during all stages of the GS permitting process,
irrespective of primacy status. Close coordination during program
implementation will minimize effort and burden on States and owners and
operators and streamline the administrative process for transferring
permits or permit applications when primacy is granted. These
requirements are tailored for Class VI wells to ensure that States are
prepared to review Class VI permit applications as soon as possible
following program approval; and, in light of the national priorities to
promote climate change mitigation strategies, such modifications of
Sec. 145.23 may help ensure expeditious implementation of Class VI
requirements across the country.
Today's rule, at Sec. 145.23(f)(13), requires States to describe
in their primacy application procedures for notifying any States,
Tribes, and Territories of Class VI permit applications where the AoR
is predicted to cross jurisdictional boundaries and for documenting
this consultation. This new requirement addresses comments on the
proposed rule and NODA and Request for Comment that Class VI operations
are likely to have larger AoRs that may cross jurisdictional boundaries
and necessitate trans-boundary coordination. At Sec. 145.23(f)(9), the
final rule also requires States receiving Class VI program approval to
incorporate information related to any EPA approved exemptions
expanding the areal extent of an existing Class II EOR/EGR aquifer
exemption for Class VI injection. This requirement complements aquifer
exemption requirements promulgated under today's rule and ensures that
State programs incorporate information regarding the specific location
(and any associated supporting data) into their program descriptions.
The Agency plans to review these requirements as part of the
adaptive rulemaking approach to ensure that the tailored requirements
are appropriate to ensure USDW protection from endangerment.
H. How does this rule affect existing injection wells under the UIC
program?
Today's rulemaking establishes a new class of injection well, Class
VI, for GS projects because CO2 injection for long-term
storage presents several unique challenges that warrant the designation
of a new well type.
When EPA initially promulgated its UIC regulations in 1980, the
Agency defined five classes of injection wells at 40 CFR 144.6, based
on similarities in the fluids injected, construction, injection depth,
design, injection practices, and operating techniques. These five well
classes are still in use today and are described below.
Class I wells inject industrial non-hazardous liquids,
municipal wastewaters, or hazardous wastes beneath the lowermost USDW.
These wells are among the deepest of the injection wells and are
subject to technically sophisticated construction and operation
requirements.
Class II wells inject fluids (e.g., CO2; brine)
in connection with conventional
[[Page 77244]]
oil or natural gas production, enhanced oil and gas production, and the
storage of hydrocarbons that are liquid at standard temperature and
pressure.
Class III wells inject fluids associated with the
extraction of minerals, including the mining of sulfur and solution
mining of minerals (e.g., uranium).
Class IV wells inject hazardous or radioactive wastes into
or above USDWs. Few Class IV wells are in use today. These wells are
banned unless authorized under a Federal or State-approved ground water
remediation project.
Class V includes all injection wells that are not included
in Classes I-IV. In general, Class V wells inject non-hazardous fluids
into or above USDWs; however, there are some deep Class V wells that
are used to inject below USDWs. This well class includes Class V
experimental technology wells including those permitted as GS pilot
projects.
The Agency acknowledges that owners or operators of wells regulated
under existing well classifications may want to change the purpose of
their injection activity. The following sections describe the
applicability of today's rule to owners or operators of existing wells
and considerations for Directors evaluating existing wells that may be
re-permitted as Class VI wells.
Class I wells: Wells previously permitted as Class I wells for GS,
including wells permitted prior to rule promulgation and wells
permitted during the 270-day period after rule promulgation, must apply
for Class VI permits within one year of promulgation by December 10,
2011, pursuant to requirements at Sec. 146.81(c). The Agency
anticipates that permit applications (e.g., Class I or Class V)
developed for CO2 GS following publication of today's rule
will follow the Class VI requirements and be designed to facilitate
efficient re-permitting as Class VI wells. Such forethought will allow
new Class VI permits to be issued with minimal additional effort on the
part of the owner or operator and the Director. Additional information
on Class V experimental technology wells is discussed in this section.
For additional information on permitting authorities and UIC program
implementation, see section II.G.
Class II CO2 injection wells designated for enhanced
recovery: Enhanced oil recovery (EOR) and enhanced gas recovery (EGR)
technologies, collectively referred to as enhanced recovery (ER), are
used in oil and gas reservoirs to increase production. Injection of
CO2 is one of several ER techniques that have successfully
been used to boost production efficiency of oil and gas by re-
pressurizing the reservoir, and in the case of oil, by also increasing
mobility. Injection wells used for ER are regulated through the UIC
Class II program.
CO2 currently injected for ER in the U.S. comes from
both natural and anthropogenic sources, which provide 79 percent and 21
percent, respectively, of CO2 supply (DOE NETL, 2008).
Natural CO2 sources consist of geologic domes in Colorado,
New Mexico, and Mississippi. Anthropogenic sources of CO2
supplied for ER today include natural gas processing, ammonia and
fertilizer production, and coal gasification facilities.
Historically, CO2 purchases comprise about 33 to 68
percent of the cost of a CO2-ER project (EPRI, 1999). For
this reason, CO2 injection volumes are carefully tracked at
ER sites. CO2 recovered from production wells during ER is
recycled (i.e., separated and re-injected), and at the conclusion of an
ER project as much CO2 as is feasible is recovered and
transported to other ER facilities for re-use. However, a certain
amount of CO2 remains underground. Current Class II ER
requirements do not require tracking and monitoring of the injectate;
therefore, the migration and fate of the unrecovered CO2 is
not documented.
As of 2008, there were 105 CO2-EOR projects within the
US (Oil and Gas Journal, 2008). The majority (58) of these projects are
located in Texas, and the remaining projects are located in
Mississippi, Wyoming, Michigan, Oklahoma, New Mexico, Utah, Louisiana,
Kansas, and Colorado. CO2-EOR projects recovered 323,000
barrels of oil per day in 2008, 6.5 percent of total domestic oil
production. A total of 6,121 CO2 injection wells among 105
projects were used to inject 51 million metric tons of CO2
(Oil and Gas Journal, 2008; EIA, 2009; DOE NETL, 2008). Compared to
CO2-EOR, CO2-EGR remains largely in the
development stage (e.g., Oldenburg et al., 2001).
Future deployment of CCS may fundamentally alter CO2-ER
in the U.S. DOE anticipates that many early GS projects will be sited
in depleted or active oil and gas reservoirs because the reservoirs
have been previously characterized for hydrocarbon recovery and may
have suitable infrastructure (e.g., wells, pipelines, etc.) in place.
Additionally, oil and gas fields now considered to be ``depleted'' may
resume operation because of increased availability and decreased cost
of anthropogenic CO2.
EPA believes that if the business model for ER changes to focus on
maximizing CO2 injection volumes and permanent storage, then
the risk of endangerment to USDWs is likely to increase. This is
because reservoir pressure within the injection zone will increase as
CO2 injection volumes increase. Elevated reservoir pressure
is a significant risk driver at GS sites, as it may cause unintended
fluid movement and leakage into USDWs that may cause endangerment.
Additionally, increasing reservoir pressure within the injection zone
as a result of GS will stress the primary confining zone (i.e.,
geologic caprock) and well plugs to a greater degree than during
traditional ER (e.g., Klusman, 2003). Finally, active and abandoned
well bores are much more numerous in oil and gas fields than other
potential GS sites, and under certain circumstances could serve as
potential leakage pathways. For example, in typical productive oil and
gas fields, a CO2 plume with a radius of about 5 km (3.1
miles) may come into contact with several hundred producing or
abandoned wells (Celia et al., 2004).
EPA proposed that the Class VI GS requirements would not apply to
Class II ER wells as long as any oil or gas production is occurring,
but would apply only after the oil and gas reservoir is depleted. Under
the proposed approach, Class II wells could be used for the injection
of CO2, as long as oil production is simultaneously
occurring from the same formation. The preamble to the proposal sought
comment on the merits of this approach.
Some commenters agreed with the proposed approach while others
suggested that the approach did not adequately address risks posed to
USDWs by injection operations transitioning from production to long-
term storage of CO2. A majority of commenters requested that
EPA develop specific criteria for this transition.
Consistent with these comments, EPA determined that owners or
operators of wells injecting CO2 in oil and gas reservoirs
for GS where there is an increased risk to USDWs compared to
traditional Class II operations using CO2 should be required
to obtain a Class VI permit, with some special consideration for the
fact that they are transitioning from a well not originally designed to
meet Class VI requirements. Additionally, EPA recognizes that further
clarification is needed to sufficiently characterize the factors that
lead to increased risks and warrant conversion from Class II to Class
VI.
Therefore, today's rule clarifies that Class VI requirements apply
to any CO2 injection project (regardless of formation
[[Page 77245]]
type) when there is an increased risk to USDWs as compared to
traditional Class II operations using CO2. Traditional ER
projects are not impacted by this rulemaking and will continue
operating under Class II permitting requirements. EPA recognizes that
there may be some CO2 trapped in the subsurface at these
operations; however, if there is no increased risk to USDWs, then these
operations would continue to be permitted under Class II.
EPA has developed specific, risk-based factors to be considered by
the Director in making the determination to apply Class VI requirements
to transitioning wells. EPA believes this approach provides the
necessary, site-specific flexibility while providing appropriate
protection of USDWs from endangerment. These risk-based factors for
determining whether Class VI requirements apply are finalized in
today's rule at Sec. 144.19 and include: (1) Increase in reservoir
pressure within the injection zone; (2) increase in CO2
injection rates; (3) decrease in reservoir production rates; (4) the
distance between the injection zone and USDWs; (5) the suitability of
the Class II AoR delineation; (6) the quality of abandoned well plugs
within the AoR; (7) the owner's or operator's plan for recovery of
CO2 at the cessation of injection; (8) the source and
properties of injected CO2; and (9) any additional site-
specific factors as determined by the Director. Any single factor may
not necessarily result in a determination that a Class II owner or
operator must apply for a Class VI permit; rather, all factors must be
evaluated comprehensively to inform a Director's (or owners' or
operators') decision. The Agency is also developing guidance to support
Directors and owners or operators in evaluating these factors and
making the determination on whether to apply Class VI requirements.
Owners and operators of Class II wells that are injecting carbon
dioxide for the primary purpose of long-term storage into an oil and
gas reservoir must apply for and obtain a Class VI permit where there
is an increased risk to USDWs compared to traditional Class II
operations using CO2. EPA expects that, in most cases, the
ER owners or operators will use these same factors to evaluate whether
there is an increased risk to USDWs. When an increased risk is
identified, the owner or operator must notify the Director of their
intent to seek a Class VI permit. Today's rule clarifies that the
Director has the discretion to make this determination in the absence
of an owner or operator notification and, in doing so, require the
owner or operator to apply for and obtain a Class VI permit in order to
continue injection operations (Sec. 144.19(a)). In the event that an
injection operation makes changes to the ER operation such that the
increased risk to USDWs warrants transition to Class VI and does not
notify the Director, the owner or operator may be subject to specific
enforcement and compliance actions to protect USDWs from endangerment,
including corrective action within the AoR, cessation of injection,
monitoring, and/or PISC under sections 1423 and 1431 of the SDWA.
The Agency acknowledges that some stakeholders and commenters are
concerned about the burden that a transition may impose on existing
programs. EPA believes that transition to Class VI is necessary to
ensure USDW protection but is allowing the constructed components of
Class II ER wells to be grandfathered into the Class VI permitting
regime at the discretion of the Director and pursuant to requirements
at Sec. 146.81(c), in order to facilitate the transition from Class II
to Class VI wells without undue regulatory burden. As outlined in
section II.G, today's rule clarifies that State oil and gas agencies
that oversee the Class II program in many States may assume regulatory
authority for Class VI by either a memorandum of understanding with the
Class VI primacy agency, or by obtaining primacy for the entire Class
VI program as long as it is identified in the State's program
description under Sec. 145.23. In this way, the same agency may
oversee the Class II and Class VI programs, streamlining the transition
process. State primary enforcement responsibility is discussed further
in section II.G.
As part of EPA's adaptive rulemaking approach for Class VI wells,
the Agency will collect data on transitioning Class II projects to
determine whether the factors at Sec. 144.19 adequately address risks
to USDWs and whether additional or amended Federal regulations or other
actions are warranted for transitioning wells from ER to long-term
storage of CO2.
Class V Experimental Technology Wells: Prior to finalization of the
Class VI regulation, a number of CO2 injection projects were
permitted as Class V experimental technology wells for the purpose of
testing GS technology in the U.S. Wells permitted under this
classification are designed for the purpose of testing new technology
that is of an experimental nature. EPA understands that some of the
wells previously permitted as Class V experimental technology wells may
no longer be used for this purpose. GS wells that are not being used
for experimental purposes must be re-permitted as Class VI wells and
will be subject to today's requirements.
In the preamble to the proposed rule, EPA described UIC Program
Guidance 83 (Using the Class V Experimental Technology Well
Classification for Pilot GS Projects) and the use of the Class V
experimental technology well classification (see section II.E.1 of
today's notice). EPA stated that the guidance will continue to apply to
experimental projects (as long as the projects continue to qualify as
experimental technology wells under the guidelines described in the
guidance) and to future projects that are experimental in nature.
Several commenters on the proposed rule asked EPA to clarify the
point at which Class V experimental technology wells should be re-
permitted as Class VI wells. Today's rule, at Sec. 146.81(c), requires
owners or operators of Class V experimental technology wells no longer
being used for experimental purposes (e.g., wells that will continue
injection of CO2 for the purpose of GS) to apply for Class
VI permits within one year of rule promulgation and to comply with the
requirements of today's rule. However, EPA is allowing the constructed
components of Class V experimental technology wells to be grandfathered
into the Class VI permitting regime at the discretion of the Director
and pursuant to requirements at Sec. 146.81(c).
Following promulgation of today's rule, only GS projects of an
experimental nature (i.e., to test GS technologies and collect data)
will continue to be classified, permitted, and regulated as Class V
experimental technology wells; and Class V wells are prohibited from
operating as non-experimental GS operations under Sec. 144.15.
Experimental projects are those whose primary purpose is to test new,
unproven technologies. EPA does not consider it appropriate to permit
CO2 injection wells that are testing the injectivity or
appropriateness of an individual formation (e.g., as a prelude to a
commercial-scale operation) as Class V experimental technology wells.
Such wells should be permitted as Class VI wells.
Other commenters suggested that owners or operators of wells
injecting CO2 into basalts, coal seams, and salt domes
should be able to seek a Class V experimental permit. EPA agrees that
the Class V experimental technology well classification may be
appropriate for these projects provided they are experimental in
nature. EPA expects that, following today's rule, a limited number of
experimental injection
[[Page 77246]]
projects testing GS technology will continue. EPA anticipates that
these projects will be small-scale and involve limited CO2
volumes. However, if these projects become larger scale and are no
longer experimental, they will need to be permitted as Class VI wells.
The construction, operation or maintenance of any non-experimental
Class V GS wells is prohibited (Sec. 144.15).
The Agency is preparing additional guidance for owners or operators
and Directors regarding the use of the Class V experimental technology
well classification for GS following promulgation of today's rule. The
guidance will assist owners and operators and Directors in determining
what constitutes a Class V experimental technology well for the
purposes of testing GS technology.
Grandfathering for Class I, Class II and Class V Experimental
Technology Wells: Recognizing that owners or operators of existing
Class I, Class II, and Class V experimental technology wells may seek
to change the purpose of their injection well, EPA proposed to give the
Director discretion to carry over or ``grandfather'' the construction
requirements (e.g., permanent, cemented well components) provided he or
she is able to make a determination that these wells would not endanger
USDWs. EPA sought comment on this approach and how the proposed
grandfathering provisions for existing wells may affect compliance with
Class VI construction requirements.
Nearly all industry commenters favored grandfathering of Class I,
II, and V well construction requirements for GS, indicating that most
wells are built to appropriate specifications and would have sufficient
mechanical integrity for GS in order to protect USDWs from
endangerment. These commenters cited oil and gas industry experience
with CO2 injection in the UIC Class II program and suggested
that this experience demonstrates that construction requirements for
Class II injection wells are sufficient to protect USDWs. Other
commenters asserted that grandfathering Class II construction will
expedite the transition of Class II ER projects to Class VI GS.
Several commenters were concerned that the structural modifications
that may be required for some existing Class II wells to comply with
the proposed injection well construction requirements at Sec. 146.86
may actually compromise the integrity of those wells. One commenter
also mentioned that pre-existing wells, including wells approved for
sequestration as Class I and/or Class II wells, have not been
constructed to the same standards. These existing wells penetrating the
injection zone may, therefore, become potential threats to USDWs.
In response, EPA recognizes that the oil and gas industry has
decades of experience injecting CO2 for ER and that many
Class V experimental technology wells, including those used in the
RCSP's projects, are specifically designed for injection of
CO2 and are being constructed to Class I non-hazardous waste
well specifications. In today's final rule, at Sec. 146.81(c), owners
or operators seeking to grandfather existing Class I, II, or V wells
for GS must demonstrate to the Director that the grandfathered wells
were engineered and constructed to meet the requirements at Sec.
146.86(a) and ensure protection of USDWs from endangerment in lieu of
requirements at Sec. 146.86(b) and Sec. 146.87(a). Based on the owner
or operator's demonstration, the Director will determine if a well is
appropriately constructed for GS. If the Director determines that the
construction is appropriate for GS, the well will be re-permitted as a
Class VI well and must meet the operational, testing and monitoring,
reporting, injection well plugging, and PISC and site closure
requirements in subpart H of part 146. If an owner or operator seeking
to grandfather an existing Class I, II, or V well to a Class VI well
cannot make this demonstration, then grandfathering of the constructed
well and re-permitting as a Class VI well is prohibited.
III. What is EPA's final regulatory approach?
Today's rule creates a new class of injection well (Class VI) under
the existing UIC program with new minimum Federal requirements that
protect USDWs from endangerment during underground injection of
CO2 for the purpose of GS. Today's action includes
requirements for the permitting, siting, construction, operation,
financial responsibility, testing and monitoring, PISC, and site
closure of Class VI injection wells that address the pathways through
which USDWs may be endangered. These requirements are tailored from
existing UIC program components to ensure that they are appropriate for
the unique nature of injecting large volumes of CO2 for GS
into a variety of geological formations to ensure that USDWs are not
endangered.
Today's rule retains many of the requirements for Class VI wells
that EPA proposed on July 25, 2008. However, based on a review of
public comments on the proposed rule and the NODA and Request for
Comment, EPA made several changes to the GS rule. These changes are
highlighted as follows and are described in today's publication.
Additional description of the adaptive rulemaking
approach. To ensure USDW protection and meet the potentially fast pace
of GS deployment, EPA plans to continue its adaptive rulemaking
approach for GS to incorporate new research, data, and information
about GS and associated technologies. See section II.F.
Elaboration on the rationale for allowing States to gain
Class VI primacy independent of other well classes. To encourage States
to take responsibility for implementation of Class VI regulations and
foster a more comprehensive approach to managing GS projects within a
broader framework for managing CCS issues, Sec. 145.21 of today's rule
allows States to gain primacy for Class VI wells independent of other
well classes. See section II.G.
Explanation of the considerations for permitting wells
that are transitioning from Class II to Class VI. To clarify the point
at which the purpose of CO2 injection transitions from ER
(i.e., a Class II well) to long-term storage (i.e., Class VI) and the
risk posed to USDWs increases and is greater than traditional ER
projects injecting CO2, today's rule at Sec. 144.19
contains specific, risk-based factors to be considered by owners or
operators and by Directors in making this determination. See section
II.H.
Incorporation of a process to allow Class VI well owners
or operators to seek a waiver from the injection depth requirements. To
provide flexibility to address concerns about geologic storage capacity
limitations, address injection depth on a site-specific basis, and
accommodate injection into different formation types. Today's rule, at
Sec. 146.95, allows owners or operators to seek a waiver of the Class
VI injection depth requirements provided they can demonstrate USDW
protection. Today's final rule also limits the use of aquifer
exemptions for Class VI well injection activities (Sec. 144.7(d)). See
section III.D.
Clarification of the requirements for submitting materials
to support Class VI permit applications. Today's rule specifies
separate requirements for information to be submitted with the permit
application (Sec. 146.82(a)) and information that must be submitted
before well operation is authorized (Sec. 146.82(c)). This
modification addresses comments that not all of the information to
support the proposed Class VI permit application requirements will be
available at the
[[Page 77247]]
time the operator develops their initial permit application, See
section III.A.
Addition of requirements for updating project-specific
plans. To ensure that management of GS projects reflect up-to-date
information, today's rule requires periodic reviews of the AoR and
corrective action, testing and monitoring, and emergency and remedial
response plans (Sec. 146.84(e), Sec. 146.90(j), and Sec. 146.94(d)).
Any significant changes to the plans require a permit modification
(under Sec. 144.39(a)(5)). See Sections III.F and III.K.
Increasing the frequency of AoR reevaluations. To address
concerns about the inherent uncertainties in modeling CO2
movement, the emerging nature of GS technology, and the importance of
targeting monitoring activities where risk to USDWs is greatest,
today's rule at Sec. 146.84(e) requires that the AoR for GS projects
be reevaluated at a fixed frequency, not to exceed five years as
specified in the AoR and corrective action plan, or when monitoring and
operational conditions warrant. See section III.B.
Clarification and expansion of financial responsibility
requirements for Class VI well owners or operators. To ensure that
financial resources are available to protect USDWs from endangerment,
today's rule (at Sec. 146.85) identifies qualifying financial
instruments, the time frames over which financial responsibility must
be maintained, procedures for estimating the costs of activities
covered by the financial instruments, procedures for notifying the
Director of adverse financial conditions, and requirements for
adjusting cost estimates to reflect changes to the project plans. See
section III.I.
Revisions to the GS site monitoring and plume tracking
requirements to ensure that the most appropriate methods are used to
identify potential risks to USDWs posed by injection activities, verify
predictions of CO2 plume movement, provide inputs for
modeling, identify needed corrective actions, and target other
monitoring activities. Today's rule, at Sec. 146.90(g), requires Class
VI well owners or operators to use direct methods to monitor for
pressure changes in the injection zone and to supplement these direct
methods with indirect, geophysical techniques unless the Director
determines, based on site-specific geology, that such methods are not
appropriate. See section III.F.
EPA believes that these changes will result in a clearer, more
protective approach to permitting GS projects across the U.S. while
still allowing for consideration of site specific variability.
In addition to protecting USDWs, today's rule provides a regulatory
framework to promote consistent approaches to permitting GS projects
across the U.S. and supports the development of a key climate change
mitigation technology.
Today's final GS rule contains tailored requirements for geologic
siting; AoR and corrective action; construction; operation; monitoring
and MIT; recordkeeping and reporting; well plugging, PISC, and site
closure; financial responsibility; emergency and remedial response;
public involvement; and permit duration of Class VI wells.
To develop today's final regulatory approach, EPA considered public
comments submitted in response to the proposed rule and the NODA and
Request for Comment. Sections III.A through L focus on the aspects of
the GS regulation that are tailored to the unique nature of GS and
highlight the changes between the proposed and final GS rule.
Additional background information is available in the preamble, NODA
and Request for Comment, and docket for this rulemaking.
A. Site Characterization
Today's final action requires owners or operators of Class VI wells
to perform a detailed assessment of the geologic, hydrogeologic,
geochemical, and geomechanical properties of the proposed GS site to
ensure that GS wells are sited in appropriate locations and inject into
suitable formations. Class VI well owners or operators must also
identify additional confining zones, if required by the Director, to
increase USDW protection.
Site characterization is a fundamental component of the UIC
program. Owners or operators must identify the presence of suitable
geologic characteristics at a site to ensure the protection of USDWs
from endangerment associated with injection activities. Existing UIC
regulations for siting injection wells include requirements to identify
geologic formations suitable to receive injected fluids and confine
those fluids such that they are isolated in order to ensure protection
of USDWs from endangerment. Today's rule similarly requires the owner
or operator to perform a detailed assessment to evaluate the presence
and adequacy of the various geologic features necessary to receive and
confine large volumes of injected CO2 so that the injection
activities will not endanger USDWs. Today's requirements for Class VI
wells are based extensively on the long-standing site characterization
requirements of the UIC program, and are tailored to address the unique
nature of GS. Specifically, Sec. 146.83 of today's rule sets forth the
criteria for a GS site that is geologically suitable to receive and
confine the injected CO2, while Sec. 146.82 identifies the
specific information an owner or operator must submit to the Director
in order to demonstrate that the site meets the minimum siting criteria
at Sec. 146.83.
Today's rule at Sec. 146.83 retains the minimum criteria for
siting as proposed. Owners or operators of Class VI wells must provide
extensive geologic data to demonstrate to the Director that wells will
be sited in areas with a suitable geologic system comprised of a
sufficient injection zone and a confining zone free of transmissive
faults or fractures to ensure USDW protection. In addition, the Agency
proposed that owners or operators must, at the Director's discretion,
identify and characterize additional (secondary) confinement zones that
will impede vertical fluid movement. EPA sought comment on the merits
of identifying these additional zones, and received many comments on
this topic.
The majority of commenters who commented on the requirement to
identify additional zones at the Director's discretion disagreed with
the proposed approach, saying that the requirement is unnecessary if
the injection zone and confining zones were competent, and believing it
would reduce the number of GS storage site opportunities. EPA disagrees
with the commenters' assertion that secondary confinement and
containment zones should not be required under the final rule and
received no data or information to support commenters' assertion that
characterizing secondary confining zones is technically infeasible.
Therefore, EPA is retaining the requirement that owners or operators
must, at the Director's discretion, identify and characterize
additional confining zones. In certain geologic settings, these zones
may be appropriate to ensure USDW protection, impede vertical fluid
movement, allow for pressure dissipation, and provide additional
opportunities for monitoring, mitigation and remediation (Sec.
146.83(b)).
Today's rule at Sec. 146.82 establishes the detailed information
that owners or operators must submit to the Director to demonstrate
that the site is suitable for GS. As part of the site characterization
and permit application process, owners or operators of Class VI wells
are required to submit maps and cross sections describing subsurface
geologic formations and the general vertical and
[[Page 77248]]
lateral limits of all USDWs within the AoR. The Agency anticipates that
owners or operators will use existing wells within the AoR or construct
stratigraphic test wells for purposes of data collection; such wells
may be subsequently converted to monitoring wells. Site
characterization identifies potential risks and eliminates unacceptable
sites, e.g., sites with potential seismic risk or sites that contain
transmissive faults or fractures. Data and information collected during
site characterization also inform the development of construction and
operating plans, provide inputs for AoR delineation models, and
establish baseline information to which geochemical, geophysical, and
hydrogeologic site monitoring data collected over the life of the
injection project can be compared.
Today's rule also requires owners or operators to submit, with
their permit applications, a series of comprehensive site-specific
plans: An AoR and corrective action plan, a monitoring and testing
plan, an injection well plugging plan, a PISC and site closure plan,
and an emergency and remedial response plan. This requirement for a
comprehensive series of site-specific plans is new to the UIC program.
The Director will evaluate all of the plans in the context of the
geologic data, proposed construction information, and proposed
operating data submitted as part of the site characterization process,
to ensure that planned activities at the facility are appropriate to
the site-specific circumstances and address all risks of endangerment
to USDWs.
EPA sought comment on the proposed submissions required for permit
applications, and received many comments indicating that not all of the
information listed in the proposed rule at Sec. 146.82 will be
available at the time the operator develops their initial permit
application. In response to comments, EPA revised Sec. 146.82 so that
the final regulation specifies separate requirements for information to
be submitted with the permit application (Sec. 146.82(a)) and
information that must be submitted before well operation is authorized
(Sec. 146.82(c)).
Today's final rule includes requirements at Sec. 146.82(a)(2) that
the owner or operator identify all State, Tribal, and Territorial
boundaries within the AoR. Based on the information provided to the
Director during the initiation of the permit application, the Director,
pursuant to requirements at Sec. 146.82(b), must provide written
notification to all States, Tribes, and Territories in the AoR to
inform them of the permit application and to afford them an opportunity
to be involved in any relevant activities (e.g., development of the
emergency and remedial response plan (Sec. 146.94)). These
requirements respond to comments received regarding the anticipated
large AoRs and injection volumes for GS and the importance of ensuring
trans-boundary coordination across the U.S. The Agency encourages
transparency in the permitting process and anticipates that State-
State/State-Tribal communication on GS permitting will facilitate
information sharing and encourage safe, protective projects.
The final GS permitting requirements provided in today's rule in
conjunction with the minimum siting requirements at Sec. 146.83 enable
flexibility and the discretion of the permitting authority when
appropriate, while ensuring USDW protection. This flexibility and
permitting authority discretion serves to maximize efficiencies for
owners or operators and permitting agencies. The rule enables owners or
operators to choose from the variety of technologies and methods
appropriate to their site-specific conditions. At the same time, the
rule provides the foundation for national consistency in permitting of
GS projects. To promote national consistency, the Agency is developing
guidance to support comprehensive site characterization required under
today's rule.
B. Area of Review (AoR) and Corrective Action
Today's rule at Sec. 146.84 enhances the existing UIC requirements
for AoR and corrective action to require computational modeling of the
AoR for GS projects that accounts for the physical and chemical
properties of the injected CO2 and is based on available
site characterization, monitoring, and operational data. Owners or
operators must periodically reevaluate the AoR to incorporate
monitoring and operational data and verify that the CO2 is
moving as predicted within the subsurface.
AoR modeling and reevaluation are important components of the
overall proposed strategy to track the CO2 plume and
pressure front through an iterative process of site characterization,
modeling, and monitoring at GS sites. This approach addresses the
unique and complex movement of CO2 at GS sites.
1. AoR Requirements
Under the UIC program, EPA established an evaluative process to
determine that there are no features near an injection well (such as
faults, fractures or artificial penetrations) where injected fluid
could move into a USDW or displace native fluids into USDWs resulting
in endangerment to USDWs. Existing UIC regulations require that the
owners or operators define the AoR, within which they must identify
artificial penetrations (regardless of property ownership) and
determine whether they have been properly completed or plugged. The AoR
determination is integral to assessing geologic site suitability
because it requires the delineation of the expected extent of the
carbon dioxide plume and associated pressure front and identification
and evaluation of any penetrations that could result in the
endangerment of USDWs. For existing injection well classes (I through
V), the AoR is defined either by a fixed radius around the injection
well or by a simple radial calculation (40 CFR 146.6).
AoR and corrective action plan: EPA proposed that owners or
operators of Class VI wells prepare, maintain, and comply with a plan
to delineate the AoR for a proposed GS project, periodically reevaluate
the delineation, and perform corrective action that meets the
requirements of this section and is acceptable to the Director.
Commenters supported the proposed requirement for an AoR and corrective
action plan, particularly advocating updates that ensure that
facilities are being properly managed to address changing circumstances
(e.g., addition of monitoring wells or operational changes). The Agency
is developing guidance that describes the content of project plans
required in the GS rule, including the AoR and corrective action plan.
Today's final rule retains the requirement for owners or operators
to develop and implement an AoR and corrective action plan; the
approved plan will be incorporated into the Class VI permit and will be
considered permit conditions; failure to follow the plan will result in
a permit violation under SDWA section 1423. Owners or operators must
also review the AoR and corrective action plan following the most
recent AoR reevaluation and submit an amended plan, or demonstrate to
the Director that no amendment to the AoR and corrective action plan is
needed (Sec. 146.84(e)(4)). The iterative process by which this and
other required plans are reviewed throughout the life of a project will
promote an ongoing dialogue between owners or operators and the
Director. Tying the plan reviews to the AoR reevaluation frequency is
appropriate to ensure that reviews of the plans are conducted on a
defined schedule, if there is a change in the AoR, or if other
circumstances change, while adding little burden if the AoR
reevaluation
[[Page 77249]]
confirms that the plan is appropriate as written. The plan review
process also supports development and review of effective testing and
monitoring programs. Additional information on updates to the AoR and
corrective action plan is discussed in subsequent sections.
AoR definition: In the proposed rule, EPA defined the AoR for a GS
project as ``the region surrounding the GS project that may be impacted
by the injection activity,'' and stated that ``the AoR is based on
computational modeling that accounts for the physical and chemical
properties of all phases of the injected CO2 stream.''
Several commenters stated that the proposed AoR definition for Class VI
wells was vague and open to broad interpretation, which could lead to
overly large or small AoRs. Other commenters believed that specific
CO2 phases and areas of quantitative measures of elevated
pressure should be included in the definition.
EPA evaluated all comments on the AoR definition, and determined
that a performance-based definition provides sufficient instruction
regarding the region that should be included within the AoR. However,
to provide additional clarity, EPA modified the Class VI AoR definition
for today's final rulemaking. The AoR is defined in the final rule as,
``the region surrounding the geologic sequestration project where USDWs
may be endangered by the injection activity. The AoR is delineated
using computational modeling that accounts for the physical and
chemical properties of all phases of the injected CO2 stream
and displaced fluids and is based on available site characterization,
monitoring, and operational data as set forth in Sec. 146.84.'' The
Agency is developing guidance on AoR and corrective action to support
AoR delineation (i.e., including regions of the CO2 plume
and pressure front).
Use and applicability of computational models: EPA proposed that
the AoR for Class VI wells be determined using sophisticated
computational modeling that accounts for multiphase flow and the
buoyancy of CO2, and is informed by site characterization
data. EPA proposed that any computational model that meets minimum
Federal requirements and is acceptable to the Director may be used,
including proprietary models. EPA sought comment on the use and
applicability of computational modeling and allowing the use of
proprietary models for GS AoR delineation.
Many commenters agreed with EPA that computational multiphase
modeling is the most accurate method of delineating the AoR of GS
sites. Several commenters also provided detailed technical suggestions
regarding how modeling should be conducted. Some commenters opposed the
use of computational models, stating that they are overly complicated
to use and interpret and are not warranted for protection of USDWs.
EPA agrees with commenters who support the use of computational
modeling, and retains the requirement in today's rule at Sec.
146.84(a). The Agency is developing guidance on AoR and corrective
action to support the use of computational modeling for AoR
delineation. Available data from pilot projects and research studies
(e.g., Schnaar and Digiulio, 2009) support today's final approach of
requiring the use of computational models to delineate the AoR for GS
sites.
Comments were submitted both in support of and against allowing the
use of proprietary models. Several commenters who supported allowing
the use of proprietary models said that allowing the use of these
models will save costs and increase efficiency, as many existing
CO2 injection projects currently rely on proprietary models.
However, commenters suggested that the Director be given access to the
model in order to fully evaluate results and modeling assumptions.
Commenters that opposed the use of proprietary models did not believe
that such models are sufficiently transparent, and believed that the
Director would not be able to replicate the results.
EPA's final approach allows the use of proprietary models at the
discretion of the Director. EPA does not agree with commenters who
believe that the use of proprietary models will prohibit full
evaluation of model results and assumptions. Several available
proprietary models meet minimum Federal requirements for use in AoR
delineation and their use has been documented in peer-reviewed research
studies. Class VI well owners or operators, including those using
proprietary AoR delineation models, are required to disclose the code
assumptions, relevant equations, and scientific basis to the
satisfaction of the Director. To ensure that all predictive models used
for AoR delineation are meeting the Agency's intent, EPA will collect
and review project data on models used in early GS projects as part of
its adaptive rulemaking approach. See section II.F.
AoR reevaluation: EPA proposed that the AoR delineation be
reevaluated periodically over the life of the project in order to
incorporate CO2 monitoring data into models to ensure
protection of USDWs from endangerment. Under the proposed approach, AoR
reevaluation would occur at a minimum of every 10 years during
CO2 injection, or when monitoring data and modeling
predictions differ significantly. EPA sought comment on the requirement
for reevaluation every 10 years and what conditions would merit
reevaluation of the AoR.
The majority of commenters agreed that AoR reevaluations are
necessary, citing the large volumes of CO2 that may be
injected, the uncertainty of CO2 movement in the subsurface,
the need to incorporate monitoring data, and the lack of experience in
tracking large volumes of CO2. EPA agrees with commenters
who supported the proposed approach for periodic AoR reevaluation. EPA
believes that in order to sufficiently protect USDWs from endangerment,
the CO2 plume and pressure front should be tracked over the
lifetime of the project using an iterative approach of site
characterization, modeling, and monitoring. Periodic AoR reevaluation,
as required in today's final action, is an integral component of this
approach. EPA believes that the AoR reevaluation is an efficient use of
resources and notes that if the CO2 plume and pressure front
are moving as predicted, the burden of the AoR reevaluation requirement
will be minimal. In cases where the observed monitoring data agree with
model predictions, an AoR reevaluation may simply consist of a
demonstration to the Director that monitoring data validate modeled
predictions.
Several commenters supported the proposed reevaluation timeframe of
a minimum of 10 years or when monitoring and modeling data differ.
However, many commenters believed that 10 years was too infrequent and
suggested more frequent reevaluations or basing the reevaluation
timeframe on a performance standard, given the potential risks posed by
these projects to USDWs and the general uncertainty related to
CO2 movement at GS projects. Based on consideration of
public comments, EPA agrees that reevaluations of the AoR every 10
years may not be sufficient, and today's final approach requires an AoR
reevaluation at a minimum of once every five years, or when monitoring
data and modeling predictions differ significantly. EPA believes that
this revised frequency addresses commenters' concerns about the
inherent uncertainties in modeling CO2 movement, the
emerging nature of GS technology, and the importance of targeting
monitoring activities where
[[Page 77250]]
risk of endangerment to USDWs is greatest.
2. Corrective Action Requirements
EPA proposed that owners or operators of Class VI wells identify
and evaluate all artificial penetrations within the AoR. Based on this
review, owners or operators, in consultation with the Director, would
identify the wells that need corrective action to prevent the movement
of CO2 or other fluids into or between USDWs. Owners or
operators would perform corrective action to address deficiencies in
any wells (regardless of ownership) that are identified as potential
conduits for fluid movement into USDWs. This inventory and review
process is similar to what is required of Class I and Class II
injection well owners or operators. The proposal did not prescribe any
specific methods or cements that should be used for corrective action,
but stated that the methods used must be appropriate for CO2
injection and compatible with all fluids.
Phased corrective action: Due to the anticipated large size of the
AoR for Class VI wells, EPA proposed allowing owners or operators to
conduct corrective action on a phased basis during the lifetime of the
project, at the discretion of the Director. In these cases, corrective
action would not need to be conducted throughout the entire AoR prior
to injection. Corrective action would only be necessary in areas near
the injection well with a high certainty of CO2 exposure
during the first years of injection as informed by site-
characterization data and model predictions. Artificial penetrations in
areas farther from the injection well would be addressed after
injection has commenced, but prior to CO2 plume and pressure
front movement into that area. The proposal sought comment on allowing
for phased corrective action at the discretion of the Director.
The majority of commenters agreed with EPA's proposed approach of
allowing phased corrective action at the Director's discretion. Most
commenters believed that phased corrective action is a practical and
cost effective approach. However, some commenters argued that phased
corrective action should be allowed at all sites and not left to
Director's discretion. Others argued that specific timeframes (e.g.,
two to five years) for corrective action should be mandated to ensure
that wells are addressed prior to plume movement into that area.
Several State commenters disagreed with EPA's proposal to allow phased
corrective action and believed that all corrective action should be
completed prior to injection.
EPA agrees with commenters who supported allowing for phased
corrective action at the discretion of the Director, and retains this
provision in today's final regulation at Sec. 146.84(d). Phased
corrective action may provide many benefits to a project including
spreading corrective action costs throughout the life of a GS project,
avoiding delays in project start-up, allowing for use of future,
improved corrective action techniques, and addressing unanticipated
changes in the movement of the CO2 plume or pressure front.
Given the wide range of conditions and site-specific considerations
unique to GS sites, Director's discretion is appropriate as Directors
are in the best position to make decisions about the appropriateness of
phased corrective action.
EPA agrees with commenters that corrective action on wells should
be completed in advance of the anticipated arrival of the
CO2 plume or pressure front. However, it is not appropriate
to set a specific timeframe for completing corrective action because
CO2 plume movement will be site-specific and may change over
the life of a GS project. Instead, decisions regarding the timing of
corrective action will be incorporated into the approved AoR and
corrective action plan for each project based on project-specific
information. The Agency is developing guidance on AoR and corrective
action for GS sites, which addresses the types of issues these
commenters raise.
C. Injection Well Construction
Today's rule finalizes requirements (at Sec. 146.86) for the
design and construction of Class VI wells using materials that can
withstand contact with CO2 over the life of the GS project
in order to prevent movement of fluids into USDWs.
Proper construction of injection wells provides multiple layers of
protection to ensure the prevention of fluid movement into USDWs.
Today's final approach is based on existing construction requirements
for surface casing, long-string casing, and tubing and packer for Class
I hazardous waste injection wells, with modifications to address the
unique physical characteristics of CO2, including its
buoyancy relative to other fluids in the subsurface and the potential
presence of impurities in captured CO2. In addition to
protecting USDWs, today's comprehensive construction requirements
respond to concerns about GS project safety and potential impacts on
USDWs.
Surface and long-string casing requirements: EPA proposed that
surface casing for a Class VI well be set through the base of the
lowermost USDW and cemented to the surface; and, that the long-string
casing be cemented in place along its entire length from the injection
zone to the surface. This is consistent with existing requirements for
Class I hazardous waste injection wells.
EPA proposed the enhanced casing requirements for Class VI wells to
maintain additional barriers to CO2 leakage outside of the
injection zone, and solicited comment on the proposed construction
requirements related to the depth of the surface casing. Commenters
objecting to the proposed requirements argued that the surface casing
and long-string casing requirements may preclude GS in areas with very
deep USDWs. They commented that, under certain circumstances, it would
be too burdensome or technologically infeasible to construct the
casings to the required depth. Commenters also argued that these
requirements would adversely impact acceptance of GS and would slow
down large-scale deployment of this climate change mitigation
technology. These commenters recommended that the rule allow more
flexibility regarding surface and long-string casing depths to
accommodate varied conditions where Class VI wells may be constructed
throughout the U.S. Other commenters agreed with the Agency's proposed
long-string casing requirements for Class VI wells, stating that the
requirements prevent undesirable migration of fluids behind the casing
and provide maximum zonal isolation.
The Agency disagrees that the surface and long-string casing
requirements are not flexible enough to address the varied geological
formations and aquifer characteristics across the United States. EPA
adds that cementing of deep wells has been performed successfully by
owners or operators of Class I wells at depths up to 12,000 feet
(USEPA, 2001). Protection of USDWs from endangerment, regardless of
their depth or stratigraphic location, is the primary mission of the
UIC program and the purpose of all requirements for injection wells.
However, in order to address concerns about lack of flexibility
while ensuring USDW protection, EPA modified the surface casing
requirements at Sec. 146.86(b) to provide owners or operators
flexibility regarding how to complete the surface casing in situations
where the cement cannot be re-circulated to the surface. The regulation
does not specify how the cementing
[[Page 77251]]
must be accomplished (e.g., single or staged circulation); instead, it
allows flexibility for owners or operators to propose alternative
cementing methods that provide a sufficient cement seal and prevent
fluid movement through any channels adjacent to the well bore under all
circumstances in order to protect USDWs from endangerment. The Agency
is retaining the requirements as proposed for long-string casing
construction for Class VI wells. To further address comments on deep
injection wells, today's final rule includes requirements at Sec.
146.95 for owners or operators that seek a waiver of the injection
depth requirements. Owners or operators of wells operating under
injection depth waivers must comply with additional construction
requirements to ensure that wells used to inject above or between USDWs
are protective and will not endanger USDWs. See section III.D for a
detailed discussion of the waiver approach.
Cement and well materials requirements: EPA proposed that all
materials used in the construction of Class VI wells must be compatible
with fluids with which the materials may be expected to come into
contact, and that cement and cement additives must be compatible with
the CO2 stream and formation fluids and of sufficient
quality and quantity to maintain integrity over the design life of the
project. The Agency requested comment on cementing of the long-string
casing, including the use of degradation-resistant well construction
materials, such as acid-resistant cements and corrosion-resistant
casing for Class VI wells.
Commenters who disagreed with EPA's proposed requirements for well
materials and cement argued that the specific use of acid-resistant/
corrosion-resistant cement is excessive. They expressed concerns that
the proposed rule did not reflect actual field experience or recent
laboratory research and they encouraged the Agency to defer imposing
these additional requirements until further field experience and
research are conducted. These commenters suggested that the Agency
allow Director's discretion in determining the standards for casing and
cementing on a case-by-case basis.
Commenters who supported the use of acid-resistant/degradation-
resistant cement and materials asserted that their use is essential to
reduce the risk of leaks associated with compromised mechanical
integrity and to protect USDWs from endangerment, at a modest cost
relative to the long-term benefit of well integrity.
Some commenters supported the use of Class II well construction
standards for Class VI wells. These commenters indicated that the oil
and gas industry has several decades of CO2 injection
experience, which, they believe demonstrates that Class II construction
standards are sufficient to protect human health and the environment.
EPA recognizes that the oil and gas industry has experience injecting
CO2 and that many of the wells used for ER may be suitable
for GS. However, GS is sufficiently different from Class II ER
operations to warrant today's tailored construction requirements for
Class VI wells at Sec. 146.86. For example, the volume of
CO2 anticipated to be injected in Class VI wells is
significantly greater than for Class II wells. Additionally, formation
pressures are expected to be higher as a result of Class VI injection
when compared to formation pressures associated with Class II ER
projects. Today's final rule does provide for grandfathering of
construction for wells transitioning to GS provided the owner or
operator can demonstrate to the Director (during the re-permitting
process) that wells were constructed and cemented with materials
compatible with GS activities; see section II.H.
EPA agrees with commenters that cement additives and degradation
resistant materials are crucial to proper construction of Class VI
wells. Because of the numerous approaches developed for cement design
and due to continually evolving well materials and construction
technology (as evidenced by oil and gas industry experience
demonstrating the effectiveness of existing cementing materials and
procedures), EPA believes it would not be prudent or feasible to
specify design standards for cement or cementing procedures, such as
wellbore conditioning. Instead, the final rule specifies a performance
standard at Sec. 146.86(b)(1) that all casing and cementing or other
materials used in the construction of each well have sufficient
structural strength, be designed for the life of the GS project, be
compatible with the injected fluids, and prevent fluid movement into or
between USDWs.
Tubing and packer requirements: EPA proposed that all Class VI
wells be constructed with tubing and a packer that is set opposite a
cemented interval at a location approved by the Director, and sought
comment on this approach. Several commenters agreed with the proposed
approach for tubing and packer of Class VI wells, saying that tubing
and packer in Class VI wells facilitate continuous monitoring of
pressure in the annulus between the tubing and casing and effectively
provide two barriers from USDWs. Additionally, tubing can be replaced
relatively easily in the event that damage to the tubing is identified
or a tubing diameter change is necessary. EPA agrees with commenters
that the use of tubing and packer in accordance with specified
requirements at Sec. 146.86(c) offers the best multiple-barrier
protection of USDWs from endangerment and today's final rule retains
this requirement.
Horizontal wells: In the proposed rule, EPA solicited comment on
the merits of horizontal well drilling techniques for Class VI wells
and the applicability of proposed well construction requirements to
horizontal injection well design. Commenters strongly supported the use
of horizontal well drilling techniques for Class VI wells. Many
commenters cited the oil and gas industry's extensive technical
experience with horizontal injection well construction and the
practical experience gained at GS pilot projects including the In Salah
project in Algeria. Commenters also emphasized that horizontal well
drilling helps to reduce surface impact by reducing the number of
injection well heads required to achieve a given injection rate, which
limits the number of potential leakage pathways into USDWs. Commenters
stated that allowing the use of horizontal wells for GS would maximize
CO2 injection volumes into a particular reservoir and
increase the total effective GS CO2 storage capacity in the
U.S.
EPA agrees with commenters that horizontal well drilling techniques
represent a potential and promising method for increasing efficiency of
GS projects while simultaneously reducing impact and potential leakage
pathways into USDWs. EPA agrees that using existing experience with
horizontal well construction and use in conjunction with the Class VI
requirements may help improve efficiency in GS operations while
ensuring protection of USDWs from endangerment. Therefore, the Agency
will allow the use of horizontal wells for Class VI GS as long as the
wells are constructed and implemented to meet the requirements under
subpart H of part 146.
D. Class VI Injection Depth Waivers and Use of Aquifer Exemptions for
GS
Today's final rule includes requirements at Sec. 146.95 that allow
owners or operators to seek a waiver from the Class VI injection depth
requirements for GS to allow injection into non-USDW formations while
ensuring that USDWs above and below
[[Page 77252]]
the injection zone are protected from endangerment. The Agency
anticipates that any issuance of waivers will be limited to
circumstances where there are deep USDWs (74 FR 44802, August 31, 2009)
and/or where the lack of a waiver of injection depth requirements would
result in impractical or technically infeasible well construction, and
where USDW protection is demonstrated and maintained through the life
of the GS project. These requirements are designed to ensure that the
owner or operator and the Director consider, on a site-specific basis,
the implications, benefits, and challenges associated with GS, water
availability, and USDW protection. Today's final rule also establishes
limited circumstances under which aquifer exemption expansions may be
granted for owners or operators of Class II EOR/EGR wells transitioning
to Class VI injection wells for GS.
1. Proposed Rule
Injection depth requirements for GS: In the proposed rule, EPA
defined Class VI injection wells as ``wells used for GS (injection) of
CO2 beneath the lowermost formation containing a USDW.'' The
proposed injection depth requirements (i.e., that injection is below
the lowermost USDW) for Class VI wells are consistent with the siting
and operational requirements for deep, technically sophisticated wells
and are an important component of the UIC program. The basis for these
requirements is the principle that placing distance between the
injection formation and USDWs will decrease risks to USDWs. In deep-
well injection scenarios, the added depth and distance between the
injection zone and overlying formations serve both as a buffer allowing
for pressure dissipation and as a zone for monitoring that may detect
any excursions (of the injectate) out of the injection zone. Additional
depth and distance also allow CO2 trapping mechanisms,
including physical trapping, dissolution of CO2 in native
fluids and mineralization, to occur over time--thereby reducing risks
that CO2 may migrate from the injection zone and endanger
USDWs. Added depth also allows the potential for the presence of
additional confining layers (between the injection zone and overlying
formations/USDWs).
The Agency acknowledged that the proposed injection depth
requirements would preclude injection of CO2 into zones in
between and above USDWs and may restrict the use of GS in areas of the
country with deep USDWs, where well construction would be impractical
or technically infeasible. As proposed, the definition would also have
effectively precluded injection of CO2 into shallow
formations such as coal seams and basalts. The Agency requested comment
on alternative approaches that would allow injection between USDWs and/
or above the lowermost USDW and thus potentially allow for more areas
to be available for GS while continuing to prevent endangerment of
USDWs.
The Agency received comments in support of, and opposition to, the
proposed injection depth requirements for Class VI wells. Commenters
who supported the proposed requirements cited the importance of USDW
protection, the integrity and importance of the long-standing deep well
UIC requirements, and concerns about water availability and the future
use of deep USDWs. Commenters also indicated that in the early years of
GS deployment, injection depth limitations would be prudent.
Those opposed to the proposed requirements supported allowing
injection above and between USDWs. These commenters indicated that
injection depth flexibility for GS is important to ensure that no parts
of the country are excluded from GS activities and that CCS deployment
is not restricted. Other commenters encouraged injection depth
flexibility because, they asserted, some Class II, Class III, and Class
V operations already inject above the lowermost USDW without any
potential for threats to underlying (or overlying) USDWs.
Use of aquifer exemptions for GS: The UIC requirements at
Sec. Sec. 146.4 and 144.7 establish criteria for and afford the
Director discretion to issue aquifer exemptions which, when approved,
removes an aquifer from protection as a USDW, in accordance with the
requirements of Sec. 144.7(b)(1). Generally, aquifer exemptions are
granted 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 (see specific aquifer exemption
criteria at Sec. 146.4). There are also limited numbers of aquifer
exemptions for Class I industrial injection. Aquifer exemptions
associated with Class II and Class III operations are generally limited
in area (e.g., a quarter of a mile around the injection well-bore for
Class II wells). EPA attempts to limit aquifer exemptions for injection
operations to the circumstances where the necessary criteria at Sec.
146.4 are met and not, in general, for the purpose of creating
additional capacity for the subsurface emplacement of fluids.
The proposed rule acknowledged that there may be situations where
owners or operators may seek aquifer exemptions for GS and sought
comment on whether aquifer exemptions should be allowed for the purpose
of Class VI injection. EPA also requested comment on the conditions
under which aquifer exemptions for GS should be approved.
Some commenters encouraged the Agency to allow the use of aquifer
exemptions for Class VI injection and indicated that the existing
criteria at 40 CFR 146.4 and 40 CFR 144.7 are appropriate for GS.
However, a number of commenters requested that the Agency modify the
aquifer exemption criteria to provide regulatory certainty and ensure
that the criteria specifically apply to CO2 injection for
GS. Other commenters requested that the Agency modify the definition of
a USDW to reduce the need for aquifer exemptions (e.g., lowering the
upper TDS limit from 10,000 mg/l TDS). Additionally, commenters
acknowledged that there was a particular interest in aquifer exemptions
for Class II fields that may be used for GS in the future.
Other commenters suggested that the Agency limit or prohibit
aquifer exemptions for Class VI injection, citing the need to ensure
protection of current and future drinking water resources. Furthermore,
several commenters opposed to the use of aquifer exemptions suggested
modifications to the definition of a USDW to enhance protection for
formations in excess of 10,000 mg/l TDS.
Injection formations for GS: In the preamble to the proposed rule,
EPA discussed and sought comment on the range of target geologic
formations used or under investigation for GS of CO2 (e.g.,
deep saline formations, depleted oil and gas reservoirs, unmineable
coal seams, basalts, and other formations). The proposed rule also
sought comment on whether the final rule should prohibit injection into
any specific formation types that are located above the lowermost USDW.
Most commenters encouraged EPA not to automatically exclude any
potential injection formations for GS at this stage of deployment.
Commenters suggested, in particular, that there is a sufficient
technical basis and scientific evidence to allow GS in depleted oil and
gas reservoirs and in saline formations, noting that there is consensus
on how to inject into these formation types.
Some commenters, including water associations, cautioned the Agency
regarding injection into saline
[[Page 77253]]
formations, citing concerns about the potential future need for these
formations as drinking water sources. Other commenters suggested that
basalts, salt domes, shales, coal seams, limestone formations, and
fractured karst are not ready for commercial sequestration and
suggested that additional research is needed into GS in these formation
types.
More detailed information on the comments is available in the NODA
and Request for Comment and in the docket for this rulemaking.
2. Notice of Data Availability and Request for Comment
In response to comments received on the proposed injection depth
requirements, the Agency published a NODA and Request for Comment to
present additional information on an alternative for addressing
injection depth in limited circumstances where there are deep USDWs and
injection above and between USDWs would not endanger USDWs. Under the
approach, the proposed Class VI injection depth requirements would
remain unchanged but would allow an owner or operator seeking to inject
into non-USDWs above or between USDWs to apply for a waiver from the
injection depth requirements. The waiver process, presented in the NODA
and Request for Comment, would be informed by site-specific information
and would be reviewed by both the UIC and Public Water System
Supervision (PWSS) Directors to ensure appropriate siting of a GS
project as well as consideration of water resource availability and
demands.
The NODA and Request for Comment sought comment on the merits of
the injection depth waiver approach and whether the waiver process
should apply only to saline formations and oil/gas reservoirs or to all
formation types. Additionally, the Agency requested information on (1)
locations in the U.S. where injection depth is an issue; (2) data and
information on the safety of injecting through/above/between USDWs;
and, (3) strategies being considered by States, Tribes, and Regions to
address competing resource issues. The Agency requested this
information to enable a more comprehensive decision regarding the
impacts of the proposed injection depth requirements and the need for
waivers.
Comments on the waiver alternative presented in the NODA and
Request for Comment: The Agency received comments both in support of
and opposition to the injection depth waiver alternative discussed in
the NODA and Request for Comment.
Commenters supporting the waiver alternative presented in the NODA
and Request for Comment acknowledged that the waiver approach is
flexible, strikes the right balance between USDW protection and
maximizing GS capacity, and would ensure a thorough and scientifically
based, site-specific assessment of the appropriateness of a waiver
during the siting process. A number of commenters supportive of the
waiver cited hydrocarbon storage, other injection operations, and
production activities as evidence that GS into shallower geologic
environments can be performed safely and successfully while ensuring
USDW protection.
There was limited opposition to the waiver alternative presented in
the NODA and Request for Comment. Commenters who opposed the waiver
approach maintained that all injection of CO2 for GS should
be below the lowermost USDW and any new requirements should maximize
protection of USDWs. However, some commenters who opposed the waiver
process acknowledged the utility of the waiver, and urged the Agency to
consider additional requirements for any wells that operate under
injection depth waivers. The Agency did not receive any analytical or
quantitative data in response to publication of the NODA and Request
for Comment.
The Agency also received comments on the waiver application and
review process. Commenters questioned how the process would work and
how waivers would apply to existing Class I, II, or V wells that may be
re-permitted as Class VI wells in the future. Some commenters suggested
that the waiver request should be part of the permit application
process, while others felt that it should be a discrete submittal.
Other commenters expressed concern about the nexus between the waiver
process and aquifer exemptions. Some commenters who supported the
waiver concept suggested that adoption of an injection depth waiver
process should not be at the discretion of the individual UIC program
Directors and that EPA should require all States to include a waiver
process.
A number of commenters supporting the concept of the waiver of
injection depth requirements indicated that they did not support the
joint review of waiver information by both the UIC and PWSS Directors.
These commenters believed that the joint review process as discussed in
the NODA and Request for Comment was inefficient and duplicative, and
could introduce confusion and lack of clarity about the role of each
Director. However, a number of commenters did support the principle of
affording the PWSS Director a consultative role for increased
transparency and to ensure consideration of public water supply needs
in a potential GS project area when siting a Class VI well.
Noting the unique nature of the waiver process and the belief that
injection above USDWs may present additional questions relative to
movement of CO2 in the subsurface, many commenters supported
the Agency's assertion that additional requirements should apply to
waivered wells. These commenters suggested that additional regional,
hydrologic studies be required when an injection depth waiver is
considered. Other commenters encouraged EPA to enhance the site
characterization requirements when a waiver is granted to (1) ensure
the identification of appropriate upper and lower confining units, (2)
include requirements for more comprehensive, site-specific monitoring
(above and below the injection zone), and (3) ensure appropriate public
notification prior to issuance of a waiver. A number of commenters also
suggested that the Agency develop guidance to support the waiver
application process, waiver evaluation, and decision making.
Comments on the use of aquifer exemptions for GS: Comments
submitted in response to the NODA were similar to and built upon those
received on the proposal. Some commenters indicated that, in addition
to allowing injection above and between USDWs (through the waiver
process), aquifer exemptions should also be allowed for Class VI
injection. A number of these commenters requested that the Agency
modify (1) the aquifer exemption criteria to ensure that the criteria
specifically apply to CO2 injection for GS and (2) the USDW
definition to limit protection for formations currently afforded
protection under the SDWA (i.e., by reducing the 10,000 mg/l TDS
threshold). These commenters added that Class II EOR/EGR operations
injecting into exempted aquifers would need a mechanism to continue the
aquifer exemptions if the well were to be re-permitted as a GS
operation.
However, a number of commenters encouraged the Agency to limit or
prohibit aquifer exemptions for Class VI injection, citing the need to
ensure protection of current and future drinking water resources.
Furthermore, several of these commenters suggested modifications to the
definition of a USDW to enhance protection for formations in excess of
10,000 mg/l TDS.
[[Page 77254]]
Comments on injection formations for GS: Commenters submitted
comments similar to those received on the proposal. Some commenters
encouraged the Agency to limit GS injection to only deep saline
formations and depleted reservoirs. These commenters cited a lack of
information about the viability of basalts, salt domes, shales, and
coal seams for GS. Other commenters suggested that the Agency allow
injection into all formation types for GS. Commenters that supported
flexibility in injection formation types indicated that proper site-
characterization is critical, regardless of the injection formation
type. They indicated that a decision to allow injection for GS should
be made on a site-by-site basis and a prohibition based on formation
types is not appropriate.
3. Final Approach
In response to comments on the proposed injection depth
requirements, the use of aquifer exemptions for GS, the range of
potential injection formations for GS, the waiver process discussed in
the NODA and Request for Comment, and concerns about USDW protection
and national capacity for GS, today's rule finalizes requirements at
Sec. 146.95 that allow owners or operators to seek a waiver of the
Class VI injection depth requirements for injection into non-USDW
formations above and/or between USDWs. It establishes: (1) Requirements
specifying information that owners or operators must submit, and
Directors must consider, in consultation with PWSS Directors; (2)
procedures for public notice of a waiver application and for Director-
Regional Administrator communication; (3) the waiver issuance process;
and (4) additional requirements that apply to owners or operators of
Class VI wells granted a waiver of the injection depth requirements to
ensure USDW protection above and below the injection zone. Today's
final rule also establishes limited circumstances under which
expansions of aquifer exemptions may be granted for owners or operators
of Class II EOR/EGR wells transitioning to Class VI injection for GS.
Additionally, today's rule does not categorically preclude or prohibit
injection into any type of formation.
The Agency is finalizing these requirements to ensure USDW
protection while providing flexibility to UIC program Directors and
owners or operators who will undertake CO2 injection for GS.
The Agency believes this approach: (1) Responds to concerns about local
and regional geologic storage capacity limitations imposed by the
proposed injection depth requirements; (2) allows for a more site-
specific assessment of injection depth for GS projects; (3)
accommodates injection into different formation types; (4) allows for
injection of CO2 for GS into non-USDWs above and/or between
USDWs when appropriate and where it can be demonstrated that USDWs will
be protected from endangerment; and (5) responds to concerns about the
use of aquifer exemptions for GS. Finally, EPA's approach to addressing
injection depth variability through a waiver process responds to
concerns about future drinking water resource availability and the need
to ensure that high quality water remains available in sufficient
quantities to supply drinking water needs.
The final injection depth waiver requirements at Sec. 146.95 apply
to all non-USDWs including: (1) Formations that have salinities greater
than 10,000 mg/l TDS and (2) all eligible previously exempted aquifers
situated above and/or between USDWs. EPA anticipates that previously
exempted aquifers will, in many cases, not be appropriate receiving
formations for GS due to their location, size, lithologic properties,
and previous injection operations; and, therefore, the Agency expects
that few owners or operators will seek Class VI permits for GS
injection into previously exempted aquifers.
Injection depth waivers for GS: Today's final rule requires an
owner or operator seeking a Class VI waiver of the injection depth
requirements to submit additional information to the Director to inform
a comprehensive assessment of site-suitability for a Class VI well to
inject into a non-USDW above or between USDWs. The Agency believes that
it is appropriate and reasonable that the owner or operator and the
Director consider additional, specific information prior to waiver
issuance in addition to the required Class VI permit information and
the site characterization information collected (pursuant to
requirements at Sec. 146.82(a) for the site-specific characterization
of geologic, hydrogeologic, geochemical, and geomechanical properties
and Sec. 146.83 to determine the suitability of the proposed GS site).
In addition to submitting a Class VI permit application, the owner
or operator must also submit a supplemental report (the GS Class VI
injection depth waiver application report) referenced at Sec.
146.82(d) and outlined at Sec. 146.95(a) with additional, specific
information including: Information about the injection zone;
identification of confining units above and below the injection zone;
tailored AoR modeling above and below the injection zone; a
demonstration that well design is appropriate and protective of USDWs,
in lieu of specific well construction requirements at Sec. 146.86; a
description of how monitoring will be tailored for injection above/
between USDWs; and information about public water supplies in the AoR.
The purpose of the report is to ensure that the owner or operator
collects appropriate information and demonstrates to the Director that
the injection zone is suitable for GS and is confined by confining
units above and below the injection zone; that well construction,
operation, and monitoring are tailored for the site; and, that USDWs
are not and will not be endangered. This report, suggested by
commenters on the NODA and Request for Comment, ensures that waiver
information is discrete from the permit application as indicated at
Sec. 146.82(d) and must be made available to the UIC Director, PWSS
Directors, the Regional Administrator, and the public when the waiver
is publicly noticed with the draft, Class VI permit application.
EPA believes that, to be effective, a waiver of injection depth
requirements should be granted only after the UIC program Director, the
PWSS Director(s), and the public have evaluated information specific to
the site and anticipated injection activity. In addition, the decision
to waive injection depth requirements must be made using a clear and
transparent public notification process. The requirements at Sec.
146.95(b) establish considerations that the UIC Director must assess
when evaluating a waiver application in conjunction with the permit
application for a Class VI GS project. These are designed to ensure
that USDW protection, site-specific drinking water resource issues, and
the use and impact of GS technologies are considered and documented.
The requirements at Sec. 146.95(b)(2) also establish the manner in
which the UIC Director will consult with the PWSS Director(s) of
States, Territories, and Tribes having jurisdiction over lands within
the AoR of a well for which a waiver is sought to ensure that water
system concerns are considered when evaluating a waiver application.
The communication with the PWSS Director is consultative and does not
constitute a final Agency decision.
Under Sec. 146.95(c) and pursuant to requirements at Sec. 124.10,
the public notification process for a waiver of injection depth
requirements for a Class VI well must occur concurrently with the Class
VI permit notification in order to ensure that all necessary
information is disclosed to the public for notice and
[[Page 77255]]
comment and that the public understands that the site, if permitted,
would be operating under a waiver from the injection depth
requirements. In addition, the rule at Sec. 146.95(c) requires the
Director to provide the public with appropriate, site-specific and
waiver-specific information to inform public comment. If the permitting
authority receives comments on the injection depth waiver during the
public comment period for both the waiver and the permit application,
the Director must evaluate comments prior to approving the waiver and
issuing the Class VI permit. These requirements balance USDW protection
and disclosure of PWSS information with the GS permit application
process requirements.
Today's final regulations, at Sec. 146.95(d), require the Director
to provide the Regional Administrator with the information collected
during the waiver application and the public notice processes. Based on
this information and pursuant to requirements at Sec. 146.95(d), the
Regional Administrator will provide written concurrence or non-
concurrence regarding waiver issuance. The requirements at Sec.
146.95(d)(1) afford the Regional Administrator discretion to request
limited, additional information to support the waiver decision. The
Regional Administrator also has the discretion to require re-initiation
of the public notice and comment period if necessary. Today's rule at
Sec. 146.95(d)(2) clarifies that Directors of State-approved programs
shall not issue waivers without the written concurrence of the Regional
Administrator. EPA believes Agency input is necessary in making
injection depth waiver decisions and agrees with commenters who
expressed interest in ensuring that multi-State boundary and water
resource issues are addressed. EPA also believes that Agency
involvement in the waiver decision process will contribute to national
consistency in waiver issuance.
The requirements at Sec. 146.95(e) identify the information that
EPA will maintain on its Web site to provide transparency and inform
the public regarding GS injection depth waiver issuance throughout the
U.S.
Today's rule finalizes additional requirements at Sec. 146.95(f)
to address comments and provide clarity to owners or operators who
receive and operate with a waiver of the Class VI injection depth
requirements. These requirements are a supplement to all other
applicable requirements finalized today (see Sec. 146.95(f)(1)). The
additional requirements are designed to complement existing
requirements by:
Building upon the site characterization and AoR
delineation conducted during the waiver application process (at Sec.
146.95(a)),
Supplementing specific requirements that are not
applicable due to the fact that certain Class VI requirements (e.g., at
Sec. 146.86) reference the ``lowermost USDW,''
Expanding the monitoring requirements during operation and
PISC to address protection of USDWs underlying and overlying the
injection zone, and,
Ensuring protection of USDWs above and below an injection
zone when a Class VI well is issued a waiver of the injection depth
requirements.
The Agency believes that collection and assessment of site- and
project-specific information is integral to the waiver process. The
Agency is developing guidance to support owners or operators in
assessing a GS project site and applying for a waiver of the Class VI
injection depth requirements and to assist Directors in evaluating
waiver applications.
Today's final approach for injection depth waivers represents
minimum Federal requirements. Adoption of the waiver process will
remain at the discretion of individual UIC programs, since States may
choose to develop requirements that are more stringent than the minimum
Federal requirements provided in today's rule. Furthermore, States,
Territories and Tribes may be prohibited by state law from allowing
such a waiver process. Therefore, States, Territories, and Tribes
seeking primacy for Class VI wells are not required to provide for
injection depth waivers in their UIC regulations and may choose not to
make this process available to owners or operators of Class VI wells
under their jurisdiction. Although some commenters asked EPA to require
that waivers be applied nationally, the Agency believes that the
decision about whether a waiver program is appropriate in a specific
State, Tribe, or Territory should be made by each program. This
approach allows flexibility for individual program Directors to
determine the appropriateness of allowing for waivers based on regional
or State-specific conditions, such as the predominant geologic settings
anticipated to be used for GS or other land uses in the State while
ensuring maximum protection of USDWs from endangerment. UIC program
Directors may adopt GS requirements that do not allow injection above
or between USDWs if they determine this to be appropriate or if State
law prohibits the injection depth waiver process.
No waivers can be issued prior to the establishment of a Class VI
UIC program in a State, pursuant to the requirements at Sec.
145.21(see section II.E.2). This is designed to ensure that States
determine whether a waiver process will be allowed as a part of their
GS program.
Use of aquifer exemptions for GS: Today's rule allows for the
expansion to the areal extent of existing aquifer exemptions for Class
II EOR/EGR wells transitioning to Class VI injection for GS pursuant to
requirements at Sec. Sec. 146.4 and 144.7(d). Today's final rule also
precludes the issuance of new aquifer exemptions for Class VI wells.
Aquifer exemptions will only be granted for projects that are
transitioning from Class II EOR/EGR wells to Class VI, and are referred
to as aquifer exemption expansions below. However, Class VI owners or
operators granted expansions of existing Class II EOR/EGR aquifer
exemptions for GS projects must meet all of the tailored requirements
for Class VI wells in today's rule, except where there are specific
provisions for grandfathering of constructed wells pursuant to
requirements at Sec. 146.81(c).
If an owner or operator applies for a Class VI permit to inject
CO2 into a previously exempted aquifer (non-USDW) that is
located above and/or between USDWs, the permit applicant must also
apply for a waiver of the injection depth requirements pursuant to
Sec. 146.95 to ensure that if a waiver is granted, USDWs above and
below the injection zone are protected from endangerment.
While the Agency developed the waiver process to address comments
and concerns about: (1) Current and future drinking water resources and
(2) the use of climate mitigation technology at appropriate sites, the
Agency acknowledges that there are limited circumstances where aquifer
exemptions for GS may be warranted. The aquifer exemption requirements
in today's final rule afford owners or operators an opportunity to
assess and select a suitable GS site while also preserving USDWs (i.e.,
formations/aquifers afforded SDWA protection). EPA agrees with
commenters who expressed concerns about USDW preservation and
protection and believes that, in most cases, the injection depth waiver
is a more appropriate option than aquifer exemptions for Class VI
injection, and believes that aquifer exemption expansions for GS should
be granted in limited circumstances.
The aquifer exemption requirements and the injection depth waiver
requirements serve different purposes. An aquifer exemption removes the
[[Page 77256]]
injection formation from SDWA protection as a USDW and allows injection
(i.e., permitted or rule authorized) into an exempted formation, while
an injection depth waiver allows (Class VI) CO2 injection
for GS above or between USDWs and ensures protection of USDWs above and
below the injection zone (which may be an exempted aquifer).
The Agency recognizes that a limited number of Class II EOR/EGR
well owners or operators currently inject into exempted aquifers or
exempted portions of aquifers and these owners or operators may
transition to Class VI GS in the future (see section II.H). In response
to commenters who believed that there is a need for aquifer exemptions
in specific circumstances and in an effort to maintain USDW protection
while providing flexibility to transitioning projects, today's rule
allows owners or operators of Class II EOR/EGR operations injecting
into exempted aquifers (or exempted portions of aquifers) to reapply
for an aquifer exemption expansion for the re-permitted Class VI
injection.
For all Class II EOR/EGR aquifer exemption expansions for Class VI
injection, public notice and opportunity for a public hearing is
required under Sec. 144.7(b)(3). In addition, today's rule requires
that all such aquifer exemption expansion requests be treated as
substantial program revisions under Sec. 145.32 and will require
revision of part 147. Furthermore, if EPA directly implements the UIC
program in a State, an aquifer exemption expansion requires a revision
to the UIC program of the applicable State under part 147.
The Agency acknowledges that the expansion of an existing aquifer
exemption for a GS project will remove additional USDWs (or portions of
USDWs) from SDWA protection, and that owners or operators of other
classes of injection wells could apply for a permit to inject into
these exempted aquifers. However, EPA clarifies that aquifer exemption
expansions granted under today's rule will only be granted for the
purpose of GS (and the injection will be subject to today's tailored
requirements for Class VI wells). Any other uses of an exempted aquifer
(e.g., for Class I through V injection) require a separate permit, are
subject to existing UIC requirements, and must be approved by the UIC
Director. The Agency anticipates that a UIC Director will (and
encourages the UIC Director to) consider the following types of risks
when evaluating additional injection activities into the AoR of a GS
project: The number of artificial penetrations in the AoR, potential
adverse geochemical interactions between previously injected
CO2 and other injection fluids, and an increase in reservoir
pressure as a result of multiple injectors and subsurface plume
interaction. EPA believes that these factors would reduce the
likelihood that exempted aquifers associated with GS injection will be
used for other activities.
Additionally, the Agency recognizes that an owner or operator
could, in theory, request multiple expansions to the areal extent of a
previously exempted aquifer used for Class II EOR/EGR injection.
However, due to the nature of Class VI operations including the permit
application process, the AoR evaluation, and the development of site-
specific plans, the Agency anticipates that an owner or operator will
not be able to continually expand an aquifer exemption for a Class VI
operation. Instead, the applicant should identify, up front, the
predicted extent of the injected CO2 plume and any mobilized
fluids that may result in degradation of water quality over the
lifetime of the GS project to develop an appropriate aquifer exemption
request. Identification of the areal extent of the expanded aquifer
exemption must be informed by computational modeling of the site
developed for delineation of the AoR, and be of sufficient size to
cover any possible changes to the computational model that may arise
during future reevaluation of the AoR over the life of the project.
Pursuant to requirements at Sec. 144.7(d)(2), the Director will
comprehensively evaluate the permit application information in concert
with the areal extent of the aquifer exemption expansion request. The
purpose of these requirements is to ensure USDW protection while
developing an exemption expansion that is commensurate with the Class
VI injection project, for the life of the project, to reduce the
potential need for additional expansions of a specific aquifer
exemption for Class VI injection in the future.
Furthermore, in the event that a Class VI owner or operator obtains
evidence based on monitoring data collected at the GS site, as required
by Sec. 146.90(g), that non-exempted, USDW portions of the aquifer
(i.e., on the periphery of the exempted aquifer) may be endangered by
the injection activity, the owner or operator must immediately cease
injection and implement the Emergency and Remedial Response Plan
approved by the Director pursuant to requirements at Sec. 146.94.
Additionally, the Agency clarifies that such USDW endangerment is a
violation of the UIC requirements and associated Class VI permit
conditions (e.g., Sec. 144.12; Sec. 146.86, etc.).
Today's final approach is designed to ensure that the differences
between traditional Class II EOR/EGR operations and Class VI operations
are considered during the aquifer exemption application process and the
Class VI permitting process. These differences include the anticipated
large CO2 injection volumes associated with GS, the buoyant
and mobile nature of the injectate, and its corrosivity in the presence
of water. The Agency believes that this process will encourage owners
or operators and Directors to consider the use of alternative
formations for GS, including non-USDW formations through the waiver
process, prior to applying for or approving aquifer exemption
expansions for Class II EOR/EGR wells transitioning to Class VI GS
operations. See the discussion on injection depth waivers for GS for
information on scenarios that will require the use of both aquifer
exemptions and waivers in this section.
Injection formations for GS: In response to comments received on
the proposal and the NODA and Request for Comment, today's rule does
not categorically preclude or prohibit injection into any type of
formation. Instead, the requirements are designed to ensure protection
of USDWs from endangerment through proper siting, well construction,
operation, monitoring, and PISC at all sites selected for GS.
EPA recognizes that some types of formations, such as coal seams
and basalts, are typically shallow and above the lowermost USDW. EPA
expects that injection wells conducting GS in these shallow formations
will be permitted as Class VI wells and such wells will be issued
waivers, provided that their owners or operators can meet all of the
requirements for an injection depth waiver at Sec. 146.95 and
demonstrate that such injection can be performed in a manner that
protects USDWs. EPA adds that wells used to inject into these formation
types or other formation types (e.g., salt domes and shales) for
experimental purposes would be permitted as Class V experimental
technology wells. See section II.H for additional information on the
use of the Class V experimental technology well classification
following finalization of today's rulemaking.
To facilitate experimental injection for GS and to increase
understanding of injection into basalts, shales, and other formation
types, EPA is preparing additional guidance for owners or operators and
Directors regarding the use of Class V experimental technology
[[Page 77257]]
wells for GS following promulgation of today's rule.
Adaptive approach: In the early stages of GS deployment, EPA will
collect and review project data on GS projects, including information
on any Class VI wells granted a waiver of the injection depth
requirements and any aquifer exemption expansions issued for Class II
EOR/EGR wells transitioning to Class VI GS. Given the unique nature of
the waiver of injection depth requirements, the Agency will further
assess if the requirements provided in Sec. 146.95 are appropriately
designed to evaluate waiver applications, issue waivers, and ensure
protection of USDWs. The adaptive approach will also afford the Agency
an opportunity to assess the manner in which waivers and expansions of
existing Class II EOR/EGR aquifer exemptions for GS are issued across
the U.S. and evaluate the applicability of injection into all formation
types.
E. Injection Well Operation
Today's final rule contains tailored requirements at Sec. 146.88
for the operation of Class VI wells, including injection pressure
limitations, use of down-hole shut-off systems, and annulus pressure
requirements to ensure that injection of CO2 does not
endanger USDWs.
The requirements for operation of Class VI injection wells are
based on the existing requirements for Class I wells, with enhancements
to account for the unique conditions that will occur during GS
including buoyancy, corrosivity, and higher sustained pressures over a
longer period of operation.
Injection pressure limitations: EPA proposed that owners or
operators limit injection pressure such that pressure in the injection
zone does not exceed 90 percent of the fracture pressure of the
injection zone, and that injection may not initiate new fractures or
propagate existing fractures. Most commenters opposed an arbitrary
pressure limit, and advocated setting pressure limitations on a site-
specific basis. Today's final rule retains the requirement that
pressure in the injection zone must not exceed 90 percent of the
fracture pressure of the injection zone (Sec. 146.88(a)). The
calculated fracture pressure--and therefore, the injection pressure
limit--are based on site-specific geologic and geomechanical data
collected during the site characterization process as advocated by
commenters.
Annulus pressure: EPA proposed that owners or operators fill the
annulus with an approved non-corrosive fluid and maintain pressure on
the annulus that exceeds the operating injection pressure. Many
commenters disagreed with the requirement to maintain an annulus
pressure greater than the injection pressure because they indicated
that this could increase the potential for damage to the well.
EPA acknowledges that, in some circumstances, maintaining an
annulus pressure greater than the injection pressure could result in a
greater chance for damage to the well or the formation. As a result,
the final rule provides the Director discretion to adjust this
requirement if maintaining an annulus pressure higher than the
injection pressure may cause damage to the well or the formation. EPA
changed the requirements in Sec. 146.88(c) to: ``The owner or operator
must maintain on the annulus a pressure that exceeds the operating
injection pressure, unless the Director determines that such
requirement might harm the integrity of the well or endanger USDWs.''
Automatic down-hole shut-off devices: EPA proposed that owners or
operators install and use alarms and automatic down-hole shut-off
systems, in addition to the use of surface shut-off devices, to alert
the owner or operator and shut-in the well in the event of a loss of
mechanical integrity. Automatic down-hole shut-off devices are valves
located in the well tubing (at a depth established based on the
location of USDWs) that are set to close if triggered by changes in
flow rate or other monitored parameters. Automatic surface shut-off
valves are commonly used in the oil and gas industry to prevent further
well complications in the case of a triggered event such as inadvertent
well backflow during a workover. The Agency sought comment on the
merits of requiring such devices.
Commenters, including representatives of water associations,
supported the requirement to construct Class VI wells with automatic
down-hole shut-off devices. These commenters suggested that automatic
down-hole shut-off devices provide an additional barrier against upward
migration of CO2 and serve as an additional level of
protection when used in concert with surface shut-off devices.
Many industry commenters disagreed with the requirement to
construct Class VI wells with automatic down-hole shut-off devices.
These commenters indicated that down-hole shut-off devices are
redundant of surface devices and unnecessary and would not provide
additional protection to USDWs. Commenters suggested that these devices
are more appropriate for offshore wells and that the likelihood of
damage to surface wellheads is small. Other commenters stated that
installation of automatic down-hole shut-off devices in new and pre-
existing deep injection wells is complex and servicing of the devices
necessitates removal of the tubing. Commenters also indicated that the
use of such devices can complicate routine testing and well workovers,
and that failure of such devices could damage the well. Several
commenters suggested alternatives to automatic down-hole shut-off
devices including: Use of wireline retrievable plugs with landing
nipples; and use of well materials designed to withstand the proposed
injection pressures.
EPA evaluated the range of comments on this topic and maintains
that down-hole shut-off devices are an important barrier against
endangerment of USDWs from the escape of CO2. While
stakeholders commented that automatic down-hole shut-off devices are
primarily used in offshore oil and gas production applications, they
are currently used in other situations where loss of well integrity
could result in damage to the well or harm to humans (e.g., near high-
density population areas, or in onshore acid gas injection; IEA, 2003).
While commenters indicated that down-hole monitoring is more difficult,
or impractical with an automatic down-hole shut-off device in place,
EPA has identified examples of documented logging techniques, including
ultrasonic and temperature logs, that can be performed with an
automatic down-hole device emplaced (Julian et al., 2007; Somaschini et
al., 2009). They are also used in high pressure, high temperature
onshore wells and in permafrost areas.
EPA recognizes that, in limited circumstances, the sudden closing
of an automatic shut-off valve could cause damage to a well, and that
some of these devices may make well maintenance and operation more
challenging. Additionally, EPA recognizes that well complications may
increase as the frequency of routine or unexpected down-hole device
maintenance workovers increases. However, the buoyant nature of
CO2 and the elevated injection pressures associated with GS
increase the likelihood of an uncontrolled flow of CO2 out
of the well. If CO2 does begin to flow back up an injection
well, it will rapidly cool and expand as it moves toward the surface
and can result in a stream of solid CO2 which can cause
damage to the wellhead and other well instrumentation; such damage has
been documented in CO2 ER wells (Skinner, 2003; Duncan et
al., 2009). Automatic
[[Page 77258]]
shut-off devices can help prevent such occurrences.
After evaluating the risks and benefits of down-hole shut-off
systems and considering additional research, EPA will not require
automatic down-hole shut-off devices for onshore Class VI wells.
Instead, the final rule, at Sec. 146.88(e)(2), requires that owners or
operators of onshore Class VI wells install automatic surface shut-off
devices, and affords Director's discretion to mandate automatic down-
hole shut-off devices in onshore situations that may warrant their use.
EPA believes that requiring automatic surface shut-off devices instead
of down-hole devices provides more flexibility to owners or operators
when performing required mechanical integrity tests. Additionally, this
requirement addresses concerns about risks associated with routine well
workovers that may be complicated by the presence of down-hole devices
while still maintaining USDW protection.
Today's rule, at Sec. 146.88(e)(3), requires the installation of
down-hole shut-off devices for Class VI wells located in the offshore
submerged lands within the jurisdiction of a State UIC program. The
Agency believes that the unique construction and operational conditions
for offshore Class VI wells, including isolation from shorelines and
the need to construct wells through the water column and the
subsurface, may delay response time in the event of well difficulties.
These conditions merit requiring automatic down-hole shut-off devices
for offshore wells in the submerged lands of a State.
In the event of onshore or offshore well complications, an
automatic surface or down-hole shut-off device will immediately shut-in
the well to cease injection (limiting CO2 volume associated
with the event), isolate the injectate, and minimizes the risk of
subsurface fluid movement and associated problems that may endanger
USDWs. EPA believes that requiring the installation of automatic
surface shut-off devices for onshore wells (and affording Director's
discretion to require down-hole devices where necessary) and automatic
down-hole shut-off devices for offshore wells in submerged lands within
the jurisdiction of a State ensures that proper precautions are taken
to prevent subsurface fluid movement and ensure protection of USDWs,
human health, and the environment.
Well stimulation: In the proposed rule, EPA sought comment on
whether well stimulation or fracturing to enhance formation injectivity
is appropriate and should be allowed for Class VI wells. EPA also
requested submittal of information from commenters to better qualify
the use of hydraulic fracturing for well stimulation in specific
geologic settings and various lithologies. Well owners or operators
often use stimulation techniques, including intentionally creating new
or propagating existing fractures in the injection zone on wells that
have experienced decreased oil and gas production. Additionally,
increasing the number and size of fractures surrounding the injection
zone can enhance or increase the injectivity of the formation. However,
if fractures extend to the confining layer, USDWs can be endangered.
Some commenters stated that while stimulation using a range of
techniques including hydraulic fracturing is not appropriate in all
geologic settings it should be allowed for Class VI wells. Commenters
supported the requirement that hydraulic fracturing only be allowed
during well stimulation, noting that ER operations have successfully
employed hydraulic fracturing to increase well injectivity without
damaging the confining layer. These commenters thought that enhancing
injectivity through stimulation would allow injection to occur with
fewer injection wells and therefore fewer penetrations of the confining
layer.
Many commenters indicated that the Director should be able to
determine, based on site-specific information, whether stimulation
techniques would pose a risk to the confining layer. Some commenters
proposed considerations for determining whether stimulation, including
hydraulic fracturing, is appropriate in a given situation and
acknowledged that tools exist for owners or operators and Directors to
manage the safe use of well stimulation practices. These tools include
use of monitoring programs or computer simulations in conjunction with
stimulation activities to determine if stimulation is negatively
impacting confining layers. Others suggested that open-hole injection
zones and multiple injection points can also aid in increasing well
injectivity.
A water association commented that activities such as hydraulic
fracturing should not be allowed under any circumstances in order to
prevent fracturing of the confining layer and the opening of pathways
for fluid migration into a USDW.
EPA agrees with commenters that well stimulation may be appropriate
in situations where it is determined that it will increase well
injectivity and provide better performance for some projects. However,
EPA believes that protection of USDWs from endangerment is critical and
the primary purpose of UIC regulations pursuant to SDWA. In order to
allow appropriate well stimulation while protecting confining layers
and USDWs, EPA intends to allow stimulation only at the discretion of
the Director. The Director is in the best position to determine if well
stimulation techniques, including but not limited to hydraulic
fracturing, are appropriate in a given situation. EPA has added a
requirement at Sec. 146.91(d)(2) that the owner or operator must
notify the Director before any stimulation activities are undertaken.
Such notice will provide the Director an additional opportunity to
review stimulation plans, assess the description of stimulation fluids
to be used, determine that stimulation will not interfere with
containment, assess plan appropriateness, and potentially witness the
stimulation activity. Although the plan will already have been approved
by the Director as part of the permit application process and
incorporated into the permit, this notification requirement gives the
Director an opportunity to reassess the proposed stimulation activities
in light of any new information. In order to preserve the integrity of
the confining layer, EPA is retaining the prohibition against
fracturing the confining layer at any time and adds that fracturing
should not be allowed except during well stimulation. EPA clarifies
that under no circumstances may stimulation endanger USDWs.
Tracers: In the proposed rule, EPA sought comment on the use of
tracers in GS operations. Tracers are inert compounds added to or
naturally occurring in the injection fluid, which can be easily
detected through monitoring wells or through surface monitoring
techniques. Detection of the tracer would indicate a leak of the
injection fluid from the injection zone. Many types of tracers are
available, including perfluorocarbons, SF6, noble gases, and
stable isotopes such 18O and 14C.
Some commenters supported the use of tracers in Class VI injection
wells, maintaining that tracers are a useful method for detecting
CO2 leaks. Many commenters suggested that tracers should not
be required, but should be allowed at the discretion of the Director.
Other commenters thought that owners or operators should be allowed to
decide whether to use tracers.
Most commenters asserted that tracers were unnecessary and that
better methods for tracking CO2 movement were available.
These commenters cited
[[Page 77259]]
a variety of reasons, including that tracers were expensive,
burdensome, and untested; that detection of a tracer at the surface
would do nothing to protect USDWs from endangerment; and that some
tracers may have health risks or can contribute to climate change. EPA
received comments on specific tracers, such as perfluorocarbons (which
have been proven in other applications), radioactive tracers (which
have been used successfully in the oil and gas industry, but only with
a limited radius), and the use of CO2 itself (which can act
as a tracer).
EPA agrees that tracers can be a useful tool in some circumstances,
but recognizes that some factors (e.g., the potential to contribute
GHGs to the atmosphere, cost, and difficulties associated with
monitoring for tracers) may make other methods of tracking
CO2 movement more practical. Therefore, today's rule does
not require use of tracers for Class VI wells. However, EPA does
believe that tracers may be valuable in some cases, and will retain
Director's discretion to require the use of tracers and to determine
the type of tracer to be used if the Director determines that their use
will increase USDW protection from endangerment.
F. Testing and Monitoring
Today's final rule at Sec. 146.90 requires owners or operators of
Class VI wells to develop and implement a comprehensive testing and
monitoring plan for their projects that includes injectate monitoring,
corrosion monitoring of the well's tubular, mechanical, and cement
components, pressure fall-off testing, ground water quality monitoring,
CO2 plume and pressure front tracking, and, at the
Director's discretion, surface air and soil gas monitoring (SDWA
section 1421 et al.). The rule also requires MIT to verify proper well
construction, operation, and maintenance.
Monitoring associated with injection projects is an important
component of the UIC program and is required to ensure that USDWs are
not endangered. Monitoring data can be used to verify that the
injectate is safely confined in the target formation, minimize costs,
maintain the efficiency of the storage operation, confirm that
injection zone pressure changes follow predictions, and serve as inputs
for AoR modeling. Monitoring results will provide information about
site performance when compared against baseline information (collected
during the site characterization phase) or when compared to previous
monitoring results. In conjunction with careful site selection and AoR
delineation, monitoring is critical to the successful operation, PISC,
and site closure of a GS project.
Today's monitoring requirements are based on existing UIC
regulations, tailored to address the needs and challenges posed by GS
projects. For example, supercritical CO2 is different from
many Class I injectates in physical properties and chemical
composition. Also, many GS projects are anticipated to be ``large-
scale,'' with large volumes of CO2 injected over long
project life-spans. In the proposed rule, EPA sought comment on the
testing and monitoring plan, MIT, the use of pressure fall-off testing,
the types and amounts of ground water quality monitoring, pressure
front tracking, geophysical methods, and surface air and soil gas
monitoring.
The testing and monitoring requirements for Class VI wells at Sec.
146.90 incorporate elements of pre-existing UIC requirements for
monitoring and testing, tailored and augmented as appropriate for GS
projects. EPA recognizes that much will be learned about monitoring and
testing technologies and their application in various geologic settings
in the early phases of GS deployment. Therefore, the Agency will
evaluate monitoring data from early GS projects as part of the Agency's
adaptive rulemaking approach (See section II.F). The Agency is
developing guidance to support testing and monitoring at GS sites.
1. Testing and Monitoring Plan
EPA proposed that owners or operators of Class VI wells submit
monitoring plans with their permit applications. These plans would be
tailored to the GS project and be implemented upon Director approval,
and, at a minimum, include procedures and frequencies for analysis of
the chemical and physical characteristics of the CO2 stream;
MIT (internal and external); corrosion monitoring; 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, surface air and soil gas monitoring for
CO2 fluctuations, and any additional tests necessary to
ensure USDW protection from endangerment.
EPA sought comment on the testing and monitoring plan. Commenters
recommended that the plan be reevaluated concurrently with AoR
reevaluations. Commenters agreed that the plan should be site-specific
and flexible to allow the use of varied monitoring and testing
technologies. The Agency acknowledges the importance of flexibility and
today's rule maintains a testing and monitoring plan requirement that
will allow for site specificity and selection of the most appropriate
monitoring technologies. The Agency also acknowledges the importance of
agreement between site-characterization data, AoR information, and
monitoring and testing information.
The final rule retains the requirement to develop and implement a
testing and monitoring plan and requires that the approved plan be
incorporated into the Class VI permit. Owners or operators must also
periodically review the testing and monitoring plan to incorporate
operational and monitoring data and the most recent AoR reevaluation
(Sec. 146.90(j)). This review must take place within one year of an
AoR reevaluation, following significant changes to the facility, or
when required by the Director. The iterative process by which this and
other required plans are reviewed throughout the life of a project will
promote an ongoing dialogue between the owner or operator and the
Director. Tying the plan reviews to the AoR reevaluation frequency is
appropriate to ensure that reviews of the plans are conducted on a
defined schedule to address situations where there is a change in the
AoR or other circumstances change, while adding little burden if the
AoR reevaluation confirms that the plan is appropriate as written. The
Agency is developing guidance that describes the contents of the
project plans required in the GS rule, including the testing and
monitoring plan.
2. CO2 Stream Analysis
Injectate analysis provides information on the chemical composition
and physical characteristics of the injectate. Analysis of the
CO2 stream for GS projects will provide information about
any impurities that may be present and whether such impurities might
alter the corrosivity of the injectate down-hole. Such information is
necessary to inform well construction and the project-specific testing
and monitoring plan, and enable the owner or operator to optimize well
operating parameters while ensuring compliance with the Class VI
permit. The proposed rule required that analysis of the CO2
stream be conducted prior to commencing injection and throughout
injection operations at an appropriate frequency based on the
CO2 source and the likelihood of variability in the
injectate composition. Commenters supported the need for analysis of
the CO2 stream. The final rule retains the requirement that
owners or operators need to characterize their CO2 stream as
part of
[[Page 77260]]
their UIC permit application (Sec. 146.82(a)(7)), and throughout the
operational life of the injection facility (Sec. 146.90(a)). The
details of the sampling process and frequency must be described in the
Director-approved, site/project-specific testing and monitoring plan.
Resource Conservation and Recovery Act (RCRA) Applicability to
CO2 Streams: EPA received public comment asserting that the
proposed UIC Class VI requirements were unclear as to whether the
CO2 stream would be a RCRA hazardous waste, and left
uncertain the type of permit needed. Many commenters stated that a
CO2 stream should not be treated as a RCRA hazardous waste
on the grounds that it is neither a listed hazardous waste nor does it
exhibit a hazardous characteristic. Other commenters asserted that
CO2 in the presence of water could exhibit the RCRA
corrosivity characteristic. Additionally, commenters indicated that
analytic procedures used under RCRA (in particular, the toxicity
characteristic leaching procedure (TCLP)) cannot be applied to
supercritical CO2 streams and that the Class VI regulations
would better ensure the proper management of a CO2
injectate. EPA did not receive any new data on CO2 stream
characterization in the public comments.
In general, subtitle C of RCRA establishes a ``cradle to grave''
regulatory scheme over certain ``solid wastes'' which are also
``hazardous wastes.'' RCRA defines solid waste as, among other things,
discarded material, including solid, liquid, semisolid, or contained
gaseous material. EPA has further defined the term solid waste for
purposes of its hazardous waste regulations. To be considered a
hazardous waste, a material must first be classified as a solid waste
under the regulations (40 CFR 261.2). Under EPA's regulations at 40 CFR
262.11, generators of solid waste are required to determine whether
their wastes are hazardous wastes. A solid waste is a hazardous waste
if it exhibits any of four characteristics of a hazardous waste (i.e.,
ignitability, corrosivity, reactivity, or toxicity) under 40 CFR
261.20-.24, or is a listed waste under 40 CFR 261.30-.33 (these include
various used chemical products, by-products from specific industries,
or unused commercial products).
A CO2 stream is not itself a listed RCRA hazardous
waste. EPA has reviewed estimates of CO2 injectate quality,
which were based upon information such as the quality of flue gas from
the burning of fossil fuels, existing flue gas emission controls (e.g.,
electrostatic precipitators and scrubbers), and data from applied
CO2 capture technology. These estimates indicate that
captured CO2 could contain some impurities. These estimates
also indicate that the types of impurities and their concentrations
would likely vary by facility, coal composition, plant operating
conditions, and pollutant removal and carbon capture technologies.
Under this final rule, owners or operators will need to determine
whether the CO2 stream is hazardous under EPA's RCRA
regulations, and if so, any injection of the CO2 stream may
only occur in a Class I hazardous waste injection well. Conversely,
Class VI wells cannot be used for the co-injection of RCRA hazardous
wastes (i.e., hazardous wastes that are injected along with the
CO2 stream).
EPA supports the use of CO2 capture technologies that
minimize impurities in the CO2 stream. As a result of the
public comments received on the proposed Class VI rule related to
various RCRA applicability issues, EPA initiated a rulemaking separate
from today's final UIC Class VI rule. The RCRA proposed rule will
examine the issue of RCRA applicability to CO2 streams being
geologically sequestered, including the possible option of a
conditional exemption from the RCRA requirements for CO2 GS
in Class VI wells (see RIN 2050-AG60, EPA Semiannual Regulatory Agenda,
Spring 2010, EPA-230-Z-10-001). EPA will consider comments received on
the Class VI rule during the development of the RCRA proposal. The
Agency clarifies that commenters who wish to submit comments on the
RCRA proposal must do so during the comment period for that rule.
Today's rule does not itself change applicable RCRA regulations.
Comprehensive Environmental Response, Compensation, and Liability
Act (CERCLA) Applicability to CO2 Streams: EPA received a
range of comments regarding CERCLA liability and GS. Some commenters
suggested that the Agency allow for a GS exemption under CERCLA, while
others requested that the rule specify that injectate intrusion into a
USDW is not considered a CERCLA release and that the SDWA provides
enough civil and criminal enforcement authority to address any
environmental contamination that might result from GS. Other commenters
supported maximizing protection under CERCLA by writing Class VI GS
permits as broadly as possible so that ``unauthorized releases'' are
avoided.
CERCLA, more commonly known as Superfund, is the law that provides
broad Federal authority to clean up releases or threatened releases of
hazardous substances that may endanger human health or the environment.
CERCLA references four other environmental laws to designate more than
800 substances as hazardous and to identify many more as potentially
hazardous due to their characteristics pursuant to RCRA. CERCLA
authorizes EPA to clean up sites contaminated with hazardous substances
and seek compensation from responsible parties or compel responsible
parties to perform cleanups themselves.
CO2 itself is not listed as a hazardous substance under
CERCLA. However, the CO2 stream may contain a listed
hazardous substance (such as mercury) or may mobilize substances in the
subsurface that could react with ground water to produce listed
hazardous substances (such as sulfuric acid). Whether such substances
may result in CERCLA liability from a GS facility depends entirely on
the composition of the specific CO2 stream and the
environmental media in which it is stored (e.g., soil or ground water).
CERCLA exempts from liability under CERCLA section 107, 42 U.S.C. 9607,
certain ``Federally permitted releases'' (FPR) as defined in CERCLA, 42
U.S.C. 9601(10), which would include the permitted injectate stream as
long as it is injected and behaves in accordance with the permit
requirements. Class VI permits will need to be carefully structured to
ensure that they prevent potential releases from the well, which are
outside the scope of the Class VI permit and thus not considered
federally permitted releases.
The UIC program Director has authority under the SDWA to address
potential compliance issues (e.g., potential releases that may endanger
USDWs) resulting from injection violations in the unlikely event that
an emergency or remedial response (at Sec. 146.94) is necessary.
Although EPA anticipates that the need for emergency or remedial
actions at GS sites will be rare, today's rule requires that emergency
and remedial response plans be developed and updated to address such
events (in accordance with the remedial response requirements at Sec.
146.94) and that owners or operators demonstrate that financial
resources are set aside to implement the plans if necessary (pursuant
to the financial responsibility requirements at Sec. 146.85).
[[Page 77261]]
3. Mechanical Integrity Testing (MIT)
Injection well MIT is a critical component of the UIC program's
requirements designed to ensure USDW protection from endangerment.
Testing and monitoring the integrity of an injection well at an
appropriate frequency throughout the injection operation, in
conjunction with corrosion monitoring of well materials, can verify
that the injection system is operating as intended or provide notice
that there may be a loss of containment that may lead to endangerment
of USDWs. Routine MITs enable owners or operators to ensure that well
integrity is maintained from construction throughout the life of the
injection project. UIC regulations for other deep-well classes require
injection well owners or operators to demonstrate both internal and
external mechanical integrity.
Internal MIT: Internal mechanical integrity (MI) is an absence of
significant leakage in the injection tubing, casing, or packer. Loss of
internal MI is usually due to corrosion or mechanical failure of the
injection well's tubular and mechanical components. Typically, internal
MI is demonstrated with an annual pressure test of the annular space
between the injection tubing and long-string casing.
For Class VI wells, EPA proposed that owners or operators perform
an initial annulus pressure test and then continuously monitor
injection pressure, injection rate, injected volume, pressure on the
annulus between the tubing and long-stem casing, and annulus fluid
during injection. EPA sought comment on the appropriate frequency of
internal MIT and the practicality of continuous testing to measure
internal MI. Commenters' suggestions on the appropriate frequency
varied and some believed that the proposed requirement for continuous
monitoring seemed excessive and/or impractical.
Today's rule at Sec. 146.89 retains the requirements for
continuous monitoring to demonstrate internal MI presented in the
proposed rule. This is driven by concerns that the potential
corrosivity of CO2 in the presence of water and the
anticipated high pressures and volumes of injectate could compromise
the integrity of the well. Continuous monitoring to demonstrate
internal MI for Class VI wells is essential because it allows for the
immediate identification of corrosion-related mechanical integrity
problems or problems due to temperature and pressure effects associated
with injection of supercritical CO2. Furthermore, the
technologies used for continuous monitoring are currently available and
widely used.
External MIT: External well MI is demonstrated by establishing the
absence of significant fluid movement along the outside of the casing,
generally between the cement and the well structure, and between the
cement and the well-bore. 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-bore. This type of failure can lead to movement of injected
fluids out of intended injection zones and toward USDWs.
EPA proposed annual external MIT using a tracer survey, a
temperature or noise log, a casing inspection log, or any other test
the Director requires. EPA sought comment on the appropriate frequency
and types of MITs for Class VI wells. In general, commenters requested
flexibility in methods and timing of testing, with some suggesting a
five-year frequency for external MIT.
Because GS is a new technology and there are a number of unknowns
associated with the long-term effects of injecting large volumes of
CO2, today's rule requires owners or operators of
CO2 injection wells to demonstrate external MI at least once
annually during injection operations using a tracer survey or a
temperature or noise log (Sec. 146.89(c)). This increase in required
testing frequency relative to other injection well classes ensures the
protection of USDWs from endangerment given the potential corrosive
effects of CO2 (in the presence of water) on well components
(steel casing and cement) and the buoyant nature of supercritical
CO2 relative to formation brines, which could enable it to
migrate up a compromised wellbore. The Director may also authorize an
alternate test of external mechanical integrity with the approval of
EPA (Sec. 146.89(e)).
In addition, the final rule is modified from the proposal to allow
the Director discretion to require use of casing inspection logs to
determine the presence or absence of any casing corrosion at Sec.
146.89(d). To ensure the appropriate application of this test and to
afford flexibility to owners or operators and Directors, the final rule
requires that the frequency of this test be established based on site-
specific and well-specific conditions and incorporated into the testing
and monitoring plan if the Director requires such testing. This
modification is made to clarify that such logs, while not used to
directly assess mechanical integrity, may be used to measure for
corrosion of the long-string casing and thus may serve as a useful
predictor of potential mechanical integrity problems in the future.
4. Corrosion Monitoring
Existing UIC Class I deep well operating requirements allow the
Director discretion to require corrosion monitoring and control where
corrosive fluids are injected. Corrosion monitoring can provide early
warning of well material corrosion that could compromise the well's MI.
Given the potential for corrosion of well components if they are in
contact with water saturated with CO2 or CO2 in
the presence of water, corrosion monitoring is included as a routine
part of Class VI well testing. EPA proposed quarterly monitoring using
coupons, routing the CO2 injectate through a loop of well
material, or an alternative method proposed by the Director.
Some commenters believed that such testing was unnecessary given
that well materials will need to be constructed with materials
compatible with the injectate. EPA notes, however, that the long-term
effects of CO2 on cement and other well components are not
yet completely understood. Given the anticipated long life-span of a
Class VI well and the difficulties that would be associated with a
corrosion-related well failure, EPA believes that quarterly corrosion
monitoring is justified and retains the requirement in the final rule
(at Sec. 146.90(c)).
5. Ground Water/Geochemical Monitoring
Ground water and geochemical monitoring are important monitoring
techniques that ensure protection of USDWs from endangerment, preserve
water quality, and allow for timely detection of any leakage of
CO2 or displaced formation fluids out of the target
formation and/or through the confining layer. Periodically analyzing
ground water quality (e.g., salinity, pH, and aqueous and pure-phase
CO2) above the confining layer can reveal geochemical
changes that result from leaching or mobilization of heavy metals and
organic compounds, or fluid displacement.
EPA proposed periodic monitoring of the ground water quality and
geochemical changes above the confining zone and sought comment on the
types and frequencies of monitoring to be performed. The Agency agrees
with commenters who support a flexible monitoring regime, and believes
that the amounts and types of monitoring should be site specific.
[[Page 77262]]
Some commenters expressed concern that monitoring wells penetrating
the confining layer could become conduits for fluid movement. EPA
clarifies that direct geochemical monitoring is not required in the
target formation itself, although sampling via wells in the target
formation may be desirable in some circumstances, e.g., to perform
geochemical monitoring in wells used for direct pressure monitoring to
meet requirements of Sec. 146.90(g). Furthermore, EPA believes that
the benefits of direct monitoring using wells outweigh the risks of
unintended fluid migration. Monitoring wells provide important
information that confirms injectate confinement. Careful siting and
appropriate construction of monitoring wells are critical to effective
monitoring and can minimize the potential that monitoring wells serve
as conduits for fluid movement.
The final rule, at Sec. 146.90(d), retains the requirement for
direct ground water quality monitoring as specified in the site-
specific monitoring plan. Such monitoring is required above the
confining zone (and below the lower confining zone for waivered wells
pursuant to requirements at Sec. 146.95(f)). The number, placement,
and depth of monitoring wells will be site-specific and will be based
on information collected during baseline site characterization. Ground
water and geochemical monitoring results, when compared to baseline
site characterization data, previous monitoring results, and
operational parameters will enable owners or operators and Directors to
assess project performance, confirm that the injectate, formation
fluids, and the injection operation are not impacting overlying (and
underlying, for wells operating under injection depth waivers)
formations, identify formation fluid changes, inform modifications to
the monitoring plan, and ensure USDW protection from endangerment.
6. Pressure Fall-Off Testing
Pressure fall-off tests are designed to determine if reservoir
pressures are tracking predicted pressures and modeling inputs. The
results of pressure fall-off tests will confirm site characterization
information, inform AoR reevaluations, and verify that projects are
operating properly and the injection zone is responding as predicted.
EPA proposed that owners or operators perform pressure fall-off
testing at least once every five years and requested comment on the use
and frequency of these tests. Some commenters expressed support for the
tests, and suggested frequencies of annually to every five years. Some
commenters expressed opposition to the tests stating that they are not
necessary and the information they provide is not unique and may be
obtained from other tests.
The Agency believes that pressure fall-off testing provides
valuable information and that a five-year frequency is appropriate. The
final rule, at Sec. 146.90(f), retains the requirement for testing at
least once every five years. EPA believes that this frequency will
allow for pressure tracking in the injection formation. It will also
help to verify that the operation is responding as modeled/predicted
and allow the owner or operator to take appropriate action (e.g.,
recalibration of the AoR model) in the event that the monitoring
results do not match expectations.
7. CO2 Plume and Pressure Front Monitoring/Tracking
Monitoring the movement of the CO2 and the pressure
front are necessary to identify potential risks to USDWs posed by
injection activities, verify predictions of plume movement, provide
inputs for modeling, identify needed corrective actions, and target
other monitoring activities. The proposed rule required tracking of the
plume and pressure front by direct pressure monitoring via monitoring
wells in the first formation overlying the confining zone or by using
indirect geophysical techniques such as seismic profiling, electrical,
gravity, and electromagnetic surveys.
EPA sought comment on the requirement to track the CO2
plume and pressure front and the appropriate technologies and
geophysical methods that can be used for such monitoring. Commenters
focused on appropriate testing frequency and technologies, expressing
concerns about cost and the belief that the requirements were too
stringent and might negatively affect public opinion. With respect to
direct monitoring of pressure, some commenters supported the proposed
approach, while others believed the use of monitoring wells would be
costly and difficult. Some commenters supported indirect (i.e.,
geophysical) monitoring of the plume, while others expressed concerns
that seismic methods may not be effective in all settings.
In consideration of all public comments, today's final rule at
Sec. 146.90 requires Class VI well owners or operators to perform
monitoring to track the extent of the CO2 plume and pressure
front. The owner or operator must use direct methods to monitor for
pressure changes in the injection zone. Indirect methods (e.g.,
seismic, electrical, gravity, or electromagnetic surveys and/or down-
hole CO2 detection tools) are required unless the Director
determines, based on site-specific geology that such methods are not
appropriate (Sec. 146.90(g)).
The purpose of monitoring in the injection zone (Sec.
146.90(g)(1)) is to track the development and movement of the pressure
front and CO2 plume. This will support an understanding of
site performance and verify predictive modeling. Pressure monitoring
within the injection zone is necessary because any such monitoring
above the confining zone would not detect movement of the pressure
front unless a breach of the confining zone occurs. EPA believes that
monitoring using wells in the injection zone (i.e., that penetrate the
confining zone) can be safely performed if the wells are constructed to
prevent flow between the injection zone and USDWs or other layers above
the confining zone. Such construction technologies exist and have been
used in the oil and gas industry for years. EPA believes that the
benefits of monitoring in the injection formation outweigh the
manageable risk of those monitoring wells serving as conduits for fluid
movement. EPA adds that owners or operators may consider performing
additional pressure monitoring in wells that are above the confining
zone (e.g., in the same wells used to perform ground water quality
monitoring required at Sec. 146.90(d)) to provide additional
verification that no pressure changes are occurring above the confining
zone due to CO2 leakage or displacement of native fluids. An
appropriate monitoring regimen will enhance public confidence in GS.
EPA disagrees that the use of monitoring wells to track the plume and
pressure front will be too costly and believes that the benefits
outweigh the costs.
Additionally, Sec. 146.90(g)(2) requires owners or operators to
track the position of the CO2 plume using indirect methods
(e.g., seismic, electrical, gravity, or electromagnetic surveys and/or
down-hole CO2 detection tools), unless the Director
determines based on site-specific geology, that such methods are not
appropriate. EPA is affording Director's discretion regarding the use
of geophysical techniques at some sites because the Agency recognizes
that geophysical methods are not appropriate in all geologic settings.
For example, geophysical methods are difficult to execute in areas that
are structurally and topographically complex or where lithologies have
limited contrast in density, porosity, permeability, and other physical
properties. EPA clarifies that this
[[Page 77263]]
determination will be made by the Director based on the site-specific
geologic information submitted by the owner or operator with their
permit application. However, because the use of geophysical methods can
yield valuable information about the extent of the CO2 plume
and pressure front, EPA is requiring their use unless they are
determined not to be appropriate.
EPA believes that this approach--requiring direct pressure
monitoring at all sites and the use of indirect geophysical or down-
hole techniques except where the Director determines that such methods
are not appropriate based on site-specific information--provides owners
or operators the flexibility to develop a site-specific monitoring
plan, ensures that direct monitoring is available to track the movement
of the CO2 and validate models, and recognizes that indirect
techniques may not be appropriate in all situations.
8. Surface Air/Soil Gas Monitoring
EPA proposed that Directors have discretion to require surface air
and/or soil gas monitoring at GS sites. Surface air and soil gas
monitoring can be used to monitor the flux of CO2 out of the
subsurface, with elevation of CO2 levels above background
levels indicating potential leakage and USDW endangerment. While deep
subsurface well monitoring forms the primary basis for detecting
threats to USDWs, knowledge of leaks to shallow USDWs is of critical
importance because 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 may assist owners or operators in
identifying the general location of the leak and what USDWs may have
been impacted by the leak, and initiating targeted emergency and
remedial response actions.
EPA sought comment on the use of surface air and soil gas
monitoring technologies to ensure USDW protection. Commenters that
supported the use of surface air and soil gas monitoring technologies
stressed the importance of USDW protection and noted that this
monitoring can provide a potential indication that a leak into a USDW
has occurred and may need to be remediated. These commenters suggested
that such monitoring should be site-specific and that any data
collected must be compared against baseline data (collected prior to
commencing an injection project). Those who opposed the proposed
surface air and soil gas monitoring requirements questioned the
applicability of surface air and soil gas technologies to USDW
protection, and expressed concerns about the potential for false
positives, uncertainty and variability in measurements, and the
negative impact that this requirement may have on public perception of
GS. Some commenters also believed that requiring such monitoring would
be outside the scope of SDWA authority.
The Agency agrees that surface air and soil gas monitoring, when
coupled with subsurface monitoring, may be appropriate at some GS
projects to ensure USDW protection and agrees that baseline information
is needed for this type of monitoring. EPA also acknowledges that
surface air and soil gas measurements are subject to variability and
may not be suitable for all settings as a method to ensure USDW
protection. However, EPA does not believe that this should entirely
preclude their use. The decision to use surface monitoring and the
selection of monitoring methods will be site-specific (e.g., may be
influenced by geology; injection depth; and operational conditions) and
must be based on potential risks to USDWs within the AoR. EPA also
believes that appropriately selected surface monitoring technologies
will not negatively influence public opinion, but could help to assure
the public that GS projects are being appropriately operated and
monitored. Used in conjunction with deep subsurface monitoring, as
required at Sec. 146.90, and as part of a multi-barrier approach to
protecting USDWs from endangerment, surface air and soil gas monitoring
are within the scope of SDWA's general authority (SDWA sections 1421 et
al.). Furthermore, where deployed, such monitoring will increase USDW
protection, enable immediate notification of the UIC Director in the
case of potential USDW endangerment, and facilitate remedial action.
The final rule at Sec. 146.90(h) retains the allowance for surface
air and soil gas monitoring at the discretion of the Director as a
means of identifying leaks that may pose a risk to USDWs and informing
emergency notification of a Class VI owner or operator and UIC Director
in the event of a USDW endangerment, pursuant to requirements at Sec.
146.91(c).
Since proposal of the Class VI UIC requirements (73 FR 43492, July
25, 2008), EPA proposed, and is finalizing concurrently with this
rulemaking, GS reporting requirements under the GHG Reporting Program
(subpart RR). Subpart RR is being promulgated under authority of the
CAA and builds on UIC requirements with the additional goals of
verifying the amount of CO2 sequestered and collecting data
on any CO2 surface emissions. If a Director requires surface
air/soil gas monitoring pursuant to requirements at Sec. 146.90(h) and
an owner or operator demonstrates that monitoring employed under
Sec. Sec. 98.440 to 98.449 of subpart RR meets the requirements at
Sec. 146.90(h)(3), the Director must approve the use of monitoring
employed under subpart RR.
The Agency recognizes that there may be unique circumstances
wherein the UIC Director requires the use of surface air/soil gas
monitoring other than monitoring deployed under subpart RR due to site-
specific considerations. For example, a UIC Director may identify a
sensitive USDW such as a sole source aquifer, as defined at 40 CFR part
149, in the AoR of a GS project. He or she may determine that the most
appropriate method of enhancing protection of such resources is to
require the owner or operator to deploy an array of soil gas probes,
pursuant to Sec. 146.90(h), around the sole source aquifer at
specified depths and lateral spacing, with specified sampling and
reporting frequencies, to ensure USDW protection. Such monitoring might
not be necessary under subpart RR, where the primary purpose of surface
air and soil gas monitoring is to verify the amount of CO2
sequestered and collect data on any CO2 surface emissions.
EPA believes that the requirements of these two rules complement
one another by concurrently ensuring USDW protection, as appropriate,
and requiring reporting of CO2 surface emissions under
subpart RR. Subpart RR is discussed further in section II.C.
9. Additional Requirements
EPA recognizes that monitoring and testing technologies used at GS
sites will vary and be project-specific, influenced by both geologic
conditions and project characteristics. At certain sites additional
monitoring may be needed. Furthermore, EPA acknowledges that the
science and technology behind subsurface monitoring and testing will
continue to develop, and new methods may emerge to provide additional
monitoring options. Therefore, the final rule (at Sec. 146.90(i))
allows the Director discretion to require additional monitoring where
appropriate. For example, a Director may require a Class VI owner or
operator to conduct ground water quality monitoring in additional
formations or zones or require the use of multiple indirect geophysical
methods for plume and pressure front tracking if he or she determines
it is
[[Page 77264]]
necessary based on review of project-specific information submitted.
The final rule, at Sec. 146.90(k), requires owners or operators to
submit a quality assurance and surveillance plan (QASP) for all testing
and monitoring requirements. A QASP ensures that all aspects of
monitoring and testing are verifiable, including the technologies,
methodologies, frequencies, and procedures involved. Each QASP will be
unique to a given GS project, informed by site-specific details,
monitoring technologies selected, and will be updated as the project
evolves in concert with the testing and monitoring plan.
G. Recordkeeping and Reporting
Pursuant to Sec. 1445(a)(1) of the SDWA, today's final rule at
Sec. 146.91 requires owners or operators of Class VI wells to submit
the results of required periodic testing and monitoring associated with
the GS project. Furthermore, today's rule at Sec. 146.91(e) also
requires that all required reports, submittals, and notifications under
subpart H be submitted to EPA in an electronic format. This requirement
applies to owners or operators in Class VI primacy States and those in
States where EPA implements the Class VI program, pursuant to Sec.
147.1. All Directors will have access to the data through the EPA
electronic data system.
EPA expects that the Class VI permit application process will be an
iterative process, during which the owner or operator must submit
information to the Director to inform permitting decisions and permit
issuance. During this process, the Director is responsible for
reviewing and approving the required information. The Agency is
requiring that owners or operators submit information in an electronic
format to facilitate accessibility and transferability; however, if an
owner or operator cannot submit the required data using EPA's
electronic reporting system, EPA expects the Director to seek EPA's
approval regarding an alternate reporting format. Following EPA's
approval of a non-electronic submittal format, an alternate reporting
procedure may be allowed.
The electronic reporting requirement is designed to facilitate
programmatic activities by providing Directors with information needed
to ensure compliance with UIC Class VI permits, while also ensuring
that GS projects are operating properly, are in compliance with their
permit conditions, and are sufficiently protective of USDWs. The
information compiled under Sec. 146.91 may be used as evidence of a
permit violation.
Use of EPA's electronic reporting system will also allow EPA to
access data related to Class VI program implementation and facilitate
coordination between EPA and co-regulators. EPA plans to use the data
and information submitted by owners or operators to periodically
evaluate the effectiveness of the GS program, enabling the Agency to
make changes to the Class VI program as necessary to incorporate new
research, data, and information about GS and associated technologies.
1. What information must be provided by the owner or operator?
Today's rule identifies the technical information and reports that
Class VI owners or operators must submit to the Director to obtain a
Class VI permit to construct, operate, monitor, and close a Class VI
well. The information submitted as a demonstration, to the Director,
must be in the appropriate format and level of detail necessary to
support permitting and project-specific decisions by the Director to
ensure USDW protection. The final decision regarding the
appropriateness and acceptability of all owner or operator submissions
rests with the Director.
Class VI Permit Application Information: Today's rule requires
owners or operators to submit, pursuant to the requirements at Sec.
146.91(e), information to the Director to support Class VI permit
applications (this information is enumerated at Sec. 146.82). This
information includes site characterization information on the
stratigraphy, geologic structure, and hydrogeologic properties of the
site; a demonstration that the applicant has met financial
responsibility requirements; proposed construction, operating, and
testing procedures; and AoR/corrective action, testing and monitoring,
well plugging, PISC and site closure, and emergency and remedial
response plans. The specific requirements for the content of this
information are discussed in other sections of this preamble.
Operational and Monitoring Reports: Today's rule, at Sec. 146.91,
requires owners or operators to submit project monitoring and
operational data at varying intervals, including semi-annually and
prior to or following specific events (e.g., 30-day notifications and
24-hour emergency notifications).
EPA proposed that operating data be reported semi-annually. EPA
also proposed that monitoring data be submitted semi-annually in
certain circumstances. Several commenters asked that the Director have
discretion to authorize reporting less frequently than semi-annually,
while other commenters suggested monthly or quarterly reporting. EPA is
retaining the semi-annual reporting requirement for operating data and
some monitoring data in the final rule (Sec. 146.91(a)). However,
permitting authorities may choose to require more frequent reporting.
The final rule also requires owners or operators to report the
results of mechanical integrity tests, any other injection well testing
required by the Director, and any well workovers within 30 days (Sec.
146.91(b)), as proposed.
Today's final rule consolidates notification requirements and
clarifies the manner in which the data must be reported. Owners or
operators must notify the Director in writing 30 days prior to any
planned well workover, stimulation, or test of the injection well
(Sec. 146.91(d)). This notification affords the Director an
opportunity to evaluate the planned activity in the context of new
information received since permit approval and correspond with the
owner or operator, if necessary, regarding any suggested modifications
to the planned activity or to place additional conditions on the
planned activity if necessary. EPA clarifies that a response by the
Director following 30-day notification is not required if the Director
has no further concerns regarding the activity. The final rule also
requires owners or operators to notify the Director within 24 hours of
obtaining any evidence that the injected CO2 stream and
associated pressure front may cause an endangerment to a USDW, any
noncompliance with a permit condition, or of an event (such as
malfunction of the injection system or triggering of a down-hole
automatic shut-off system) that may endanger USDWs, or any release of
carbon dioxide to the atmosphere or biosphere detected through any
required soil/air monitoring (Sec. 146.91(c)).
Area of review reevaluations and plan amendments: Today's final
rule requires owners or operators to electronically submit AoR
reevaluation information and all plan amendments, pursuant to Sec.
146.84, at a minimum of every five years.
Annual report: In addition to the recordkeeping and reporting
requirements, EPA sought comment on requiring submittal of an annual
report throughout the duration of a GS project. Most commenters did not
support annual reports.
Today's final rule does not include a requirement for an annual
report. EPA recognizes the concerns expressed by commenters about the
burden associated with an annual report, and
[[Page 77265]]
believes that the reporting required at Sec. 146.91(a) in conjunction
with the AoR reevaluations and associated plan updates, which are
required no less frequently than every five years, will facilitate a
continuous dialogue between owners or operators and the permitting
authority, provide evidence of compliance with the Class VI permit, and
ensure protection to USDWs.
2. How must information be submitted?
Electronic Reporting: Recognizing that much of the data generated
during Class VI site characterization, operation, testing and
monitoring, mechanical integrity testing, and during the post-injection
site care period will be generated in electronic format, EPA proposed
that owners or operators report data in an electronic format acceptable
to the Director (Sec. 146.91). EPA also proposed that the Director
have discretion to accept data in other formats, if appropriate. EPA
sought comment on electronic data submissions and the concept of
providing Directors discretion to accept other data formats. See
section II.C for additional information on mandatory reporting of
greenhouse gases under the Clean Air Act.
Most commenters supported the concept of requiring data to be
submitted electronically. Commenters also recognized that there may be
a need to accept data in other formats. Several commenters expressed
concern about whether States would have the capabilities to accept
electronic data submissions from owners or operators.
In light of the prevalent use of electronic data, the expectation
that Class VI wells will be used into the future, that the capability
to send and receive electronic data will improve over time, and that
today, information generated during GS site characterization,
operation, monitoring, and testing is generated in electronic formats,
the final rule requires that owners or operators submit data in an
electronic format.
Acknowledging that some States may have to develop electronic data
systems to receive electronic information from the owner or operator,
and that many States which already have electronic data systems will
have to make changes to accommodate a new class of UIC well (Class VI),
EPA believes that it is prudent to provide assistance by developing a
central framework for the electronic system that will be used by States
to gather and track owner or operator data. This will enable owners or
operators to submit data without having to wait for a State to develop
a system. It will also provide for standardized submissions across the
country and enable States to focus State resources on reviewing and
approving permit applications rather than building or upgrading
separate, independent databases for GS information.
EPA recognizes that there may be some circumstances where it may be
necessary to collect data in other formats, e.g., for historical data,
etc. Therefore, the Agency is providing for the Director to allow
submission of data in alternative formats on a case-by-case basis. EPA
expects that decisions to allow submission of data in formats other
than electronic will be based on the inability or inefficiency of
converting data to electronic formats, rather than the ability of the
State to accept electronic data.
3. What are the recordkeeping requirements under this rule?
Today's final rule requires that owners or operators retain most
operational monitoring data as required under Sec. 146.91 for 10 years
after the data are collected. In addition, the rule requires that
owners or operators retain certain data until 10 years after site
closure. This recordkeeping timeframe, which is longer than
requirements for other injection well classes, is appropriate and
tailored to the longer life-spans of GS projects.
The proposed rule did not include any requirements for operational
data recordkeeping. However, existing UIC requirements at 40 CFR
144.51(j), which apply to all permitted injection wells require
retention of certain operational data and permit application data for
three years and retention of injectate quality data throughout the life
of the project and for three years after injection well plugging.
Commenters requested clarity on the recordkeeping requirements for
Class VI well owners or operators, particularly related to well
plugging and site closure reports.
Today's final rule clarifies the recordkeeping requirements for
Class VI well owners or operators. These include the requirements at 40
CFR 144.51(j) and the Class VI-specific recordkeeping requirements in
today's rule at Sec. 146.91(f). Class VI well owners or operators must
retain data collected to support permit applications and data on the
CO2 stream until 10 years after site closure. Owners or
operators must retain monitoring data collected under the testing and
monitoring requirements at Sec. 146.90(b-i) for 10 years after it is
collected. Today's rule allows the Director authority to require the
owner or operator to retain specific operational monitoring data for a
longer duration of time (Sec. 146.91(f)(5)). Well plugging reports,
PISC data, and site closure reports must be kept for 10 years after
site closure (Sec. Sec. 146.92(d), 146.93(f), and 146.93(h)).
EPA believes that longer record retention timeframes are
appropriate for Class VI wells to ensure that all necessary data are
available to support AoR reevaluations, updates to the various plans
which will occur at least every five years, and non-endangerment
demonstrations during PISC. In addition, extended retention periods
will ensure that data are available should any project-specific
questions or concerns arise following site closure. These data will
also support EPA's review of project data as part of the adaptive
rulemaking approach.
Class VI compliance: Today's final Class VI rule includes
requirements for permitting, siting, construction, operation, financial
responsibility, testing and monitoring, PISC, and site closure of Class
VI injection wells to ensure that USDWs are not endangered. Site-
specific information collected during the site characterization process
and periodically updated throughout the life of the project is
incorporated into the GS project plans and used to establish permit
conditions. This information establishes the manner in which an owner
or operator must construct, operate, monitor, report on, and close a
Class VI GS project--the conditions the owner or operator must meet to
ensure compliance. Pursuant to requirements at 40 CFR 144.8, an owner
or operator's failure to comply with the site-specific permit
conditions, failure to complete construction elements, failure to
complete or provide compliance schedules or monitoring reports, failure
to submit complete reports, and any action that causes USDW
endangerment during the life of the GS project are considered instances
of noncompliance and will result in a violation of the permit under
SDWA section 1423. Additionally, EPA may use this information as
evidence of an imminent and substantial endangerment of a USDW, which
may require remedial action under SDWA section 1431.
Data and information gathered through information requests, semi-
annual and 30-day reporting, and other project records will provide
information to demonstrate and confirm that a Class VI project is in
compliance. Information reported within 24 hours as required under
Sec. 146.91(c), including, but not limited to: Evidence that the
injected CO2 stream or associated pressure front may cause
an endangerment to a USDW; triggering of a shut-off system; or failure
to maintain mechanical integrity is used to inform the Director of any
evidence
[[Page 77266]]
indicating that an owner or operator of a Class VI well has violated a
permit condition or caused endangerment to USDWs.
H. Well Plugging, Post-Injection Site Care (PISC), and Site Closure
Today's final action, at Sec. 146.92 requires owners or operators
of Class VI wells to plug injection and monitoring wells in a manner
that protects USDWs. The final rule, at Sec. 146.93, also contains
tailored requirements for extended, comprehensive post-injection
monitoring and site care of GS projects following cessation of
injection until it can be demonstrated that movement of the
CO2 plume and pressure front no longer pose a risk of
endangerment to USDWs.
Proper plugging of injection and monitoring wells is a long-
standing requirement in the UIC program designed to ensure that
injection wells do not serve as conduits for fluid movement following
cessation of injection and site closure in order to ensure protection
of USDWs. PISC, which is unique to GS, is necessary to ensure that site
monitoring continues until the injectate and any mobilized fluids do
not pose a risk to USDWs.
1. Injection Well Plugging
EPA proposed that, after injection ceases at a GS project, the
injection well must be plugged in order to ensure that the well itself
does not become a conduit for fluid movement into USDWs. Well plugging
activities include flushing the well with a buffer fluid, testing the
external mechanical integrity of the well, and emplacing cement into
the well in a manner that will prevent fluid movement that may endanger
USDWs. In the proposed rule, EPA did not specify the types of materials
or tests that must be used during well plugging, acknowledging that
there are a variety of methods that are appropriate and new materials
and tests may become available in the future. However, all plugging
materials must be compatible with the injectate (i.e., such that
plugging materials would not degrade over time). EPA sought comment on
the injection well plugging activities identified in the proposed rule.
Most commenters supported EPA's proposed approach regarding well
plugging. Because the injection well plugging requirements provide
appropriate protection of USDWs while allowing owners or operators
flexibility in meeting the well plugging requirements by allowing them
to choose from available materials and tests to carry out the
requirements, EPA retains the requirements as proposed in today's rule
at Sec. 146.92. The owners or operators must prepare and comply with a
Director-approved injection well plugging plan submitted with their
permit application (Sec. 146.92(b)). The approved injection well
plugging plan will be incorporated into the Class VI permit. The Agency
is developing guidance that describes the contents of the project plans
required in the GS rule, including the injection well plugging plan.
Owners or operators must submit a notice of intent to plug at least
60 days prior to plugging the well. At this time, if any changes have
been made to the original well plugging plan (e.g., based on
operational and monitoring data or data collected during AoR
reevaluations), the owner or operator must submit a revised injection
well plugging plan (Sec. 146.92(c)). Any amendments to the injection
well plugging plan must be incorporated into the permit following
public notice and comment and approval by the Director. EPA envisions
that owners or operators will take into account similar considerations
that guide updates to other project plans, e.g., the testing and
monitoring plan, as they update the injection well plugging plan.
However, EPA is not requiring formal periodic review and updates to the
injection well plugging plan throughout the injection phase because it
is not expected that changes to this plan will be implemented until the
point at which the injection well is to be plugged. EPA also encourages
an ongoing dialogue between owners or operators and Directors regarding
planned well plugging activities. Finally, owners or operators must
submit, to the Director, a plugging report within 60 days after
plugging. The Agency is developing guidance on injection well plugging,
PISC, and site closure that addresses performing well plugging
activities.
2. Post-Injection Site Care (PISC)
Today's final rule at Sec. 146.93 incorporates a PISC period,
specific to Class VI wells. PISC is the period after CO2
injection ceases--but prior to site closure--during which the owner or
operator must continue monitoring to ensure USDW protection from
endangerment.
PISC and site closure plan submittal and updates: EPA proposed that
owners or operators would prepare, update, and comply with a Director-
approved PISC and site closure plan that would describe the anticipated
PISC monitoring activities and frequency.
EPA sought comment on the PISC and site closure plan requirements.
Most commenters supported the requirement for PISC monitoring and the
proposed approach regarding submittal, revision, and implementation of
a PISC and site closure plan. Many commenters agreed that a PISC
monitoring plan is a necessary and important part of the permitting
process. These commenters supported the option to amend the plan.
However, they contended that, upon cessation of injection, if
evaluation of monitoring and modeling results indicates that the
project is performing as expected, an owner or operator should not have
to submit amendments to the plan.
Today's final regulation retains the PISC and site closure plan
requirements (Sec. 146.93) with an additional requirement at Sec.
146.93(a)(2)(v) that the owner or operator include the duration of the
PISC timeframe, and the demonstration of any alternative PISC timeframe
pursuant to requirements at Sec. 146.93(c) as part of the plan. The
requirement to maintain and implement the approved PISC and site
closure plan is directly enforceable regardless of whether the
requirement is a condition of the Class VI permit. The PISC and site
closure plan will serve to clarify PISC requirements and procedures
prior to commencement of a project.
Upon cessation of injection, today's rule requires that owners or
operators of Class VI wells either submit an amended PISC and site
closure plan or demonstrate to the Director through monitoring data and
modeling results that no amendment to the plan is needed (Sec.
146.93(a)(3)). Any amendments to the PISC and site closure plan would
be incorporated into the permit once they are approved by the Director.
EPA envisions that owners or operators would take into account similar
considerations that guide updates to other project plans, e.g., the
testing and monitoring plan, as they update the PISC and site closure
plan. EPA also encourages an ongoing dialogue between owners or
operators and Directors regarding planned PISC and site closure
activities. The Agency is developing guidance that describes the
content of the project plans required in the GS rule, including the
PISC and site closure plan.
PISC timeframe: EPA proposed that during PISC, owners or operators
of Class VI wells would be required to periodically monitor the site
and track the position of the CO2 plume and pressure front
to ensure USDWs are not endangered. The proposed rule identified a
default PISC timeframe of 50 years following the cessation of
injection. This timeframe was based on a review of research studies,
industry
[[Page 77267]]
reports, and existing environmental programs. In order to support site-
specific flexibility, the proposed rule stipulated that the PISC
timeframe could be shortened by the Director after cessation of
injection if the owner or operator could demonstrate that USDWs would
not be endangered prior to 50 years. Similarly, if after 50 years the
Director determined that USDWs may still become endangered by the
CO2 plume and/or pressure front, he or she could lengthen
the PISC timeframe. EPA sought comment on the proposed PISC timeframe
and whether the timeframe should be adjusted.
Most industry commenters supported reducing the default PISC
timeframe, stating that the 50-year default timeframe in the proposal
would make GS prohibitively expensive, and is not warranted based on
the probable timeframes of CO2 trapping. Commenters
suggested that the PISC timeframe should be specific to the
characteristics of a project, including the predicted extent of the
CO2 plume and the area of elevated pressure, geologic
factors, modeled predictions of CO2 trapping, and subsurface
geochemical reactions and that the PISC period be established on a
case-by-case basis as a part of the permitting process. Other
commenters supported the proposed 50-year PISC period and indicated
that the risks of GS to USDWs are still unclear, and thus a
conservative PISC monitoring time period should be implemented. Other
commenters asserted that a combination of a fixed timeframe and a
performance standard would strike a good balance and is preferable to
relying on only one approach.
EPA evaluated comments advocating for a shorter timeframe,
including suggestions of 10 and 30 years. However, EPA has not obtained
any data from commenters or identified other research that contradict
EPA's initial analysis and supports a default timeframe shorter than 50
years. EPA acknowledges the merits of a performance-based approach for
the PISC timeframe, recognizing the variety of site conditions that
will affect the appropriate PISC timeframe. EPA believes that the
Director will be in the best position to make a site-specific
determination allowing for the PISC timeframe to be modified while
ensuring USDWs are not endangered.
Therefore, in response to comments, EPA retains the proposed
default 50-year PISC timeframe. However, today's final rule affords
flexibility regarding the duration of the PISC timeframe by: (1)
Allowing the Director discretion to shorten or lengthen the PISC
timeframe during the PISC period based on site-specific data, pursuant
to requirements at Sec. 146.93(b); and, (2) affording the Director
discretion to approve a Class VI well owner or operator to demonstrate,
based on substantial data during the permitting process, that an
alternative PISC timeframe is appropriate if it ensures non-
endangerment of USDWs pursuant to requirements at Sec. 146.93(c).
EPA clarifies that owners or operators of all GS sites (i.e., those
commencing injection using the 50-year default PISC or those
demonstrating an alternative PISC timeframe pursuant to requirements at
Sec. 146.93(c)) must continue monitoring until they submit, for
Director review and approval, a demonstration based on monitoring and
other site-specific data that no additional monitoring is needed to
ensure that the GS project does not pose an endangerment to USDWs. If a
demonstration cannot be made that the GS project no longer poses a risk
of endangerment to USDWs, or the Director does not approve the
demonstration, the owner or operator must submit a plan to the Director
to continue post-injection site care until such a demonstration can be
made and approved by the Director.
Today's final rule at Sec. 146.93(c), affords the Director
discretion to approve a demonstration during the permitting process
(per requirements at Sec. 146.82(a)(18)) that an alternative post-
injection site care timeframe, other than the 50-year default, is
appropriate. The demonstration must be based on substantial evidence
and site-specific data and information compiled and analyzed during the
permitting process and must satisfy the Director, in consultation with
EPA that USDWs will be protected from endangerment from GS activities.
Today's final rule at Sec. 146.93(c)(1) specifies what the
Director, in consultation with EPA, must consider and what the
demonstration of an alternative PISC timeframe must be based on: The
results of site-specific computational modeling of the AoR (performed
pursuant to Sec. 146.84) and information that supports the PISC and
site closure plan development required at Sec. 146.93(a), including
the predicted timeframe for pressure decline within the injection zone
and any other zones; the predicted rate of CO2 plume
migration and timeframe for the cessation of migration; site-specific
chemical processes that will result in CO2 trapping (e.g.,
by capillary trapping, dissolution, and mineralization); the predicted
rate of CO2 trapping; and laboratory analyses, research
studies, and/or field or site-specific studies to verify the
information on trapping. The demonstration must also be based on
consideration and documentation of a characterization of the confining
zone(s), e.g., thickness, integrity, and the absence of transmissive
faults, fractures, and micro-fractures (based on information collected
per Sec. 146.82(a)(3)); the presence of potential conduits for fluid
movement near the injection well (per Sec. 146.84(c)(2)); the quality
of wells and well plugs in wells within the AoR (per Sec.
146.84(c)(3)); the distance between the injection zone and the nearest
USDWs above and/or below the injection zone (based on data collected
per Sec. 146.82(a)(5)); and any additional site-specific factors
required by the Director.
The demonstration of an alternative PISC timeframe must meet
criteria set forth at Sec. 146.93(c)(2) to ensure that the data and
models on which the demonstration is based are accurate, appropriate to
site-specific circumstances, based on the best available information,
calibrated where sufficient data are available, and reproducible. This
demonstration must be submitted as part of the permit application
pursuant to Sec. 146.82(a)(18); the duration of the alternative PISC
timeframe and the associated demonstration must be included in the PISC
and site closure plan pursuant to Sec. 146.93(a)(2)(iv); and, must be
incorporated in the permit as part of the PISC and site closure plan as
required at Sec. 146.82(c)(9).
Over the lifetime of the project, owners or operators must
periodically reevaluate the AoR regardless of the PISC timeframe
approved by the Director. This may also result in periodic
reevaluations and updates as needed to the PISC and site closure plan
(per Sec. 146.93(a)(4)). These reevaluations provide opportunities for
the owner or operator and the Director to review and validate the data
on which the alternative demonstration is based, along with operational
and monitoring data, to determine whether modifications to the
alternative PISC timeframe are needed, and to make changes to the PISC
plan as appropriate. Regardless of whether the PISC and site closure
plan is modified during the injection period or not, the rule requires
at Sec. 146.93(a)(3) that upon cessation of injection, owners or
operators must either submit an amended plan or demonstration to the
Director through monitoring data and modeling results that no amendment
to the plan is needed.
Today's final rule also retains the proposed approach affording the
Director discretion, during the PISC
[[Page 77268]]
period, to shorten the PISC timeframe if the owners or operators can
demonstrate that there is substantial evidence that the GS project no
longer poses a risk of endangerment to USDWs (Sec. 146.93(b)).
Likewise, the Director may lengthen the PISC timeframe if, after 50
years, USDWs still may become endangered.
EPA believes that a default post-injection site care timeframe of
50 years, with flexibility to adjust the timeframe during the
permitting process where substantial data exists to demonstrate that an
alternative timeframe would be protective of USDWs, or based on data
collected during the PISC period, is appropriate to address the range
of sites where GS is anticipated to occur, to accommodate site-specific
circumstances and various geologic conditions, and addresses
commenters' concerns, while ensuring USDW protection. The Agency is
developing guidance on injection well plugging, PISC, and site closure.
3. Site Closure
EPA proposed that, following a determination under Sec. 146.93
that the site no longer poses a risk of endangerment to USDWs, the
Director would approve site closure and the owner or operator would be
required to properly close site operations. EPA proposed site closure
activities similar to those for other well classes. These include
plugging all monitoring wells; submitting a site closure report; and
recording a notation on the deed to the facility property or other
documents that the land has been used to sequester CO2. Site
closure would proceed according to the approved PISC and site closure
plan. Today's final regulation retains these closure requirements (at
Sec. 146.93(d) through (h)).
The site closure report will 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 CO2 stream. The purpose of this report will
be to provide information to potential, future users and authorities of
the land surface and subsurface pore space regarding the operation.
Well plugging reports, PISC data, including, if appropriate, data and
information used to develop the alternative PISC timeframe, and site
closure reports must be kept for 10 years after site closure (or longer
at the Director's discretion), pursuant to the requirements at
Sec. Sec. 146.91(f),146.93(f), and 146.93(h). See section III.G for
more about the recordkeeping requirements in today's rule.
I. Financial Responsibility
Today's rule finalizes regulations at Sec. 146.85 to require that
owners or operators demonstrate and maintain financial responsibility
as approved by the Director for performing corrective action on wells
in the AoR, injection well plugging, PISC and site closure, and
emergency and remedial response.
The purpose of these financial responsibility requirements is to
ensure that owners or operators have the resources to carry out
activities related to closing and remediating GS sites if needed during
injection or after wells are plugged but before site closure is
approved so that they do not endanger USDWs. The end result is ensuring
that all the GS injection sites are cared for and maintained
appropriately and that there is no gap in coverage throughout injection
and post-injection site care and site closure.
EPA's Proposed Approach: Financial assurance for wells under the
UIC program 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 standby trust
fund), and an irrevocable trust fund; and (2) self-insurance
instruments, including the corporate financial test and the corporate
guarantee. In the preamble to the proposed rule, EPA described these
instruments and sought comment on the need to adjust financial
responsibility instruments for GS projects and the need for additional
financial responsibility instruments. The Agency also sought comment on
allowing separate financial demonstrations for injection well plugging
and PISC (i.e., a demonstration submitted prior to well plugging and
the beginning of the post-injection site care period rather than with
the permit application).
Summary of Public Comments and Other Input: Commenters identified
strengths and weaknesses of the various financial responsibility
instruments and expressed concerns about the risk of bank failures and
corporate insolvency, which could leave financial obligations unfunded.
Some commenters supported the use of self insurance (i.e., a financial
test and a corporate guarantee) as a mechanism to demonstrate financial
responsibility for GS projects, but expressed concerns that companies
that have passed financial tests can fail, and also that the current
tangible net worth requirement of $10 million is not adequate for GS
projects. Generally, commenters supported allowing separate financial
demonstrations for injection well plugging and PISC. Many commenters
expressed concern about the potential high cost and long time frames
involved with GS projects. They believed that financial assurance would
be difficult to obtain, particularly throughout the duration of the
PISC period and that it may discourage investment in GS.
Commenters also expressed a need for regulatory certainty to help
inform financial responsibility requirements for well owners or
operators. They suggested that EPA specify the acceptability of various
financial responsibility instruments and that States needed guidance
including information on what instruments they should approve in order
to avoid approving financial assurance that did not meet the Federal
requirements or that was financially inadvisable. Other commenters
suggested that the proposed rule left too much discretion to the
Director, possibly causing operators to run a higher risk of having
their instrument rejected. Other commenters suggested that the rule
provide flexibility to owners or operators in the choice of financial
instruments, while allowing the Director discretion to assess
instruments in the context of operational and site-specific factors,
including the level of risk over time, when approving financial
responsibility for each project.
Many commenters addressed the use of a pay-in period for trust
funds. Some commenters expressed concern that an initial three-year
pay-in period would increase upfront costs, while others suggested that
an initial pay-in period could help lower financial risk. A commenter
suggested that the duration of the pay-in period could coincide with
the estimated project risk.
In addition to evaluating public comments, EPA worked with members
of the public, academia, industry, regulatory agencies, and financial
experts to address the unique financial responsibility issues
associated with GS projects. In April and May of 2009, EPA held
webinars for the public and industry stakeholders to gather information
to inform the financial responsibility requirements and guidance. The
webinars facilitated information sharing among stakeholders on
financial instruments that could be used to meet the financial
responsibility requirements for GS projects. Approximately 100 webinar
participants, representing a range of organizations with interest in
and unique perspectives on financial
[[Page 77269]]
responsibility, attended the workshop series which focused on the
strengths and weaknesses of various financial instruments and their
applicability for various injection activities. The material presented
during the webinars and summaries of participant discussions can be
found in the docket for today's rulemaking.
EPA is also aware of recent published literature on the topic of
financial responsibility for GS. In particular, the World Resources
Institute (WRI) and CCS Regulatory Project (affiliated with Carnegie
Mellon University, Department of Engineering and Public Policy) have
published research on climate change technologies and policy issues.
These and other resources are informing EPA's financial responsibility
guidance. These reports can be found in the docket for today's
rulemaking.
To supplement publicly available literature and public comments,
EPA reevaluated the current minimum Tangible Net Worth (TNW)
requirement of $10 million used in the Class I regulations and will
recommend a TNW threshold for Class VI wells in guidance. EPA guidance
on TNW for GS will help ensure that the risk borne by the public from a
self-insured owner or operator is no greater than the riskiest scenario
where independent third-party instruments are used. The financial
responsibility guidance will also include a recommended cost estimation
methodology to assist owners or operators of Class VI wells. The
guidance will provide examples of cost considerations and activities
that may need to be performed to satisfy the requirements of today's
rule. A draft of this guidance will be posted on EPA's Web site at
http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm for
a 30-day public comment period concurrent with or shortly after
publication of today's final rule.
EPA solicited input from the Environmental Financial Advisory Board
(EFAB) to develop recommendations on financial responsibility for Class
VI wells absent any constraints under the SDWA. EFAB made several
recommendations that support the financial responsibility requirements
in today's final rule. EFAB agreed that both self insurance and third-
party insurance should be made available to responsible parties. They
also supported the requirement that third-party providers, such as
insurers, pass financial strength requirements, the use of credit
ratings to demonstrate financial strength, and that the owner or
operator notify the Director in the event of bankruptcy. EFAB also
agreed that financial responsibility requirements be linked to cost
estimates, with regular updates to both cost estimates and financial
responsibility demonstrations. Additionally, EFAB specifically
recommended:
The use of standardized language for financial
instruments. Although EFAB did not recommend the use of standardized
policy language for insurance, they did suggest that procedures be
adopted so that the Director can specifically agree to limitations
contained in the insurance policy or specifically reject such
limitations during the review process;
That the owner or operator be required to notify the
Director by certified mail of any proceeding under Title 11
(Bankruptcy), U.S. Code, within 10 business days after the commencement
of the proceeding; that owners or operators be deemed to not possess
the required financial responsibility in the event of bankruptcy,
insolvency, or a suspension or revocation of the license or charter of
the third party when using letters of credit, surety bonds, or
insurance policies or loss of authority of the third party to act as a
trustee when using a trust fund;
That because the RCRA financial mechanisms, which are
largely used in the SDWA Class I program, were developed based on
hazardous waste facility owner's or operator's considerations, there
may be differences in the owner or operator profiles for proposed GS
facilities that warrant additional assurance mechanisms. Thus, the
Agency should consider adding a new category of financial assurance to
the Class VI program that provides the Agency with the flexibility to
approve the ``functional equivalent'' to the established RCRA financial
assurance tests; and
That EPA consider the use of rate-based financing, a new
category of instrument that would provide the Director with the
flexibility to approve instruments that are functionally equivalent to
existing qualifying instruments.
Today's Final Approach: Today's final regulation retains the
substantive requirements that owners or operators of Class VI wells
demonstrate and maintain financial responsibility to cover the cost of
corrective action, injection well plugging, PISC and site closure, and
emergency and remedial response. In response to public comments EPA
requested in the proposed rule and other input, this final regulation
at Sec. 146.85, modifies the proposed requirements to provide clarity
on acceptable instruments to enhance enforceability of the
requirements, and to set reporting timeframes to provide consistency
with other EPA regulations. Specifically, EPA has clarified the
financial responsibility requirements by:
(1) Describing ``qualifying instruments'' to cover the cost of
corrective action, injection well plugging, PISC and site closure, and
emergency and remedial response in a manner that prevents endangerment
of USDWs.
(2) Adding language clarifying that the financial responsibility
instrument is directly enforceable regardless of whether the
requirement is a condition of the permit.
(3) Requiring submission of annual inflationary updates and
specifying a 60-day timeframe after notification by the Director for
the submission of written updates of adjustments to the cost estimate.
(4) Requiring owners or operators to notify the Director no later
than 10 days after filing for bankruptcy.
(5) Requiring an owner or operator or its guarantor using self
insurance to demonstrate financial responsibility for GS to meet a
Tangible Net Worth of an amount approved by the Director; have both a
net working capital and a tangible net worth of at least six times the
sum of the current well plugging, post-injection site care and site
closure cost; have assets located in the U.S. amounting to at least 90
percent of total assets or at least six times the sum of the current
well plugging, post-injection site care and site closure cost; submit
annual report of bond rating and financial information; and either: (1)
Pass a bond rating test issued by one or both of the nationally
recognized bond rating agencies, Standard & Poor's and Moody's for
which the bond's rating must be one of the four highest categories
(i.e., AAA, AA, A, or BBB for Standard & Poor's or Aaa, Aa, A, or Baa
for Moody's); or, (2) Meet all of the following five financial ratio
thresholds:
A ratio of total liabilities to net worth less than 2.0;
A ratio of current assets to current liabilities greater
than 1.5;
A ratio of the sum of net income plus depreciation,
depletion, and amortization to total liabilities greater than 0.1;
A ratio of current assets minus current liabilities to
total assets greater than -0.1; and
A net profit (revenues minus expenses) greater than 0.
These financial responsibility requirements are not made to
duplicate existing financial responsibility regulations, but are
tailored to the
[[Page 77270]]
unique characteristics and requirements of GS. Considering the
potential high costs associated with large-scale deployment of GS
projects, EPA would like to ensure that adequate and continuous
financial responsibility mechanisms are in place throughout the life of
each GS project and that the cost associated with operation of GS
projects is not passed along to the public. EPA also believes that
having stringent self-insurance requirements in addition to an annual
evaluation of the financial instrument minimizes the potential for a
financial institution (that has passed the test) to be likely to
undergo financial difficulties that can hinder the financial
responsibility demonstration for a GS project.
EPA's final approach for financial responsibility for Class VI
wells: EPA does not have authority under SDWA to be the direct or
indirect beneficiary of a trust fund under this statute for the purpose
of establishing financial responsibility for GS projects. EPA must
comply with the Miscellaneous Receipts Act, 31 U.S.C. 3302. Standby
trust funds are not stand-alone financial instruments that can be used
by an owner or operator to demonstrate financial responsibility.
Standby trusts must be used with certain types of financial
responsibility instruments to enable EPA to be party to the financial
responsibility agreement without EPA being the beneficiary of any
funds. Use of standby trust funds must be accompanied by other
financial responsibility instruments (e.g., surety bonds, letters of
credit, or escrow accounts) to provide a location to place funds if
needed. The final rule, at Sec. 146.85(a)(1), identifies the following
qualifying financial instruments for Class VI wells, all of which must
be sufficient to address endangerment of USDWs. Standby trusts are not
needed for options 1, 4, and 5.
(1) Trust Funds: If using a trust fund, owners or operators are
required to set aside funds with a third party trustee sufficient to
cover estimated costs. During the financial responsibility
demonstration, the owner or operator may be required to deposit the
required amount of money into the trust prior to the start of injection
or during the ``pay-in period'' if authorized by the Director.
(2) Surety Bond: Owners or operators may use a payment surety bond
or a performance surety bond to guarantee that financial responsibility
will be fulfilled. In case of operator default, a payment surety bond
funds a standby trust fund in the amount equal to the face value of the
bond and sufficient to cover estimated costs, and a performance surety
bond guarantees performance of the specific activity or payment of an
amount equivalent to the estimated costs into a standby trust fund.
(3) Letter of Credit: A letter of credit is a credit document,
issued by a financial institution, guaranteeing that a specific amount
of money will be available to a designated party under certain
conditions. In case of operator default, letters of credit fund standby
trust funds in an amount sufficient to cover estimated costs.
(4) Insurance: The owner or operator may obtain an insurance policy
to cover the estimated costs of GS activities requiring financial
responsibility. This insurance policy must be obtained from a third
party to decrease the possibility of failure (i.e., non-captive
insurer).
(5) Self Insurance (i.e., Financial Test and Corporate Guarantee):
Owners or operators may self insure through a financial test provided
certain conditions are met. The owner or operator needs to pass a
financial test to demonstrate profitability, with a margin sufficient
to cover contingencies and unknown obligations, and stability. If the
owner or operator meets corporate financial test criteria, this is an
indication that the owner or operator can guarantee its ability to
satisfy financial obligations based solely on the strength of the
company's financial condition. An owner or operator who is not able to
meet corporate financial test criteria may arrange a corporate
guarantee by demonstrating that its corporate parent meets the
financial test requirements on its behalf. The parent's demonstration
that it meets the financial test requirement is insufficient if it has
not also guaranteed to fulfill the obligations for the owner or
operator.
(6) Escrow Account: Owners or operators may deposit money to an
escrow account to cover financial responsibility requirements. This
account must segregate funds sufficient to cover estimated costs for GS
financial responsibility from other accounts and uses.
(7) Other instrument(s) satisfactory to the Director: In addition
to these instruments, EPA anticipates that new instruments that may be
tailored to meet GS needs may emerge, and may be determined appropriate
for use by the Director for the purpose of financial responsibility
demonstrations.
The final rule specifies that the qualifying financial
responsibility instrument must include protective conditions of
coverage, including, but not limited to: Cancellation, renewal, and
continuation provisions; specifications on when the provider becomes
liable in case of cancellation if there is a failure to renew with a
new qualifying financial instrument; and requirements for the provider
to meet a minimum credit rating, minimum capitalization, and ability to
pass the bond rating when applicable. This clarification was made in
direct response to issues raised by commenters for numerous
instruments, and also to make sure that there is no gap in coverage if
a financial instrument fails.
Today's rule, at Sec. 146.85(c), requires the owner or operator to
have a detailed written estimate, in current dollars, of the cost of:
Performing corrective action on wells in the AoR, plugging the
injection well(s), PISC and site closure, and emergency and remedial
response. A cost estimate must be prepared separately for each of these
activities and be based on the costs to the owner or operator of hiring
a third party (who is neither a parent nor a subsidiary of the owner or
operator) to perform the activities. EPA recommends that owners or
operators take the following into account when determining the cost
estimate for GS projects:
(1) Performing corrective action on wells in the AoR. This includes
conducting corrective action on deficient wells in the AoR during the
initial AoR, under a phased corrective action approach; and for newly-
identified deficient wells in subsequent AoR re-evaluations. See
section III.B for more details on the AoR and corrective action plan
requirements.
(2) Plugging the injection well(s). This includes performing a
final external MIT and plugging the wells in a manner that considers
the well depth, the number of plugs and the amount of cement needed,
the composition of the captured CO2, and the types of
subsurface formations. See section III.H for more details on plugging
requirements.
(3) Post-injection site care and closure. This includes all needed
monitoring and site care until it can be demonstrated that the site no
longer poses an endangerment to USDWs. See section III.H for more
details on post-injection site care and site closure requirements.
(4) Emergency and remedial response. This includes the cost to
perform any necessary responses or remediation to address potential
USDW endangerment. See section III.J for more details on the emergency
and remedial response requirements.
Owners or operators have the flexibility to choose from a variety
of financial instruments to meet their financial responsibility
obligations. Owners or operators may use one or multiple financial
responsibility
[[Page 77271]]
instruments for well plugging and PISC (Sec. 146.85(a)(6)). However,
EPA will not allow for a separate financial responsibility
demonstration for well plugging and PISC (i.e., a demonstration
submitted prior to well plugging and the beginning of the PISC period
rather than with the permit application). A demonstration of financial
responsibility for all phases of the GS project will be required prior
to the issuance of a Class VI permit (Sec. 146.85(a)(5)(i)).
EPA adds that under today's final rulemaking at Sec. 146.85(a),
the Director will only approve instruments determined to be sufficient
to address endangerment of USDWs, and has the discretion to disapprove
of instruments that he/she determines may not be sufficient based on
the following:
(1) The financial instrument is not determined to be a qualifying
instrument;
(2) The financial instrument is not sufficient to cover the cost to
properly plug and abandon, remediate, and manage wells;
(3) The financial instrument is not sufficient to address
endangerment of USDWs; or
(4) The financial instrument does not include required conditions
of coverage to facilitate enforceability and prevent gaps in coverage
for the life of the GS project.
EPA has added language, at Sec. 146.85(b), that a financial
responsibility instrument is directly enforceable regardless of whether
the requirement is a condition of the permit. EPA also specifies
circumstances under which an owner or operator may be released from a
financial instrument, including that the owner or operator has
completed the GS project activity for which the financial instrument
was required and has fulfilled all financial obligations as determined
by the Director, or has submitted a replacement financial instrument
and received written approval from the Director accepting the new
financial instrument and releasing the owner or operator from the
previous financial instrument. The Director's determination of
completion of a GS project activity may be sustained by a professional
engineer's report on completion. The Director must notify the owner or
operator in writing that the owner or operator is no longer required to
maintain financial responsibility for the project or activity. This
clarification was added to address unforeseen situations where EPA may
need to directly enforce the financial responsibility provisions should
the permit inadequately provide protection of USDWs from endangerment.
This rule, at Sec. 146.85(c), also requires that the owner or
operator adjust the cost estimates to address amendments to the AoR and
corrective action plan (Sec. 146.84), the injection well plugging plan
(Sec. 146.92), the PISC and site closure plan (Sec. 146.93), and the
emergency and remedial response plan (Sec. 146.94). Within 60 days
after the Director has approved any modifications to the plan(s), the
owner or operator must review and update the cost estimate for well
plugging, PISC and site closure, and emergency and remedial response to
account for any amendments if the change in the plan increases the
cost. The revised cost estimate must also be adjusted for inflation as
specified at Sec. 146.85(c)(2). Any changes to the approved cost
estimate must be approved by the Director.
Today's rule does not allow a separate demonstration for financial
responsibility requirements (i.e., a demonstration submitted prior to
well plugging and the beginning of the post-injection site care period
rather than with the permit application). Although the owner or
operator may use a financial instrument or a combination of financial
instruments for the purpose of financial responsibility for specific
phases of the GS project, the demonstration of financial responsibility
must be done for the overall GS project at the time of permit
application. However, today's rule, at Sec. 146.85(a)(6) provides
that, prior to obtaining a Class VI permit, an owner or operator may
demonstrate financial responsibility by using one or multiple
qualifying financial instruments for specific GS activities, thereby
realizing greater flexibility and cost savings from this regulation. In
the event that the owner or operator combines more than one instrument
for a specific GS activity (e.g., well plugging), such combination must
be limited to instruments that are not based on financial strength or
performance (i.e., self insurance or performance bond), for example
trust funds, surety bonds guaranteeing payment into a trust fund,
letters of credit, escrow account, and insurance. In this case, it is
the combination of instruments, rather than the single instrument,
which must provide financial responsibility for an amount at least
equal to the current cost estimate. EPA also notes that today's rule
requires the Director to approve the use and length of pay-in-periods
for trust funds or escrow accounts. EPA understands that in some cases
a short pay-in period (e.g., three-years or less) will provide some
financial flexibility for owners or operators while balancing financial
risk.
EPA has further clarified financial responsibility requirements by
requiring owners or operators or a guarantor to notify the Director no
later than 10 days after filing for bankruptcy, at Sec. 146.85(d).
This requirement is added in direct response to commenters who
addressed the necessity of adequate financial responsibility
requirements, even in the event of operator bankruptcy. EPA is adding
this requirement in order to avoid a gap in coverage in the event that
an instrument fails. This timeframe is consistent with the current U.S.
bankruptcy code. In the event that the third party files for
bankruptcy, today's rule requires that the owner or operator establish
alternative financial assurance within sixty (60) days.
Today's rule, at Sec. 146.85(e), also requires the owner or
operator to adjust cost estimates if the Director has reason to believe
that the most recent demonstration is no longer adequate to cover the
cost of the identified activities. This clarification is made in direct
response to commenters who stressed the importance of accurate cost
estimates. The Agency is developing guidance, which will provide
direction to the Director for when a demonstration may no longer be
adequate to cover the GS activities.
As a Federal agency, EPA is working to create a nationally
consistent financial responsibility program for GS activities while
providing permitting authorities an appropriate level of flexibility.
EPA is developing guidance on financial responsibility for owners or
operators of Class VI wells to assist owners or operators in evaluating
the financial responsibility requirements for Class VI wells and to
assist Directors in evaluating financial responsibility demonstrations.
The guidance will describe financial responsibility options,
demonstrations, types of financial instruments for Class VI wells as
well as how to estimate the costs to support accurate financial
responsibility demonstrations specific to the needs of a GS project.
Long-term liability and stewardship for GS projects under the SDWA:
EPA received a range of comments from stakeholders regarding liability
following site closure. Many commenters suggested that, after a GS site
is closed, liability should be transferred to the State or Federal
government or to a publicly- or industry-funded entity based on a
series of rationales (e.g., the need for certainty; the potential for
high cost; insurance and legal concerns). EPA also received
[[Page 77272]]
comments from those who disagreed with the assertion that a public
entity should bear liability following site closure based on the belief
that, if owners or operators face potential liability following site
closure, they would use precaution in their operations to avoid risks
and potential environmental damage. Additionally, many commenters
encouraged EPA to consider other State or Federal laws under which
liability transfers may be accomplished as models for GS liability
transfer.
Under SDWA authority, owners or operators of injection wells must
ensure protection of USDWs from endangerment and are subject to
liability for enforcement under the Act. The final rule requires that
an owner or operator must conduct monitoring as specified in the
Director-approved PISC and site closure plan following the cessation of
injection until the owner or operator can demonstrate to the Director
that the geologic sequestration project no longer poses an endangerment
to USDWs. For additional information about the PISC and site closure
requirements, see section III.H of this action.
Once an owner or operator has met all regulatory requirements under
part 146 for Class VI wells and the Director has approved site closure
pursuant to requirements at Sec. 146.93, the owner or operator will
generally no longer be subject to enforcement under section 1423 of
SDWA for noncompliance with UIC regulatory requirements. However, an
owner or operator may be held liable for regulatory noncompliance under
certain circumstances even after site closure is approved under Sec.
146.93, under section 1423 of the SDWA for violating Sec. 144.12, such
as where the owner or operator provided erroneous data to support
approval of site closure.
Additionally, an owner or operator may always be subject to an
order the Administrator deems necessary to protect the health of
persons under section 1431 of the SDWA after site closure if there is
fluid migration that causes or threatens imminent and substantial
endangerment to a USDW. For example, the Administrator may issue a SDWA
section 1431 order if a well may present an imminent and substantial
endangerment to the health of persons, and the State and local
authorities have not acted to protect the health of such persons. The
order may include commencing a civil action for appropriate relief. If
the owner or operator fails to comply with the order, they may be
subject to a civil penalty for each day in which such violation occur
or failure to comply continues.
Furthermore, after site closure, an owner or operator may,
depending on the fact scenario, remain liable under tort and other
remedies, or under other Statutes including, but not limited to, Clean
Air Act, 42 U.S.C. Sec. Sec. 7401-7671; CERCLA, 42 U.S.C. Sec. 9601-
9675; and RCRA, 42 U.S.C. 6901-6992.
EPA acknowledges stakeholder interest in liability and long-term
stewardship in the context of development and deployment of GS
technology, however, under current SDWA provisions EPA does not have
authority to transfer liability from one entity (i.e., owner or
operator) to another.
J. Emergency and Remedial Response
Today's rule at Sec. 146.94 requires Class VI well owners or
operators to develop and maintain an emergency and remedial response
plan that describes actions to be taken to address events that may
cause endangerment to a USDW during the construction, operation, and
PISC periods of a GS project. Owners or operators must also
periodically update the emergency and remedial response plan to
incorporate changes to the AoR or other significant changes to the
project. Today's requirements will support expeditious and appropriate
response to protect USDWs from endangerment in the unlikely event of an
emergency.
Developing emergency and remedial response plans: EPA proposed that
owners or operators submit an emergency and remedial response plan to
the Director as part of the Class VI permit application. The plan would
describe measures that would be taken in the event of adverse
conditions at the well, such as a loss of mechanical integrity, the
opening of faults or fractures within the AoR, or if movement of
injection or formation fluids caused an endangerment to a USDW.
Commenters were supportive of including an emergency and remedial
response plan as part of the Class VI permit, and some commenters
suggested that the plan should be risk based. EPA agrees that advanced
planning for emergency and remedial response is an important part of
ensuring protection of USDWs at GS sites from endangerment, and today's
rule retains the requirement for an emergency and remedial response
plan (Sec. 146.94(a)), and also requires that the approved emergency
and remedial response plan be incorporated into the Class VI permit.
The purpose of the emergency and remedial response plan is to ensure
that owners or operators comprehensively plan, in advance, what actions
would be necessary in the unlikely event of an emergency. The plan will
also ensure that operators know what entities and individuals must be
notified and what actions might need to be taken to expeditiously
mitigate any emergency situations and protect USDWs from endangerment.
The Agency is developing guidance that describes the contents of the
project plans required in the GS rule, including the emergency and
remedial response plan. The docket for today's rulemaking includes
brief research papers that discuss remedial technologies available to
address potential impacts of CO2 on water resources (USEPA,
2010b) and remedial technologies that may be used to seal faults and
fractures at GS sites (USEPA, 2010c).
EPA agrees with commenters that the emergency and remedial response
plan should be site-specific and ``risk-based.'' EPA expects that each
emergency and remedial response plan will be tailored to the site, and
today's rule provides flexibility to the owner or operator to design a
site-specific plan that meets the requirements of Sec. 146.94(a).
Rather than requiring specific information in the emergency and
remedial response plan that may not be relevant to all GS projects, the
plan allows such information to be determined on a site-specific basis.
The details of an emergency and remedial response plan may be
influenced by a variety of factors including: Geology, USDW depth, and
injection depth; the presence, depth, and age of artificial
penetrations; proposed operating conditions and properties of the
CO2; and activities in the AoR (e.g., the presence of
population centers, land uses, and public water supplies). The Director
will evaluate the proposed emergency and remedial response plan for a
GS project in the context of all information submitted with the permit
application (e.g., site characterization information, AoR evaluation
data, and well construction, monitoring, and operational information)
to ensure that the plan is appropriately comprehensive to address
potential emergencies.
Implementing the emergency and remedial response plan: EPA also
proposed several steps that the owner or operator would need to follow
if he or she obtained evidence that the injectate and associated
pressure front may endanger a USDW. Most comments requesting clarity on
this requirement recommended that EPA establish triggers during the
initial permitting phase and identify appropriate mitigation options.
EPA disagrees with commenters that it is appropriate or useful to
identify specific triggers or response actions in the rule that would
apply to all sites.
[[Page 77273]]
EPA believes that decisions about responses should be made through
consultation between owners or operators and Directors because each
response action will be site- and event-specific. The purpose of the
emergency and remedial response requirements in today's rule is to
ensure that a plan is in place for the owner or operator to take
appropriate action (e.g., cease injection) in the unlikely event of an
emergency or USDW endangerment. The plan also facilitates a dialogue
between the owner or operator and the Director to expedite the
necessary and appropriate response based on steps identified in
advance.
Today's rule at Sec. 146.94(b) requires that, if an owner or
operator obtains evidence of endangerment to a USDW, he or she must:
(1) Immediately cease injection; (2) take all steps reasonably
necessary to identify and characterize any release; (3) notify the
Director within 24 hours; and, (4) implement the approved emergency and
remedial response plan.
Emergency and remedial response plan updates: Two water
associations recommended that the emergency and remedial response plan
be reviewed and updated throughout the course of a GS project. EPA
agrees with these commenters and today's rule includes a requirement
that owners or operators must periodically review the emergency and
remedial response plan to incorporate operational and monitoring data
and the most recent AoR reevaluation at Sec. 146.94(d). This review
must take place within one year of an AoR reevaluation, following
significant changes to the facility, or when required by the Director.
The iterative process by which this and other required plans are
reviewed throughout the life of a project will promote an ongoing
dialogue between owners or operators and Directors and ensure that
owners or operators are complying with the conditions of their Class VI
permits. Tying emergency and remedial response plan reviews to the AoR
reevaluation frequency is appropriate to ensure that reviews of the
plans are conducted on a defined schedule that ensures there will be
appropriate revisions to the plan if there is a change in the AoR or
other relevant circumstances change, while adding little burden if the
AoR reevaluation confirms that the plan is appropriate as written.
K. Involving the Public in Permitting Decisions
Public input and participation in GS projects has a number of
benefits, including: (1) Providing citizens with access to decision-
making processes that may affect them; (2) educating the community
about a GS project; (3) ensuring that the public receives adequate
information about the proposed GS project; and (4) allowing the
permitting authority and owners or operators to become aware of public
viewpoints, preferences and environmental justice concerns and ensuring
these concerns are considered by 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. Early and frequent
public involvement through education and information exchange is
critical to the success of GS and can provide early insight into how
the local community and surrounding communities perceive potential
environmental, economic, or health effects associated with a specific
GS project. Owners or operators can increase the likelihood of success
by integrating social, economic, and cultural concerns of the community
into the permit decision-making process.
In the proposed rule, EPA sought comment on: (1) The
appropriateness of adopting existing public participation requirements
at 40 CFR parts 25 and 124 for GS; (2) the need for additional public
participation requirements to reflect availability of new information
technology to disseminate and gather information; and (3) ways to
enhance the public participation process.
Nearly all commenters agreed that early and frequent public
education and participation would enhance public acceptance of GS
projects. Several commenters supported adopting the existing public
participation requirements used for other injection well classes. Many
commenters favored requiring the use of new information technology to
improve public notification and involvement on GS projects and
permitting.
Today's final approach adopts the existing UIC public participation
requirements at 40 CFR part 25 and the permitting decision procedures
at 40 CFR part 124. EPA encourages owners or operators and permitting
agencies to involve the public by providing them information about the
Class VI permit (and any requests for a waiver of the injection depth
requirements or an expansion of the areal extent of an aquifer
exemption) as early in the process as possible. Under 40 CFR parts 25
and 124, permitting authorities must provide public notice of pending
actions via newspaper advertisements, postings, mailings, or e-mails to
interested parties; hold public hearings if requested; solicit and
respond to public comment; and involve a broad range of stakeholders.
EPA expects that there will be higher levels of public interest in
GS projects than for other injection activities. The Agency believes
that encouraging public participation will help permitting authorities
understand public concerns about GS projects and will afford the public
an opportunity to gain a clearer understanding of the nature and safety
of GS projects and technologies. To address comments about stakeholder
participation, EPA is amending the requirements for public notice of
permit actions and public comment period at Sec. 124.10 to clarify
that public notice of Class VI permitting activities must be given to
State and local oil and gas regulatory agencies, State agencies
regulating mineral exploration and recovery, the Director of the PWSS
program in the State, and all agencies that have jurisdiction to
oversee wells in the State in addition to the general public.
EPA agrees with commenters that the use of new forms of information
technology can improve public participation and understanding of GS
projects. EPA recognizes the importance of social media as a public
outreach tool. Social media, which are primarily Internet and mobile
based technologies for disseminating and discussing information, can
help provide accessibility and transparency to a wide audience. EPA
encourages permit applicants and permitting authorities to use the
Internet and other forms of social media to explain potential GS
projects; describe GS technologies; and post information on the latest
developments related to a GS project including schedules for hearings,
briefings and other opportunities for involvement.
L. Duration of a Class VI Permit
Today's rule establishes that Class VI permits are issued for the
life of the GS project, including the PISC period (Sec. 144.36). In
lieu of the periodic permit reissuance required for most other deep-
well classes, owners or operators of Class VI wells must periodically
reevaluate the AoR and prepare and implement a series of plans for AoR
and corrective action, testing and monitoring, injection well plugging,
PISC and site closure, and emergency and remedial response. These plans
must be reevaluated by the owner or operator throughout the life of the
project to foster a continuing dialogue between the owner or operator
and the
[[Page 77274]]
Director, and afford opportunities for public input as needed and
ensure compliance with the Class VI permit.
EPA proposed that Class VI injection well permits be issued for up
to the operating life of the facility, including the PISC period. In
the preamble to the proposed rule, EPA explained that, in lieu of
permit renewals for Class VI wells, owners or operators must
periodically re-evaluate the AoR, at least every 10 years. In existing
UIC program regulations, permit duration varies by injection well
class: permits for Class I and Class V wells are effective for up to 10
years; while Class II and III permits may be issued for the operating
life of the facility, but are subject to a review by the permitting
authority at least once every five years.
EPA sought comment on the proposed permit duration for Class VI
wells, the appropriateness of GS project plans, and the merits of
updating the AoR and corrective action plan in place of permit
reissuance. Many commenters supported EPA's proposal to issue permits
for the life of a GS project, stating that the requirements for
periodic reevaluation of the AoR and corrective action plan would make
a five-or ten-year permit review process unnecessary and that a
lifetime permit would provide operational continuity. Some commenters
suggested that other plans (e.g., the testing and monitoring plan)
should also be periodically reviewed throughout the life of the
project. Other commenters disagreed with EPA's proposed permit duration
for Class VI wells, believing that the proposed level and frequency of
interaction (i.e., every 10 years) between the primacy agency and owner
or operator would not be sufficient to justify a permit for the
operating life of the project. Comments both in favor of and opposition
to lifetime permits stressed the importance of incorporating new
information, the value of permit review and modification, and the need
for a transparent process.
EPA agrees with commenters regarding the need for continuous
interaction between permitting authorities and owners or operators of
GS projects. Today's rule retains the requirement that Class VI permits
are issued for the lifetime of the project (Sec. 144.36). It also
requires owners or operators to review and update the AoR and
corrective action plan, the testing and monitoring plan, and the
emergency and remedial response plan throughout the life of the project
(Sec. 146.84(e), Sec. 146.90(j), and Sec. 146.94(d)).
Today's rule requires owners or operators to review each plan as
required by part 146 and either identify necessary amendments to the
plan or demonstrate to the satisfaction of the Director that no
amendment is needed. These reviews must be performed within one year of
an AoR reevaluation, following any significant changes to the facility
(e.g., the addition of monitoring or injection wells), or when required
by the Director. In no case can reviews occur less often than once
every five years. This review frequency is necessary to ensure that
reviews of the plans are conducted on a defined schedule or when there
is a change in the AoR or other significant change, while adding little
burden if an AoR reevaluation confirms that the plans are appropriate
as written. (EPA also revised the AoR reevaluation frequency from 10
years to five years; see section III.B.)
EPA is not requiring formal periodic review and updates to the
injection well plugging plan and PISC and site closure plan throughout
the injection phase because it is not expected that changes to these
plans would be implemented until injection operations cease. However,
today's rule at Sec. Sec. 146.92 and 146.93 does require that owners
or operators identify any needed changes to these plans at the
cessation of injection operations.
Because the approved plans required by today's rule will be
incorporated into the Class VI permit, today's rule establishes permit
modification requirements tailored for Class VI permits (e.g.,
associated with plan updates and other project changes). These
requirements state that any changes to the plans will trigger a permit
modification pursuant to Sec. 144.39(a)(5).
These modifications invoke part 124 public participation
requirements. The Director, through consultation with the owner or
operator, may choose to provide public notice of permit modifications
as they occur or concurrent with the five year permit review schedule
at Sec. 144.36 (e.g., the Director may notice multiple modifications
at once, every five years). Minor changes to the plans (e.g.,
correction of typographical errors) that may result in a permit
modification pursuant to requirements at Sec. 144.41 for minor
modifications of permits will not require public notification. If any
of the plans are changed because of significant changes they will be
considered by the Director to be major modifications under Sec.
144.39.
Periodic review and revision of required plans and the ongoing
dialogue between owners or operators and Directors will address many of
the comments in support of periodic permit renewal, without the
associated time and expense of rewriting the entire permit. Instead,
today's final approach requires a close level of interaction between
owners or operators and Directors. It requires permits to be informed
with continually updated information, focuses resources on key issues,
and provides for public transparency and involvement when needed.
Periodic reevaluation of the AoR, along with reviews and updates to the
plans, will provide an equivalent level of review and attention to
address potential risks, while focusing time and resources on the most
important components of GS operations.
The iterative reviews and revisions of the various rule-required
plans and the underlying computational models will also provide
numerous opportunities for technical reassessments of the project.
These reviews will ensure that the owner or operator and the Director
have current knowledge of how the CO2 plume and pressure
front are behaving and afford them time to assess the information and
react appropriately to ensure protection of USDWs.
Transfer of permits: Today's final rule does not allow for
automatic transfer of a Class VI permit to a new owner or operator
(Sec. 144.38(b)). Given the unique nature of GS and the importance of
interaction between GS project owners or operators and permitting
authorities, the Agency believes that the Director should have an
opportunity to review the permit and determine whether any changes are
necessary at the time of the permit transfer, pursuant to requirements
at Sec. 144.38(a). If information about the GS project and existing
permit conditions are determined to be adequate, the permit review and
transfer may entail a minimal amount of new information and
administrative effort.
Area permits: Today's rule does not allow area permits for Class VI
wells (Sec. 144.33(a)(5)). Individual well permits are essential to
ensure that every Class VI well is constructed, operated, monitored,
plugged, and abandoned in a manner that protects USDWs from
endangerment. Individual permitting of wells maximizes opportunities
for the public to provide input on each well as it is brought into
service. This also ensures that existing wells that are converted or
re-permitted from other well classes (e.g., Class II EOR/EGR wells
converted to Class VI) are engineered and constructed to meet the
requirements at Sec. 146.86(a) and ensure protection of USDWs from
endangerment in lieu of requirements at Sec. 146.86(b) and Sec.
146.87(a).
[[Page 77275]]
While area permits allow for some administrative efficiency, this
efficiency can also be achieved through appropriately executed plans
for Class VI wells. For example, an owner or operator under Sec.
146.84(c)(1) must delineate the projected lateral and vertical movement
of the CO2 plume and formation fluids from the commencement
of injection activities until injection ceases. This delineation should
account for any future wells that the owner or operator plans to
construct in the AoR to ensure that the Director can consider all
anticipated injection and resultant pressure changes when evaluating
the plan and setting permit conditions. Similarly, testing and
monitoring plans should account for future injection wells to ensure
that ground water monitoring and CO2 plume and pressure
front tracking are planned appropriately. Through this iterative
planning and submission process, owners or operators and Directors can
accomplish multiple efficiencies: permits to construct Class VI wells
can be submitted and reviewed either separately or simultaneously, and
common, static components of the project can be identified and
incorporated into future permit applications, which would facilitate
submittal of data by the owner or operator and review and approval by
the Director of future wells in the same field.
Owners or operators and permitting authorities may also achieve
economies of scale by conducting the public process (e.g., noticing
wells; holding hearings) for several Class VI permits simultaneously.
This may improve efficiency and public understanding of how multiple
wells may interact in a given GS site. EPA also believes that requiring
separate permit applications for each well will ensure that the public
has an opportunity to provide input on each well in the field as it is
constructed or brought online.
As part of the EPA's adaptive rulemaking approach, the Agency will
collect information on early GS projects and may consider the use of
area permits in the future.
IV. Cost Analysis
Today's rulemaking finalizes regulations for the protection of
USDWs, but it does not require entities to sequester CO2.
The costs and benefits associated with protection of USDWs from
endangerment are the focus of this rule; however, those associated with
the mitigation of climate change are not directly attributable to this
rulemaking.
To calculate the costs and benefits of compliance for the final GS
Rule, 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 rule, based
on the fact that permits issued to early pilot projects included
requirements similar to those for Class I industrial wells.
The incremental costs of the rule include elements such as geologic
site characterization, well construction and operation, monitoring
equipment and procedures, well plugging, and post-injection site care
(monitoring). The benefits of this rulemaking include the decreased
risk of endangerment to USDWs and potentially a corresponding decrease
in health-related risks associated with contaminated USDWs.
The scope of the GS Rule Cost Analysis includes the full range of
activities associated with 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 timeframe of the analysis. The
scope of the cost analysis does not include capturing or purifying the
CO2, nor does it include transporting the CO2 to
the GS site. Some costs as highlighted in this section have changed
from the proposed rule based on cost updates or public comments
received.
The timeframe of the cost analysis was extended from 25 years in
the proposed rule to 50 years for the final rule. Although twice as
long as the timeframes commonly used in drinking water-related cost
analyses, EPA believes that 50 years reflects the fact that the full
lifecycle of GS projects is expected to be well beyond 25 years while
avoiding the extreme amount of uncertainty involved in projecting an
analysis across multiple generations. Costs attributed to this rule are
inclusive of GS projects begun during the 50 years of the analysis, and
all cost elements that occur during the 50-year timeframe are
discounted to present year values. The number of GS projects projected
to be implemented over the timeframe of the cost analysis (29) includes
pilot projects and other projects associated with regulations that are
in place today.\3\ EPA consulted directly with DOE and Regional
Partnerships and searched publicly available data to inform the
estimated number of projects. Again, EPA emphasizes that the rule does
not require anyone to undertake GS.
---------------------------------------------------------------------------
\3\ Note that although pilot projects are conducted on a small
scale, they are considered geologic sequestration demonstration
projects for a given site, not Class V experimental technology well
projects.
---------------------------------------------------------------------------
EPA recognizes that basing the analysis on 29 projects (consisting
of pilot projects and other projects) expected on the basis of
regulations in place today omits the incremental costs of applying
these requirements to additional projects that may result from future
changes in climate policy and that a much larger number of affected
projects (and thus higher costs) could result from such policy changes.
EPA has thus conducted several sensitivity analyses to provide
perspective on the incremental costs of the rule under possible future
climate policy scenarios. These are summarized in Section IV.A.2.b of
this preamble and discussed in greater detail in Cost Analysis for this
rule (see EPA, 2010d).
This section of the Preamble summarizes the results of the cost
analysis conducted for this rule. For details, see the Cost Analysis
for the Final GS Rule, which is included in the rule docket.
A. National Benefits and Costs of the Rule 4
---------------------------------------------------------------------------
\4\ 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 with the regulatory
alternative (RA) selected for the final rule. The Cost Analysis
includes a more comprehensive evaluation of risk and benefit tradeoffs
for all of the RAs considered for the final rule (see Chapter 2 of the
Cost Analysis for a description of each of the RAs). These evaluations
in the Cost Analysis include a nonquantitative analysis of the relative
risks of contamination to USDWs for the RAs under consideration. The
expected change in risk based on promulgation of the selected RA and
the potential nonquantified benefits of compliance with this RA are
also discussed.
a. Relative Risk Framework--Qualitative Analysis
Table IV-1 below presents the projected directional change in risk
of the selected RA relative to the baseline. As detailed in Chapter 5
in the Cost Analysis, the term ``baseline'' in the exhibit refers to
risks as they exist under the current UIC program regulations for Class
I industrial wells. The terms ``decrease'' and ``increase'' indicates
the change in risk relative to this baseline. The Agency has used best
professional judgment to qualitatively assess the relative risk
associated with each RA.
[[Page 77276]]
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 IV-1--Relative Risk of Regulatory Components for Selected RA
Versus the Current Regulations 5
------------------------------------------------------------------------
Direction of change in risk
Requirements for selected RA (relative to
baseline)
------------------------------------------------------------------------
1. Geologic Characterization
------------------------------------------------------------------------
Baseline
Identify a geologic system consisting of a Decrease.
receiving zone; trapping mechanism; and
confining system to allow injection at
planned rates and volumes.
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 and
storage reservoir.
Incremental Requirements under RA3
Perform detailed assessment of geologic,
hydrogeologic, geochemical and
geomechanical properties of proposed
site.
Identify additional zones above the
confining zone that will impede vertical
fluid movement (at Director's
discretion).
Collect seismic history data; identify and
evaluate faults and fractures.
------------------------------------------------------------------------
2. Area of Review (AoR) Study and Corrective Action
------------------------------------------------------------------------
Baseline
The AoR determined as either a \1/4\ mile Decrease.
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 a
risk to USDWs.
Incremental Requirements under RA3
Define the AoR using sophisticated
computational models based on site
specific data that accounts for
multiphase flow and the buoyancy of CO2.
Perform corrective action using materials
that are compatible with CO2.
Periodically reevaluate the AoR over the
life of the injection project.
------------------------------------------------------------------------
3. Injection Well Construction
------------------------------------------------------------------------
Baseline
The well must be cased and cemented to Decrease (enhanced well
prevent movement of fluids into or construction requirements);
between USDWs and to withstand the Increase (A waiver to inject
injected materials at the anticipated above the lowermost USDW in
pressure, temperature and other limited cases).
operational conditions. Wells must be
constructed to inject below the lowermost
USDW.
Incremental Requirements under RA3
Construct and cement wells with casing,
tubing, and packer that meet API or ASTM
International standards and are
compatible with CO2.
Cemented surface casing (base of the
lowermost USDW to surface) and long
string casing (cemented from injection
zone to surface) must be compatible with
fluids with which they may be expected to
come into contact.
(A waiver of the Class VI requirement that
projects inject below the lowermost USDW
may be permitted in limited cases.)
------------------------------------------------------------------------
4. Well Operation
------------------------------------------------------------------------
Baseline
Limit injection pressure to avoid Decrease.
initiating new fractures or propagating
existing fractures in the confining zone
adjacent to the USDWs.
Incremental Requirements under RA3
Limit injection pressure to less than the
fracture pressure of the injection
formation in any portion of the area
defined by the anticipated pressure
front. Equip injection wells with down-
hole shut-off systems.
------------------------------------------------------------------------
5. Mechanical Integrity Testing (MIT)
------------------------------------------------------------------------
Baseline
Demonstrate internal mechanical integrity, Decrease.
and conduct a pressure fall-off test
every 5 years.
Incremental Requirements under RA3
Continuously monitor injection pressure,
flow rate, injected volumes, and pressure
on the annulus between the tubing and the
long string casing. Demonstrate external
mechanical integrity annually, and
conduct casing inspection logs at the
discretion of the Director.
------------------------------------------------------------------------
6. Monitoring
------------------------------------------------------------------------
Baseline
Monitor the nature of injected fluids at a Decrease.
frequency sufficient to yield data
representative of their characteristics.
Conduct ground water monitoring within
the AoR (Director's discretion). Report
semi-annually on the characteristics of
injection fluids, injection pressure,
injection flow rate, injection volume and
annular pressure, and on the results of
MITs and groundwater monitoring.
[[Page 77277]]
Incremental Requirements under RA3
Develop, implement, and periodically
review a Testing and Monitoring plan for
the site. Monitor injectate; corrosion of
the well's tubular, mechanical and cement
components. Conduct pressure fall-off
testing; CO2 plume and pressure front
tracking; and ground water quality
monitoring.
Report operating and monitoring results
twice per year in operating reports,
unless the monthly MIT or other periodic
tests revealed operations were somehow
compromised, in which case 24 hour
notification is required.
------------------------------------------------------------------------
7. Well Plugging and Post-Injection Site Care (PISC)
------------------------------------------------------------------------
Baseline
Ensure that the well is in a state of Decrease.
static equilibrium and plugged using
approved methods. Plugs shall be tagged
and tested. Conduct PISC monitoring to
confirm that CO2 movement is limited to
intended zones.
Incremental Requirements under RA3
Flush the well with a buffer fluid,
determine bottom-hole reservoir pressure,
and perform a final external MIT. Develop
and implement a plan to conduct PISC
monitoring, (which may include pressure
monitoring, geophysical monitoring, and
geochemical monitoring in and above the
injection zone and the USDW). Following
the PISC monitoring (50 years), perform a
non-endangerment demonstration to ensure
no threat to USDWs and that no further
monitoring is necessary.
------------------------------------------------------------------------
8. Financial Responsibility
------------------------------------------------------------------------
Baseline
Demonstrate and maintain financial Decrease.
responsibility and resources to plug and
abandon the injection well.
Incremental Requirements under RA3
Demonstrate and maintain financial
responsibility for all needed corrective
action, emergency and remedial response,
and PISC and closure. Adjust the cost
estimates for these activities
periodically to account for inflation and
other conditions that may affect costs.
------------------------------------------------------------------------
9. Emergency and Remedial Response
------------------------------------------------------------------------
Baseline
No specific requirement under Baseline. Decrease.
Incremental Requirements under RA3
Develop and periodically review an
emergency and remedial response plan that
describes actions to be taken to address
events that may cause an endangerment to
a USDW during construction, operation and
PISC.
------------------------------------------------------------------------
Overall................................... Decrease.
------------------------------------------------------------------------
\5\ The activity baseline used for costing purposes in this analysis is
based on the UIC program Class I industrial waste disposal well
category because of the similarity of early CO2 sequestration permits
to the permits from that well class.
Note: Chapters 2 and 4 of the GS rule Cost Analysis provide
detail on the components of the regulatory alternatives considered
in this analysis and on the direction of change in risk associated
with them, respectively.
In considering the benefits of the GS rule, the direction of change
in risk compared to the baseline regulatory scenario was assessed for
each component of the four RAs considered. An overall assessment for
each alternative as a whole requires consideration of the relative
importance of the risk being mitigated by each component of the rule.
As shown in Table IV-1, EPA estimates that under the selected
alternative, RA3, risk will decrease relative to the baseline for each
of the nine components assessed.
b. Other Nonquantified Benefits
Finalization of this rule will result in direct benefits, that is,
protection of USDWs as is required of EPA under SDWA; and indirect
benefits, which are those protections afforded to entities as a by-
product of protecting USDWs. Indirect benefits are described 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 any
climate change mitigation are not included in the assessment.
2. National Cost Summary
a. Cost of the Selected RA
EPA estimated the incremental one-time, capital, and operations and
maintenance (O&M) costs associated with today's rulemaking. As Table
IV-2 shows, the total annualized incremental cost associated with the
selected RA is $38.1 million (as compared to $15.0 million for the
proposed rule) and $31.7 million (as compared to $15.6 million in the
proposed rule), using a 3-percent and 7-percent discount rate,
respectively. These costs are in addition to the baseline costs that
would be incurred if GS activities were instead subject to the current
rules for UIC Class I industrial wells. As can be seen from Table IV-2,
today's rule increases the costs of complying with UIC regulations for
these wells from approximately a baseline total of $70.2 million ($32.3
million in the proposed rule) to $108.3 million ($47.3 million in the
proposed rule) in annualized terms using a 3-percent discount rate,
which is an increase of 54 percent. EPA believes these increased costs
are needed to ensure the protection of UDWSs from endangerment. The
details of the costs associated with each RA are presented in the Cost
Analysis, along with a discussion of how EPA derived these estimates
(EPA, 2010d).
[[Page 77278]]
[GRAPHIC] [TIFF OMITTED] TP10DE10.091
Table IV-3 presents a breakout of the annualized incremental costs
of the selected RA by rule component using a 3-percent discount rate:
Monitoring activities account for approximately 49 percent
of the incremental regulatory costs. Most of this cost is for the
construction, operation, and maintenance of corrosion-resistant
monitoring wells. This cost 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 selected RA is
injection well operation, which accounts for approximately 22 percent
of the total incremental cost. This component ensures that the wells
operate within established parameters in the permit to prevent
unacceptable fluid movement.
Mechanical integrity testing accounts for approximately
6.8 percent of the cost. Continuous pressure monitoring is a key
component of decreasing risk because it provides an early warning that
a CO2 leak may have occurred and allows the owner or
operator to prevent compromises to well integrity.
Construction of Class VI wells using the corrosion-
resistant design and materials necessary to withstand exposure to
CO2 accounts for approximately 3.2 percent of the
incremental cost of the selected RA.
Geologic site characterization, which ensures that the
site geology is safe and appropriate for GS, accounts for approximately
12.1 percent of the incremental cost of the selected RA. Costs for this
component were determined using a site selection factor that accounts
for the expense of characterizing multiple sites prior to finding an
appropriate site.
Well plugging and post-injection site care activities,
which ensure that the injection well is properly closed and that the
geologic sequestration project no longer poses a risk to USDWs, account
for approximately 5.7 percent of the total incremental cost of RA 3.
AoR activities, which include modeling the AoR and
remediating wells in the AoR, account for approximately 1.0 percent of
the total incremental cost of RA3.
[[Page 77279]]
[GRAPHIC] [TIFF OMITTED] TP10DE10.092
b. Nonquantified Costs and Uncertainties in Cost Estimates
Should this rule somehow impede GS from happening, then the
opportunity costs of not capturing the benefits associated with GS
could be attributed to this regulation; however, the Agency has tried
to develop a rule that balances risk with practicability, site specific
flexibility and economic considerations and believes the probability of
such impedance is low. This rule ensures protection of USDWs from
endangerment associated with GS activities while also providing
regulatory certainty to industry and permitting authorities and an
increased understanding of GS through public participation and
outreach. Thus, EPA believes the rule will not impede GS from happening
and has not quantified such risk.
Uncertainties in the analysis are inherent in some of the basic
assumptions as well as some detailed cost items. Uncertainties related
to economic trends, the future rate of CCS deployment, and GS
implementation choices may affect three basic assumptions on which the
analysis is based: (1) The estimated number of projects that will be
affected by the GS rule; (2) the labor rates applied; and (3) the
estimated number of monitoring wells to be constructed per square mile
of the AoR to adequately monitor in a given geologic setting.
First, the number of projects that will deploy from 2011 through
2060 may be significantly underestimated in this analysis given the
uncertainty in future deployment of this technology. The current
baseline assumption is that 29 projects (changed from 22 projects in
the proposed rule) will deploy during the 50-year period (changed from
25 years in the proposed rule), as described in Chapter 3 of the Cost
Analysis. To address the uncertainty inherent in projecting the GS
baseline, the final rule cost analysis also presents sensitivity
analyses that considers 5 and 54 projects as the lower and upper bound
project numbers to be consistent with the Mandatory Reporting of
Greenhouse Gases: injection and Geologic Sequestration of
CO2 rule (subpart RR). EPA developed this rule
simultaneously with subpart RR to ensure coordination of requirements
and costs between the two rules. The sensitivity analysis numbers (5
and 54 projects) are based on projected deployment highlighted in the
presidential memorandum establishing the CCS Task Force and an EPA
legislative analysis model of deployment under the American Power Act,
respectively.
Second, the labor rate adopted for each of the labor categories for
owners or operators described in Section 5.2.1 of the Cost Analysis
(i.e., geoscientist, mining and geological engineer) may be
underestimated. The labor rates used in the Cost Analysis are based on
current industry costs; therefore, the level and pace of price
responses as the level of GS deployment increases represents a
potentially uncertain component in the cost estimates. The practice of
CO2 injection represents an activity that, although already
practiced widely in some contexts (i.e., ER), has the potential to
expand rapidly in the coming years. This expansion may be exponential
under certain climate legislative scenarios, which may lead to
shortages in labor and equipment in the short term and result in rapid
cost escalation for many of the cost components discussed in the Cost
Analysis. However, based on current research, potential increases in
costs due to increased deployment rates and an associated rise in
demand for labor or services in the field are not expected to cause a
rapid, wide-scale increase in deployment. To address the potential
underestimate of labor rates in the event that rapid deployment does
drive up costs, EPA conducted sensitivity analyses using labor rates
that were 50% higher than those used in the primary analysis. EPA found
that the 50% increase in industry labor rates results in annualized
incremental rule costs of $38.6 million based on a 3 percent discount
rate, an approximately 1% increase in costs from the primary analysis.
Third, for the purpose of estimating national costs, the Agency
assumes one monitoring well above the injection zone per two square
miles of AoR; for monitoring wells into the injection zone, the Agency
assumes one monitoring well per four square miles. EPA assumes
monitoring wells into the injection zone will also be used to sample
above the injection zone. However, the Agency recognizes that operators
and primacy agency Directors may choose more or fewer monitoring
[[Page 77280]]
wells depending on project site characteristics. Because the monitoring
wells and associated costs represent a significant component of the
cost analysis, the Agency acknowledges that this factor may be
significant in the overall uncertainty of the cost analysis. To address
this source of uncertainty, the Agency conducted sensitivity analyses
based on alternative estimates of 25 percent more and 25 percent fewer
monitoring wells than the number assumed for the primary analysis.
These analyses resulted in annualized incremental rule costs of
approximately $43.1 million and $33.0 million respectively, a 13
percent increase or decrease from the primary analysis results of $38.1
million at a 3 percent discount rate.
Additional uncertainties correspond more directly to specific
assumptions made in constructing the cost model. If the assumptions for
such items are incorrect, there may be significant cost implications
outside of the general price level uncertainties discussed above. These
cost items are described in Section 5.9.2 of the Cost Analysis.
EPA requested and received comments on the cost analysis presented
in the preamble of the proposed rule. One commenter expressed concern
that EPA overstated risks to USDWs, which may discourage investment in
CCS. EPA notes that the risks have been discussed as low, based on the
rule requirements and the redundancy in those requirements. One
commenter requested that costs be estimated for a range of projects,
rather than only the number of projects estimated in the cost analysis.
EPA notes that the cost analysis for the final rule presents
sensitivity analyses that consider 5 and 54 projects as the lower and
upper bound number of projects deployed which is comparable with the
Subpart RR analysis. The sensitivity analyses are intended to further
explore the implications of alternative climate policy scenarios.
EPA received comments on the proposal cost analysis section that
suggested that various estimated costs were too high, too low, or
absent. EPA clarifies that cost estimates are presented in incremental
terms. For this reason, costs may seem lower or less comprehensive than
expected. However, EPA increased some costs, such as labor rates, in
response to comments. Using industry survey data from the American
Association of Petroleum Geologists and the Society for Petroleum
Engineers, as presented in the Cost Analysis, EPA increased the
estimated labor rates significantly from the Bureau of Labor Statistics
estimates used in the analysis for the proposed rule. The updated rates
(weighted by 1.6 for overhead) in the analysis for the final rule are
$110.62 and $107.23 in 2008$ for engineers and geologists,
respectively. These correspond approximately to annual salaries of
$143,800 and $139,400 and represent an approximately 115 percent and a
one percent increase, respectively, for engineers and geologists from
the proposed rule analysis. For more details please see the Cost
Analysis for the Final GS Rule (USEPA, 2010d).
Lastly, many commenters believed that an assumption of three
monitoring wells per GS injection well was too high or too low a ratio,
or should be modeled for a range of values. EPA changed the algorithm
for calculating the number of monitoring wells to be based on the AoR,
instead of the number of injection wells. For a representative saline
project of approximately 23.3 square miles, EPA assumed 12 monitoring
wells (six above the injection zone, and six into the injection zone),
which EPA understands will be an overestimate in some cases and an
underestimate in others. Because EPA recognizes the inherent
uncertainty in this assumption, the cost analysis for the proposed rule
presented and for the final rule presents a sensitivity analysis based
on alternative estimates of 25 percent more and 25 percent fewer
monitoring wells than the number assumed for the primary analysis.
c. Supplementary Cost and Uncertainties in Cost Estimates
To better establish the context in which to evaluate the cost
analysis for this rule, EPA considers three types of costs that are not
accounted for explicitly for this rule: (1) Costs that are incurred
beyond the 50-year timeframe of the analysis, (2) costs that could
arise due to a higher rate of deployment of CCS in the future in
response to climate change legislation, and (3) overall costs of CCS
and their relationship to the proportion of such costs attributable to
the requirements. Because GS is in the early phase of development, and
given the significant interest in research, development, and eventual
commercialization of CCS, EPA provides a preliminary discussion of the
potential significance of these costs below.
The cost analysis for this rule estimates costs that EPA
anticipates will be incurred during a 50-year timeframe beginning with
rule promulgation.\6\ When analyzing costs for a commercial-size saline
formation sequestration project that begins in year one of the cost
analysis, EPA assumes that the first year is a pre-construction and
construction period, followed by 40 years of injection and then either
10, 50, or 100 years of PISC as indicated in the cost analysis for the
RAs considered. Given the 50-year timeframe (changed from 25 years in
the proposed rule) of the analysis, the first nine years (changed from
four years in proposed rule) of the PISC period would be captured in
the cost analysis for a project beginning in year one, and fewer or no
years of PISC for a project beginning later in the 50-year analytical
timeframe would be included. EPA estimates that the incremental present
value sequestration costs above the baseline costs incurred for one
representative large deep saline project within the 50-year timeframe
of the cost analysis are approximately $1.26/metric tonne
CO2. These costs over the full lifetime of the sequestration
project are estimated to be $1.40/metric tonne CO2. Thus the
50-year timeframe (changed from 25 years in proposed rule) captures
approximately 90 percent (changed from 75 percent in the proposed rule)
of the present value lifetime incremental costs associated with
implementing this rule. EPA notes, however, that the longer time
horizon over which costs are estimated inherently introduces increasing
amounts of uncertainty into those estimates, and that the relatively
low percentage share of these costs as a fraction of the total costs is
significantly influenced by the long horizon (greater than 50 years)
over which they are discounted.
---------------------------------------------------------------------------
\6\ A detailed discussion of the timeframe over which the costs
of the final requirements were estimated can be found in the Cost
Analysis. The 50 years of costs are calculated in terms of their
present value (2008$) and then annualized over a 25-year period for
a more consistent comparison to other regulations.
---------------------------------------------------------------------------
The cost analysis assumes that Class VI well owners or operators
will inject approximately 1.0 billion metric tons (or 1.0 Petagram, Pg)
of CO2 cumulatively over the next 50 years.\7\ The start
years of these projects, for both pilot and large-scale saline, are
staggered over the first seven years of the period of analysis.\8\
Based on the assumed deployment schedule, the analysis captures the
full injection periods for approximately 10 large scale saline projects
(with an injection period of 40 years) and 2 pilot saline projects
(with an injection period of four years), and for 14 ER projects (with
an assumed injection period of 10 years), which are
[[Page 77281]]
in oil and gas reservoirs. The analysis assumes that 10 percent of
projects initiated will include waiver applications, and that 50
percent of those applications will be approved, while the other 50
percent of waiver applicants are removed from the baseline. The
analysis also assumes that five percent of project permits for the
initial baseline estimate of 29 projects will not be approved for
geological or mechanical reasons.\9\ While the baseline injection
amount represents a significant step towards demonstrating the
feasibility of CCS on an annual basis, it represents a small amount of
current CO2 emissions in the United States (approximately
one percent).
---------------------------------------------------------------------------
\7\ A more detailed discussion of these projects can be found in
the Cost Analysis.
\8\ A detailed table of the scheduled deployment of projects
assumed in the baseline over the 50-year timeframe can be found in
Exhibit 3.1 of the Cost Analysis.
\9\ Of the 29 projects that compose the initial baseline, a
total of 10 percent, or approximately 3 projects, will not be
approved based on their permit or waiver applications; costs for
compiling the applications and reviewing them are included in the
cost analysis, but no further costs are incurred for those projects
that do not get approved. EPA recognizes that this may omit
opportunity costs of projects that do not go forward.
---------------------------------------------------------------------------
The U.S. fleet of 1,493 coal-fired power generators emits 1.932 Pg
CO2 equivalent per year. The technical or economic viability
of retrofitting these or other industrial facilities with CCS is not
the subject of this rulemaking. However, if some percentage of these
facilities undertook CCS and used GS, they (or the owner or operator of
the Class VI injection wells) would be subject to the UIC requirements.
For example, if 25 percent of these facilities undertook CCS (assuming
a 90 percent capture rate and the incremental rule costs outlined in
Table IV-4) the annualized incremental sequestration costs associated
with meeting the Class VI requirements would be on the order of $546
million. Similarly, if 100 percent of these plants undertook CCS, the
annualized incremental costs would be on the order of $2.2 billion,
although it is unlikely that all coal plants would deploy CCS
simultaneously. These preliminary cost estimates represent the
annualized incremental cost of meeting the additional sequestration
requirements in the rule, which would be incurred over the lifetime of
the sequestration projects, assuming that all sequestration projects
begin in the same year. These cost estimates were not generated from a
full economic analysis or included in the cost analysis for this rule,
due to the uncertainty of what percentage, if any, of such facilities
will deploy CCS in the future. However, based on current research, the
uncertainty in labor or service costs is not likely to contribute
significantly as a rapid, wide-scale increase in deployment is not
expected.\10\ Therefore, the cost estimates presented represent a
sensitivity analysis of the potential costs, assuming that 25 percent
or 100 percent of all plants undertake CCS beginning in the same year,
and do not take into consideration CCS deployment rates and project-
specific costs. Actual annualized costs incurred as CCS deploys in the
future could be higher or lower, depending on a number of factors,
including deployment rates, capital and labor cost trends, and the
shape of the learning curve among industry and State/Federal operators.
---------------------------------------------------------------------------
\10\ Potential increase in costs due to increased deployment
rates and an associated rise in demand for labor or services in the
field were considered in terms of the uncertainty this contributes
to the analysis results. However, a rapid wide scale increase in
deployment is not expected, according to the Joint Global Change
Research Institute (Dooley, 2010), therefore the uncertainty in
labor or services costs does not contribute significantly to the
uncertainty in this cost analysis.
---------------------------------------------------------------------------
Based on current literature, sequestration costs are expected to be
a small component of total CCS project costs. Table IV-4 shows example
total annualized CCS project costs broken down by capture,
transportation, and sequestration components. The largest component of
total CCS project costs is the cost of capturing CO2
($42.90/metric tonne CO2 for capture from an integrated
gasification combined cycle power plant.\11\) Transportation costs vary
widely depending on the distance from emission source to sequestration
site, but EPA uses a long-term average estimate of $4.60/metric tonne
CO2.\12\ EPA estimates total sequestration costs for a
commercial-size deep saline project to be approximately $3.80/metric
tonne CO2, of which approximately $1.40/metric tonne
CO2 is attributable to complying with requirements of this
rule (including PISC). Based on the project costs outlined in Table IV-
4, the requirements amount to approximately 2.7 percent of the total
CCS project costs.
---------------------------------------------------------------------------
\11\ Cost and Performance Baseline for Fossil Energy Plants,
Vol. 1, DOE/NETL-2007/1281, May 2007.
\12\ Costs of capture from the ``Strategic Analysis of the
Global Status of Carbon Capture and Storage Report 2: Economic
assessment of carbon capture and storage technologies. Final
Report,'' 2009, Worley Parsons for Global CCS Institute. Costs of
transport from ``Developing a Pipeline Infrastructure for
CO2 Capture and Storage: Issues and Challenges,'' Feb.
2009, INGAA Foundation.
---------------------------------------------------------------------------
[[Page 77282]]
[GRAPHIC] [TIFF OMITTED] TP10DE10.093
B. Comparison of Benefits and Costs of RAs Considered
1. Costs Relative to Benefits; Maximizing Net Social Benefits
EPA developed a relative risk analysis in place of a comparison of
quantified benefits (a direct numerical comparison of costs to
benefits) because GS is a new technology and data collection on the
potential effects of GS on USDWs are ongoing. Costs can only be
compared to qualitative relative risks as discussed in section IV.A.1.
Compared to the baseline, RA3 provides greater protection to USDWs
because it is specifically tailored to GS injection activities. The
current regulatory requirements do not specifically consider the
injection of a buoyant, corrosive (in the presence of water) fluid. In
particular, RA3 includes increased monitoring requirements that provide
the amount of protection the Agency estimates is necessary for USDWs.
As described in section IV.A. (National Benefits and Costs of the
Rule), monitoring requirements account for 49 percent of the
incremental regulatory costs, of which 74 percent is incurred for the
construction, operation, and maintenance of monitoring wells, and the
other 26 percent for tracking of the plume and pressure front through
complex modeling at a minimum of every five years for all operators and
for monitoring for CO2 leakage. Public awareness of these
protective measures would be expected to enhance public acceptance of
GS.
EPA also compared RA1 and RA2 to the baseline (discussed in the
proposed rule of July 2008). RA1 does not contain specific requirements
but requires operators to meet a performance standard regarding
protection of USDWs. RA2 is similar to the Class II UIC requirements,
with some additional construction and PISC requirements. See the Cost
Analysis (USEPA, 2010d) for a more detailed description. RA1 and RA2 do
not provide the specific safeguards against CO2 migration
that RA3 does because of a significantly greater amount of discretion
allowed to Directors and operators for interpreting requirements, and
less stringent requirements for some compliance activities. Only RA3
and RA4 require the periodic complex modeling exercise for tracking the
plume, for example. RA4 provides greater safeguards against
CO2 migration, but at a much higher cost.
2. Cost Effectiveness and Incremental Net Benefits
RA1 and RA2 provide lower costs than RA3 but at increased levels of
risk to USDWs. Although RA4 has more stringent requirements, EPA does
not believe that the increased requirements and the increased costs are
necessary to provide protection to USDWs. Therefore EPA believes that
RA3 is the most appropriate alternative.
C. Conclusions
RA3 provides a high level of protection to USDWs overlying and
underlying GS CO2 injection zones. It does so at lower costs
than the more stringent RA4 while providing significantly more
protection than RA1 or RA2. Therefore EPA has selected RA3 for the
final GS Rule.
V. Statutory and Executive Order Review
A. Executive Order 12866: Regulatory Planning and Review
Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993),
this action is a ``significant regulatory action.'' Accordingly, EPA
submitted this action to the Office of Management and Budget (OMB) for
review under EO 12866 and any changes made in response to OMB
recommendations have been documented in the docket for this action.
B. Paperwork Reduction Act (PRA)
The information collection requirements in this rule will be
submitted for approval to the Office of Management and Budget (OMB)
under the Paperwork Reduction Act (PRA), 44 U.S.C. 3501 et seq. The
information collection requirements are not enforceable until OMB
approves them.
The information collected as a result of this rule will allow EPA
and State permitting authorities to review geologic information about a
proposed injection project to evaluate its suitability for safe and
effective GS. It also allows the Agency to fulfill the requirements of
the UIC program to verify throughout the life of the injection project
that protective requirements are in place and that USDWs are protected.
The collection requirements are mandatory under the SDWA (42 U.S.C.
300h et seq.).
For the first three years after publication of the final rule in
the Federal Register, the major information requirements apply to a
total of 38 respondents, for an average of 12.6 respondents per year.
The total
[[Page 77283]]
incremental burden (for owners or operators, permitting authorities,
and the Agency) associated with the change in moving from the
information requirements of the UIC program for Class I non-hazardous
wells (baseline) to the selected alternative under the GS Rule over the
three years covered by the Information Collection Request (ICR) for the
Geologic Sequestration Rule is 53,740 hours, for an average of 17,913
hours per year. The total incremental reporting and recordkeeping cost
over the three year clearance period is $36.9 million, for an average
of $12.3 million per year (simple average over three years). The
average burden per response (i.e., the amount of time needed for each
activity that requires a collection of information) is 423 hours; the
average cost per response is $290,695. The collection requirements are
mandatory under SDWA (42 U.S.C. 3501 et seq.). Details on the
calculation of the rule information collection burden and costs can be
found in the ICR (USEPA, 2010e) and Chapter 5 of the Cost Analysis
(USEPA, 2010d). A summary of the burden and costs of the collection is
presented in Exhibit V-1.
[GRAPHIC] [TIFF OMITTED] TP10DE10.094
An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations in 40 CFR are listed in 40 CFR part 9. In addition, EPA is
amending the table in 40 CFR part 9 of currently approved OMB control
numbers for various regulations to list the regulatory citations for
the information requirements contained in this final rule.
C. Regulatory Flexibility Act (RFA)
The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedures Act or any other statute unless the agency certifies that
the rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of today's rule on small
entities, small entity is defined as: (1) A small business primarily
engaged in the generation, transmission, and/or distribution of
electric energy for sale as defined by North American Industry
Classification System (NAICS) codes 221111, 221112, 221113, 221119,
221121, 221122 with total electric output for the preceding fiscal year
that did not exceed 4 million megawatt hours; (2) a small business
primarily engaged in petroleum production as defined by NAICS code
324110 with fewer than 1,500 employees and less than 125,000 barrels
per calendar day in total Operable Atmospheric Crude Oil Distillation
capacity, as specified for government procurement purposes (capacity
includes owned or leased facilities as well as facilities under a
processing agreement or an arrangement such as an exchange agreement or
a throughput); (3) a small governmental jurisdiction that is a
government of a city, county, town, school district or special district
with a population of less than 50,000; and (4) a small organization
that is any not-for-profit enterprise which is independently owned and
operated and is not dominant in its field. The small entity definitions
for commercial operations focus on the electricity and oil and gas
sectors because these are the sectors most likely to deploy GS.
After considering the economic impacts of today's final rule on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. This rule
does not impose any requirements on small entities.
Furthermore, GS is a technologically complex activity, the cost of
which is anticipated to be prohibitive to small entities. Therefore it
is anticipated small entities would not elect to sequester
CO2 via injection wells, and thus the rule will not have any
impact on them.
D. Unfunded Mandates Reform Act (UMRA)
This rule does not contain a Federal mandate that may result in
expenditures of $100 million or more for State, local, and tribal
governments, in the aggregate, or the private sector in any one year.
The total annual incremental costs estimated for the implementation of
this rule are well under $100 million, resulting in expenditures for
the entity groupings required under an UMRA analysis that also fall far
below the $100 million per year threshold. Thus, this rule is not
subject to the requirements of sections 202 or 205 of UMRA.
This rule is also not subject to the requirements of section 203 of
UMRA because it contains no regulatory requirements that might
significantly or uniquely affect small governments. Government
responsibilities for oversight and implementation of this rule reside
with State or Federal agencies and not with small governments.
E. Executive Order 13132: Federalism
Under section 6(b) of Executive Order 13132, EPA may not issue an
action that has federalism implications, that imposes substantial
direct compliance costs, and that is not required by statute, unless
the Federal government provides
[[Page 77284]]
the funds necessary to pay the direct compliance costs incurred by
State and Local governments, or EPA consults with State and Local
officials early in the process of developing the proposed action. In
addition, under section 6(c) of Executive Order 13132, EPA may not
issue an action that has federalism implications and that preempts
State law, unless the Agency consults with State and Local officials
early in the process of developing the proposed action.
EPA concluded that today's action does not have federalism
implications. This rule will not impose substantial direct compliance
costs on State or Local governments, nor does EPA anticipate that it
will preempt State law. Thus, the requirements of sections 6(b) and
6(c) of the Executive Order do not apply to this action.
Consistent with EPA policy, EPA nonetheless consulted with
representatives of State and local governments early in the process of
developing the proposed action to permit them to have meaningful and
timely input into its development. Representatives included the
National Governors' Association, the National Conference of State
Legislatures, the Council of State Governments, the National League of
Cities, the U.S. Conference of Mayors, the National Association of
Counties, the International City/County Management Association, the
National Association of Towns and Townships, and the County Executives
of America. In the spirit of Executive Order 13132, and consistent with
EPA policy to promote communications between EPA and State and local
governments, EPA specifically solicited comment on the proposed action
from State and local officials. See section II of the Preamble for more
details on consultation with State and local officials.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
Subject to the Executive Order 13175 (65 FR 67249, November 9,
2000) EPA may not issue a regulation that has Tribal implications, that
imposes substantial direct compliance costs, and that is not required
by statute, unless the Federal government provides the funds necessary
to pay the direct compliance costs incurred by Tribal governments, or
EPA consults with Tribal officials early in the process of developing
the proposed regulation and develops a Tribal summary impact statement.
EPA has concluded that this action may have Tribal implications.
However, it will neither impose substantial direct compliance costs on
Tribal governments, nor preempt Tribal law. Indian Tribes may
voluntarily apply for primary enforcement responsibility to regulate
the UIC program in lands under their jurisdiction (See section II.G for
more details on primacy). Currently, two Tribes have received primacy
for the UIC program under section 1425 of the SDWA since the
publication of the proposed rule. EPA is responsible for implementing
the UIC program in the event that States or Tribes do not seek primary
enforcement responsibility. EPA clarifies that regardless of whether
Tribes have UIC program primacy, the rule protects USDWs from
contamination and therefore protects all populations from adverse
health effects related to potential USDW contamination.
EPA consulted with Tribal officials early in the process of
developing this regulation to permit them to have meaningful and timely
input into its development. A summary of the Tribal consultation calls
are included in the docket for the GS rulemaking. See section II.E.3
for more information on the details of the Tribal consultation process.
As required by section 7(a), EPA's Tribal Consultation Official has
certified that the requirements of the Executive Order have been met in
a meaningful and timely manner. A copy of the certification is included
in the docket for this action.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
This action is not subject to EO 13045 (62 FR 19885, April 23,
1997) because it is not economically significant as defined by EO 12866
and because the Agency does not believe the environmental health risks
or safety risks addressed by this action present a disproportionate
risk to children. Today's rule does not require or provide incentive
for firms to engage in GS, however, it does protect USDWs from
potential negative impacts from GS of CO2 should a firm
decide to undertake such a project. Health and risk assessments related
to GS of CO2 and its effects on humans and the environment
are presented in the Vulnerability Evaluation Framework for Geologic
Sequestration of Carbon Dioxide (USEPA, 2008b). Additionally, EPA notes
that it is funding and monitoring research related to the potential for
USDW contamination associated with GS projects. Much of this research
focuses on potential exceedances of drinking water standards (as
suggested), which were developed by EPA and take into account impacts
on children. Please see section II of this Preamble for more details on
this research.
H. Executive Order 13211: Actions That Significantly Affect Energy
Supply, Distribution, or Use
This action is not a ``significant energy action'' as defined in
Executive Order 13211 (66 FR 28355 (May 22, 2001)), because it is not
likely to have a significant adverse effect on the supply,
distribution, or use of energy. The higher degree of regulatory
certainty and clarity in the permitting process may, in fact, have a
positive effect on the energy sector. Specifically, if climate change
legislation that imposes caps or taxes on CO2 emissions is
passed in the future, energy generation firms and other CO2
producing industries will have an economic incentive to reduce
emissions, and this rule will provide regulatory certainty in
determining how best to meet any new requirements (for example, by
maintaining or increasing production while staying within the emissions
cap or avoiding some carbon taxes). The rule may allow some firms to
extend the life of their existing capital investment in plant machinery
or plant processes.
I. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law 104-113, 12(d) (15 U.S.C. 272 note)
directs EPA to use voluntary consensus standards in its regulatory
activities unless to do so would be inconsistent with applicable law or
otherwise impractical. Voluntary consensus standards are technical
standards (e.g., materials specifications, test methods, sampling
procedures, and business practices) that are developed or adopted by
voluntary consensus standards bodies. NTTAA directs EPA to provide
Congress, through OMB, explanations when the Agency decides not to use
available and applicable voluntary consensus standards.
This rulemaking involves environmental monitoring or measurement.
Consistent with the Agency's Performance Based Measurement System
(PBMS), EPA has decided not to require the use of specific, prescribed
analytic methods. Rather, the rule will allow the use of any method
that meets the performance criteria. The PBMS approach is intended to
be more flexible and cost-effective for the regulated community; it is
also intended to encourage innovation in analytical technology and
improved
[[Page 77285]]
data quality. While EPA is not precluding the use of any method,
whether it constitutes a voluntary consensus standard or not, as long
as it meets the performance criteria specified, the PBMS approach is
fully consistent with the use of voluntary consensus standards, as such
standards are generally designed to address the same types of criteria
required by PBMS.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629; February 16, 1994) establishes
Federal executive policy on environmental justice. Its main provision
directs Federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
EPA has determined that this final rule will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it increases the
level of environmental protection for all affected populations.
Existing electric power generation plants that burn fossil fuels may be
more prevalent in areas with higher percentages of people who are
minorities or have lower incomes on average, but it is hard to predict
where new plants with CCS will be built. EPA is developing guidance for
UIC Directors that places emphasis on considering the potential impact
of any Class VI permits on communities (such as minority and low income
populations) when evaluating Class VI injection well permit
applications, as well as provides suggestions and tools for targeted
outreach to ensure more meaningful public input and participation from
the most affected communities during the permit evaluation and approval
process.
This rule does not require that GS be undertaken; but does require
that if it is undertaken, operators will conduct the activity in such a
way as to protect USDWs from endangerment caused by CO2.
Additionally, this rule will ensure that all areas of the United States
are subject to the same minimum Federal requirements for protection of
USDWs from endangerment from GS. Additional detail regarding the
potential risk of the rule is presented in the Vulnerability Evaluation
Framework for Geologic Sequestration of Carbon Dioxide (USEPA, 2008b).
K. Congressional Review Act
The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
United States prior to publication of the rule in the Federal Register.
A Major rule cannot take effect until 60 days after it is published in
the Federal Register. This action is not a ``major rule'' as defined by
5 U.S.C. 804(2). This rule will be effective January 10, 2011.
VI. References
Benson. 2008. Multi-Phase Flow and Trapping of CO2 in
Saline Aquifers. Sally M. Benson, SPE, Stanford University.
Copyright 2008, Offshore Technology Conference.
Birkholzer, J., T. Apps, L. Zheng, Y. Zhang, T. Xu, and C.F. Tsang.
2008a. Research Project on CO2 Geological Storage and
Groundwater Resources: Water Quality Effects Caused by
CO2 Intrusion into Shallow Groundwater. LBNL paper
LBNL-1251E. http://repositories.cdlib.org/lbnl/LBNL-1251E.
Birkholzer, J., Zhou, Q., Zhang, K., Jordan, P., Rutqvist, J., and
C.F. Tsang. 2008b. Research Project on CO2 Geological
Storage and Groundwater Resources: Large-Scale Hydrological
Evaluation and Modeling of the Impact on Groundwater Systems. NETL
Project Annual Report, October 1, 2007 to September 30, 2008.
BLM. 2009. Framework for Geological Carbon Sequestration on Public
Land.
Celia, M.A., S. Bachu, J.M. Nordbotten, S.E. Gasda, and H.K. Dahle.
2004. Quantitative Estimation of CO2 Leakage from
Geological Storage: Analytical Models, Numerical Models, and Data
Needs. p. 663-671. In M. Wilson et al. (ed.) Proc. Int. Conf. on
Greenhouse Gas Control Technologies, 7th, Vancouver, BC, Canada. 5-9
Sept. 2004. Vol. 1. Elsevier Science, Amsterdam.
DOE NETL. 2007. Carbon Sequestration Atlas of the U.S. and Canada.
U.S. Department of Energy, Office of Fossil Energy, National Energy
Technology Laboratory. March 2007.
DOE NETL. 2008. Carbon Sequestration Atlas of the United States and
Canada (Atlas II). Second Edition. National Energy Technology
Laboratory, Pittsburgh, PA, USA.
Dooley, J.J., R.T. Dahowski, C.L. Davidson. 2008. On the Long-Term
Average Cost of CO2 Transport and Storage, Pacific
Northwest National Laboratory, PNNL-17389.
Dooley, J., C. Davidson, and R. Dahowski. 2009. An Assessment of the
Commercial Availability of Carbon Dioxide Capture and Storage
Technologies as of June 2009. Joint Global Change Research
Institute. Pacific Northwest National Laboratory. PNNL-18520.
Duncan, I.J., J.P. Nicot, and J.W. Choi. 2009. Risk Assessment for
Future CO2 Sequestration Projects Based on CO2
Enhanced Oil Recovery in the U.S. Energy Procedia 1(1): 2037-2042.
Energy Information Administration (EIA). 2009. Annual Energy Review,
2008.
EPRI. 1999. Enhanced Oil Recovery Scoping Study. Report TR-113836.
GAO. 2008. Climate Change--Federal Actions Will Greatly Affect the
Viability of Carbon Capture and Storage as a Key Mitigation Option.
GAO-08-1080.
GAO. 2010. Climate Change: A Coordinated Strategy Could Focus
Federal Geoengineering Research and Inform Governance Efforts. GAO-
10-903.
Holloway, S., J. Pearce, V. Hards, T. Ohsumi, and J. Gale. 2007.
Natural Emissions of CO2 from the Geosphere and their
Bearing on the Geological Storage of Carbon Dioxide. Energy 32:
1194-1201.
IEA. 2003. Acid Gas Injection: A Study of Existing Operations. Phase
1: Final Report.
IEA. 2008. CO2 Capture and Storage: A Key Abatement
Option. Energy Technology Analysis. Paris: IEA/OECD, 2008.
IPCC. 2005. IPCC Special Report on Carbon Dioxide Capture and
Storage. Prepared by Working Group III of the Intergovernmental
Panel on Climate Change. Metz, B., O. Davidson, H.C. de Coninck, M.
Loos, and L.A. Meyer (eds.). New York: Cambridge University Press.
IRS. 2009. Internal Revenue Service (IRS) Guidance for Tax
Incentives for GS Projects 2009-44 IRB http://www.irs.gov/irb/2009-44_IRB/ar11.html#d0e1860.
Julian, J.Y., G.E. King, J.E. Johns, J.K. Sack, and D.B. Robertson.
2007. Detecting Ultra-Small Leaks with Ultrasonic Leak Detection-
Case Histories from the North Slope, Alaska. Presented at
International Oil Conference and Exhibition, 27-30 June, Veracruz,
Mexico. Society of Petroleum Engineers. Paper Number 108906-MS.
Klusman, R.W. 2003. Evaluation of Leakage Potential from a Carbon
Dioxide EOR/Sequestration Project. Energy Conversion and Management
44: 1921-1940.
Oldenburg, C.M., K. Pruess, and S.M. Benson. 2001. Process Modeling
of CO2 Injection into Natural Gas Reservoirs for Carbon
Sequestration and Enhanced Gas Recovery. Energy and Fuels 15: 293-
298.
Oil and Gas Journal. 2008. Enhanced Oil Recovery Survey. April 21,
2008, p. 41-59.
Schnaar, G., and D.C. Digiulio. 2009. Computational Modeling of the
Geologic Sequestration of Carbon Dioxide. Vadose Zone J. 8: 389-403.
Skinner, L. 2003. CO2 Blowouts: An Emerging Problem.
World Oil. 224(1).
Somaschini, G., J. Lovell, H. Abdullah, B. Chariyev, P. Singh, and
F. Arachman. 2009. Subsea Deployment of Instrumented Sand Screens in
High-Rate Gas Wells. Presented at SPE Annual Technical Conference
and Exhibition, 4-7 October 2009, New Orleans,
[[Page 77286]]
Louisiana. Society of Petroleum Engineers. Paper Number 125047-MS.
USEPA. 2001. Class I Underground Injection Control Program: Study of
the Risks Associated with Class I Underground Injection Wells.
USEPA. 2007. Using the Class V Experimental Technology Well
Classification for Pilot Carbon Geologic Sequestration Projects--
Underground Injection Control Program Guidance (UICPG 83).
March 2007.
USEPA. 2008a. Climate Change--Climate Economics. Economic Analyses.
Updated May 7, 2008. http://www.epa.gov/climatechange/economics/economicanalyses.html.
USEPA. 2008b. Vulnerability Evaluation Framework for Geologic
Sequestration of Carbon Dioxide.
USEPA. 2010. Climate Change Science Facts. 430-10-F-002.
USEPA. 2010a. International Geologic Sequestration Efforts: An
Overview of the Sleipner, Weyburn, and In Salah Projects and Summary
of International Regulatory Developments. 816-R10-011.
USEPA. 2010b. Drinking Water Treatment Considerations: Water
Quality, Carbon Dioxide Concentration, and Geologic Sequestration
Projects. 816-R10-014.
USEPA. 2010c. Technologies Available to Address Induced Faults and
Fractures: Considerations for GS Sites. 816-R10-0018.
USEPA. 2010d. Cost Analysis for the Federal Requirements Under the
Underground Injection Control Program for Carbon Dioxide Geologic
Sequestration Wells (Final GS Rule). 816-R10-013.
USEPA. 2010e. Information Collection Request for the Federal
Requirements Under the Underground Injection Control Program for
Carbon Dioxide Geologic Sequestration. 816-R10-012.
USEPA. 2010f. EPA's June 2010 American Power Act Analysis. http://www.epa.gov/climatechange/economics/economicanalyses.html#apa2010.
USGS. 2010. A Probabilistic Assessment Methodology for the
Evaluation of Geologic Carbon Dioxide Storage. http://pubs.usgs.gov/of/2010/1127/.
WRI. 2007. J. Logan, J. Venezia, and K. Larsen. Issue Brief:
Opportunities and Challenges for Carbon Capture and Sequestration.
WRI Issue Brief, No. 1. World Resources Institute. October 2007.
Washington, DC.
List of Subjects
40 CFR Part 124
Environmental protection, Administrative practice and procedure,
Air pollution control, Hazardous waste, Indians--lands, Reporting and
recordkeeping requirements, Water pollution control, Water supply.
40 CFR Part 144
Environmental protection, Administrative practice and procedure,
Confidential business information, Hazardous waste, Indians--lands,
Reporting and recordkeeping requirements, Surety bonds, Water supply.
40 CFR Part 145
Environmental protection, Confidential business information,
Indian--lands, Intergovernmental relations, Penalties, Reporting and
recordkeeping requirements, Water supply.
40 CFR Part 146
Environmental protection, Hazardous waste, Indian--lands, Reporting
and recordkeeping requirements, Water supply.
40 CFR Part 147
Environmental protection, Indian--lands, Intergovernmental
relations, Penalties, Reporting and recordkeeping requirements, Water
supply.
Dated: November 22, 2010.
Lisa P. Jackson,
Administrator.
0
For the reasons set forth in the preamble, title 40 chapter I of the
Code of Federal Regulations is amended as follows:
PART 124--PROCEDURES FOR DECISION MAKING
0
1. The authority citation for part 124 continues to read as follows:
Authority: Resource Conservation and Recovery Act, 42 U.S.C.
6901 et seq.; Safe Drinking Water Act, 42 U.S.C. 300f et seq.; Clean
Water Act, 33 U.S.C. 1251 et seq.; Clean Air Act, 42 U.S.C. 7401 et
seq.
Subpart A--General Program Requirements
0
2. Section 124.10 is amended by revising paragraph (c) introductory
text and by adding paragraph (c)(1)(xi) to read as follows:
Sec. 124.10 Public notice of permit actions and public comment
period.
* * * * *
(c) Methods (applicable to State programs, see 40 CFR 123.25
(NPDES), 145.11 (UIC), 233.23 (404), and 271.14 (RCRA)). Public notice
of activities described in paragraph (a)(1) of this section shall be
given by the following methods:
(1) * * *
(xi) For Class VI injection well UIC permits, mailing or e-mailing
a notice to State and local oil and gas regulatory agencies and State
agencies regulating mineral exploration and recovery, the Director of
the Public Water Supply Supervision program in the State, and all
agencies that oversee injection wells in the State.
* * * * *
PART 144--UNDERGROUND INJECTION CONTROL PROGRAM
0
3. The authority citation for part 144 continues to read as follows:
Authority: Safe Drinking Water Act, 42 U.S.C. 300f et seq.;
Resource Conservation and Recovery Act, 42 U.S.C. 6901 et seq.
Subpart A--General Provisions
0
4. Section 144.1 is amended by adding paragraph (f)(1)(viii) and by
revising paragraph (g) introductory text to read as follows.
Sec. 144.1 Purpose and scope of part 144.
* * * * *
(f) * * *
(1) * * *
(viii) Subpart H of part 146 sets forth requirements for owners or
operators of Class VI injection wells.
* * * * *
(g) Scope of the permit or rule requirement. The UIC permit program
regulates underground injection by six classes of wells (see definition
of ``well injection,'' Sec. 144.3). The six classes of wells are set
forth in Sec. 144.6. All owners or operators of these injection wells
must be authorized either by permit or rule by the Director. In
carrying out the mandate of the SDWA, this subpart provides that no
injection shall be authorized by permit or rule if it results in the
movement of fluid containing any contaminant into underground sources
of drinking water (USDWs--see Sec. 144.3 for definition), if the
presence of that contaminant may cause a violation of any primary
drinking water regulation under 40 CFR part 141 or may adversely affect
the health of persons (Sec. 144.12). Existing Class IV wells which
inject hazardous waste directly into an underground source of drinking
water are to be eliminated over a period of six months and new such
Class IV wells are to be prohibited (Sec. 144.13). For Class V wells,
if remedial action appears necessary, a permit may be required (Sec.
144.25) or the Director must require remedial action or closure by
order (Sec. 144.6(c)). During UIC program development, the Director
may identify aquifers and portions of aquifers which are actual or
potential sources of drinking water. This will provide an aid to the
Director in carrying out his or her duty to protect all USDWs. An
aquifer is a USDW if it fits the definition under Sec. 144.3, even if
it has not been ``identified.'' The Director may also designate
``exempted aquifers'' using the
[[Page 77287]]
criteria in 40 CFR 146.4 of this chapter. Such aquifers are those which
would otherwise qualify as ``underground sources of drinking water'' to
be protected, but which have no real potential to be used as drinking
water sources. Therefore, they are not USDWs. No aquifer is an exempted
aquifer until it has been affirmatively designated under the procedures
at Sec. 144.7. Aquifers which do not fit the definition of
``underground source of drinking water'' are not ``exempted aquifers.''
They are simply not subject to the special protection afforded USDWs.
During initial Class VI program development, the Director shall not
expand the areal extent of an existing Class II enhanced oil recovery
or enhanced gas recovery aquifer exemption for Class VI injection wells
and EPA shall not approve a program that applies for aquifer exemption
expansions of Class II-Class VI exemptions as part of the program
description. All Class II to Class VI aquifer exemption expansions
previously issued by EPA must be incorporated into the Class VI program
descriptions pursuant to requirements at Sec. 145.23(f)(9).
* * * * *
0
5. Section 144.3 is amended by adding in alphabetic order the
definition ``geologic sequestration'' to read as follows:
Sec. 144.3 Definitions.
* * * * *
Geologic sequestration means the long-term containment of a
gaseous, liquid, or supercritical carbon dioxide stream in subsurface
geologic formations. This term does not apply to carbon dioxide capture
or transport.
* * * * *
0
6. Section 144.6 is amended by revising paragraph (e) and adding
paragraph (f) to read as follows:
Sec. 144.6 Classification of wells.
* * * * *
(e) Class V. Injection wells not included in Class I, II, III, IV,
or VI. Specific types of Class V injection wells are described in Sec.
144.81.
(f) Class VI. Wells that are not experimental in nature that are
used for geologic sequestration of carbon dioxide beneath the lowermost
formation containing a USDW; or, wells used for geologic sequestration
of carbon dioxide that have been granted a waiver of the injection
depth requirements pursuant to requirements at Sec. 146.95 of this
chapter; or, wells used for geologic sequestration of carbon dioxide
that have received an expansion to the areal extent of an existing
Class II enhanced oil recovery or enhanced gas recovery aquifer
exemption pursuant to Sec. Sec. 146.4 of this chapter and 144.7(d).
0
7. Section 144.7 is amended as follows:
0
a. Revising paragraph (a);
0
b. Revising paragraphs (b)(1) and (b)(2); and
0
c. Adding paragraph (d) as follows:
Sec. 144.7 Identification of underground sources of drinking water
and exempted aquifers.
(a) The Director may identify (by narrative description,
illustrations, maps, or other means) and shall protect as underground
sources of drinking water, all aquifers and parts of aquifers which
meet the definition of ``underground source of drinking water'' in
Sec. 144.3, except to the extent there is an applicable aquifer
exemption under paragraph (b) of this section or an expansion to the
areal extent of an existing Class II enhanced oil recovery or enhanced
gas recovery aquifer exemption for the exclusive purpose of Class VI
injection for geologic sequestration under paragraph (d) of this
section. Other than EPA approved aquifer exemption expansions that meet
the criteria set forth in Sec. 146.4(d) of this chapter, new aquifer
exemptions shall not be issued for Class VI injection wells. Even if an
aquifer has not been specifically identified by the Director, it is an
underground source of drinking water if it meets the definition in
Sec. 144.3.
(b)(1) The Director may identify (by narrative description,
illustrations, maps, or other means) and describe in geographic and/or
geometric terms (such as vertical and lateral limits and gradient)
which are clear and definite, all aquifers or parts thereof which the
Director proposes to designate as exempted aquifers using the criteria
in Sec. 146.4 of this chapter.
(2) No designation of an exempted aquifer submitted as part of a
UIC program shall be final until approved by the Administrator as part
of a UIC program. No designation of an expansion to the areal extent of
a Class II enhanced oil recovery or enhanced gas recovery aquifer
exemption for the exclusive purpose of Class VI injection for geologic
sequestration shall be final until approved by the Administrator as a
revision to the applicable Federal UIC program under part 147 or as a
substantial revision of an approved State UIC program in accordance
with Sec. 145.32 of this chapter.
* * * * *
(d) Expansion to the Areal Extent of Existing Class II Aquifer
Exemptions for Class VI Wells. Owners or operators of Class II enhanced
oil recovery or enhanced gas recovery wells may request that the
Director approve an expansion to the areal extent of an aquifer
exemption already in place for a Class II enhanced oil recovery or
enhanced gas recovery well for the exclusive purpose of Class VI
injection for geologic sequestration. Such requests must be treated as
a revision to the applicable Federal UIC program under part 147 or as a
substantial program revision to an approved State UIC program under
Sec. 145.32 of this chapter and will not be final until approved by
EPA.
(1) The owner or operator of a Class II enhanced oil recovery or
enhanced gas recovery well that requests an expansion of the areal
extent of an existing aquifer exemption for the exclusive purpose of
Class VI injection for geologic sequestration must define (by narrative
description, illustrations, maps, or other means) and describe in
geographic and/or geometric terms (such as vertical and lateral limits
and gradient) that are clear and definite, all aquifers or parts
thereof that are requested to be designated as exempted using the
criteria in Sec. 146.4 of this chapter.
(2) In evaluating a request to expand the areal extent of an
aquifer exemption of a Class II enhanced oil recovery or enhanced gas
recovery well for the purpose of Class VI injection, the Director must
determine that the request meets the criteria for exemptions in Sec.
146.4. In making the determination, the Director shall consider:
(i) Current and potential future use of the USDWs to be exempted as
drinking water resources;
(ii) The predicted extent of the injected carbon dioxide plume, and
any mobilized fluids that may result in degradation of water quality,
over the lifetime of the GS project, as informed by computational
modeling performed pursuant to Sec. 146.84(c)(1), in order to ensure
that the proposed injection operation will not at any time endanger
USDWs including non-exempted portions of the injection formation;
(iii) Whether the areal extent of the expanded aquifer exemption is
of sufficient size to account for any possible revisions to the
computational model during reevaluation of the area of review, pursuant
to Sec. 146.84(e); and
(iv) Any information submitted to support a waiver request made by
the owner or operator under Sec. 146.95, if appropriate.
0
8. Section 144.8 is amended by adding paragraph (b)(2)(iii) to read as
follows:
[[Page 77288]]
Sec. 144.8 Noncompliance and program reporting by the Director.
* * * * *
(b) * * *
(2) * * *
(iii) All Class VI program reports shall be consistent with
reporting requirements set forth in Sec. 146.91 of this chapter.
* * * * *
Subpart B--General Program Requirements
0
9. Section 144.12 is amended by revising the first sentence in
paragraph (b) to read as follows:
Sec. 144.12 Prohibition of movement of fluid into underground sources
of drinking water.
* * * * *
(b) For Class I, II, III, and VI wells, if any water quality
monitoring of an underground source of drinking water indicates the
movement of any contaminant into the underground source of drinking
water, except as authorized under part 146, the Director shall
prescribe such additional requirements for construction, corrective
action, operation, monitoring, or reporting (including closure of the
injection well) as are necessary to prevent such movement. * * *
* * * * *
0
10. Section 144.15 is added to read as follows:
Sec. 144.15 Prohibition of non-experimental Class V wells for
geologic sequestration.
The construction, operation or maintenance of any non-experimental
Class V geologic sequestration well is prohibited.
0
11. Section 144.18 is added to subpart B to read as follows:
Sec. 144.18 Requirements for Class VI wells.
Owners or operators of Class VI wells must obtain a permit. Class
VI wells cannot be authorized by rule to inject carbon dioxide.
0
12. Section 144.19 is added to subpart B to read as follows:
Sec. 144.19 Transitioning from Class II to Class VI.
(a) Owners or operators that are injecting carbon dioxide for the
primary purpose of long-term storage into an oil and gas reservoir must
apply for and obtain a Class VI geologic sequestration permit when
there is an increased risk to USDWs compared to Class II operations. In
determining if there is an increased risk to USDWs, the owner or
operator must consider the factors specified in Sec. 144.19(b).
(b) The Director shall determine when there is an increased risk to
USDWs compared to Class II operations and a Class VI permit is
required. In order to make this determination the Director must
consider the following:
(1) Increase in reservoir pressure within the injection zone(s);
(2) Increase in carbon dioxide injection rates;
(3) Decrease in reservoir production rates;
(4) Distance between the injection zone(s) and USDWs;
(5) Suitability of the Class II area of review delineation;
(6) Quality of abandoned well plugs within the area of review;
(7) The owner's or operator's plan for recovery of carbon dioxide
at the cessation of injection;
(8) The source and properties of injected carbon dioxide; and
(9) Any additional site-specific factors as determined by the
Director.
Subpart C--Authorization of Underground Injection by Rule
0
13. Section 144.22 is amended by revising paragraph (b) to read as
follows:
Sec. 144.22 Existing Class II enhanced recovery and hydrocarbon
storage wells.
* * * * *
(b) Duration of well authorization by rule. Well authorization
under this section expires upon the effective date of a permit issued
pursuant to Sec. Sec. 144.19, 144.25, 144.31, 144.33 or 144.34; after
plugging and abandonment in accordance with an approved plugging and
abandonment plan pursuant to Sec. Sec. 144.28(c) and 146.10 of this
chapter; and upon submission of a plugging and abandonment report
pursuant to Sec. 144.28(k); or upon conversion in compliance with
Sec. 144.28(j).
Subpart D--Authorization by Permit
0
14. Section 144.31 is amended by revising paragraph (e) introductory
text to read as follows:
Sec. 144.31 Application for a permit; authorization by permit.
* * * * *
(e) Information requirements. All applicants for Class I, II, III,
and V permits shall provide the following information to the Director,
using the application form provided by the Director. Applicants for
Class VI permits shall follow the criteria provided in Sec. 146.82 of
this chapter.
* * * * *
0
15. Section 144.33 is amended by revising paragraph (a)(4) and adding
paragraph (a)(5).
Sec. 144.33 Area permits.
(a) * * *
(4) Used to inject other than hazardous waste; and
(5) Other than Class VI wells.
* * * * *
0
16. Section 144.36 is amended by revising paragraph (a) to read as
follows:
Sec. 144.36 Duration of permits.
(a) Permits for Class I and V wells shall be effective for a fixed
term not to exceed 10 years. UIC permits for Class II and III wells
shall be issued for a period up to the operating life of the facility.
UIC permits for Class VI wells shall be issued for the operating life
of the facility and the post-injection site care period. The Director
shall review each issued Class II, III, and VI well UIC permit at least
once every 5 years to determine whether it should be modified, revoked
and reissued, terminated or a minor modification made as provided in
Sec. Sec. 144.39, 144.40, or 144.41.
* * * * *
0
17. Section 144.38 is amended by revising paragraph (b) introductory
text to read as follows:
Sec. 144.38 Transfer of permits.
* * * * *
(b) Automatic transfers. As an alternative to transfers under
paragraph (a) of this section, any UIC permit for a well not injecting
hazardous waste or injecting carbon dioxide for geologic sequestration
may be automatically transferred to a new permittee if:
* * * * *
0
18. Section 144.39 is amended as follows:
0
a. Revising the second sentence in paragraph (a) introductory text;
0
b. Revising the second sentence in paragraph (a)(3) introductory text;
and
0
c. Adding a new paragraph (a)(5) to read as follows:
Sec. 144.39 Modification or revocation and reissuance of permits.
* * * * *
(a) * * * For Class I hazardous waste injection wells, Class II,
Class III or Class VI wells the following may be causes for revocation
and reissuance as well as modification; and for all other wells the
following may be cause for revocation or reissuance as well as
modification when the permittee requests or agrees.
* * * * *
(3) * * * Permits other than for Class I hazardous waste injection
wells, Class II, Class III or Class VI wells may be
[[Page 77289]]
modified during their permit terms for this cause only as follows:
* * * * *
(5) Basis for modification of Class VI permits. Additionally, for
Class VI wells, whenever the Director determines that permit changes
are necessary based on:
(i) Area of review reevaluations under Sec. 146.84(e)(1) of this
chapter;
(ii) Any amendments to the testing and monitoring plan under Sec.
146.90(j) of this chapter;
(iii) Any amendments to the injection well plugging plan under
Sec. 146.92(c) of this chapter;
(iv) Any amendments to the post-injection site care and site
closure plan under Sec. 146.93(a)(3) of this chapter;
(v) Any amendments to the emergency and remedial response plan
under Sec. 146.94(d) of this chapter; or
(vi) A review of monitoring and/or testing results conducted in
accordance with permit requirements.
* * * * *
0
19. Section 144.41 is amended by adding a new paragraph (h) to read as
follows:
Sec. 144.41 Minor modifications of permits.
* * * * *
(h) Amend a Class VI injection well testing and monitoring plan,
plugging plan, post-injection site care and site closure plan, or
emergency and remedial response plan where the modifications merely
clarify or correct the plan, as determined by the Director.
Subpart E--Permit Conditions
0
20. Section 144.51 is amended to read as follows:
0
a. Adding a new paragraph (j)(4);
0
b. Revising paragraph (o); and
0
c. Removing the first sentence in paragraph (q)(1) and adding two
sentences in its place; and
0
d. Revising the first sentence in paragraph (q)(2).
Sec. 144.51 Conditions applicable to all permits.
* * * * *
(j) * * *
(4) Owners or operators of Class VI wells shall retain records as
specified in subpart H of part 146, including Sec. Sec. 146.84(g),
146.91(f), 146.92(d), 146.93(f), and 146.93(h) of this chapter.
* * * * *
(o) A Class I, II or III permit shall include and a Class V permit
may include conditions which meet the applicable requirements of Sec.
146.10 of this chapter to ensure that plugging and abandonment of the
well will not allow the movement of fluids into or between USDWs. Where
the plan meets the requirements of Sec. 146.10 of this chapter, the
Director shall incorporate the plan into the permit as a permit
condition. Where the Director's review of an application indicates that
the permittee's plan is inadequate, the Director may require the
applicant to revise the plan, prescribe conditions meeting the
requirements of this paragraph, or deny the permit. A Class VI permit
shall include conditions which meet the requirements set forth in Sec.
146.92 of this chapter. Where the plan meets the requirements of Sec.
146.92 of this chapter, the Director shall incorporate it into the
permit as a permit condition. For purposes of this paragraph, temporary
or intermittent cessation of injection operations is not abandonment.
* * * * *
(q) * * *
(1) The owner or operator of a Class I, II, III or VI well
permitted under this part shall establish mechanical integrity prior to
commencing injection or on a schedule determined by the Director.
Thereafter the owner or operator of Class I, II, and III wells must
maintain mechanical integrity as defined in Sec. 146.8 of this chapter
and the owner or operator of Class VI wells must maintain mechanical
integrity as defined in Sec. 146.89 of this chapter. * * *
(2) When the Director determines that a Class I, II, III or VI well
lacks mechanical integrity pursuant to Sec. Sec. 146.8 or 146.89 of
this chapter for Class VI of this chapter, he/she shall give written
notice of his/her determination to the owner or operator. * * *
* * * * *
0
21. Section 144.52 is amended as follows:
0
a. By revising paragraph (a) introductory text;
0
b. Revising paragraph (a)(2);
0
c. Revising paragraphs (a)(7)(i)(A) and (a)(7)(ii); and
0
d. Revising paragraph (a)(8).
Sec. 144.52 Establishing permit conditions.
(a) In addition to conditions required in Sec. 144.51, the
Director shall establish conditions, as required on a case-by-case
basis under Sec. 144.36 (duration of permits), Sec. 144.53(a)
(schedules of compliance), Sec. 144.54 (monitoring), and for EPA
permits only Sec. 144.53(b) (alternate schedules of compliance), and
Sec. 144.4 (considerations under Federal law). Permits for owners or
operators of hazardous waste injection wells shall include conditions
meeting the requirements of Sec. 144.14 (requirements for wells
injecting hazardous waste), paragraphs (a)(7) and (a)(9) of this
section, and subpart G of part 146. Permits for owners or operators of
Class VI injection wells shall include conditions meeting the
requirements of subpart H of part 146. Permits for other wells shall
contain the following requirements, when applicable.
* * * * *
(2) Corrective action as set forth in Sec. Sec. 144.55, 146.7, and
146.84 of this chapter.
* * * * *
(7) * * *
(i) * * *
(A) The well has been plugged and abandoned in accordance with an
approved plugging and abandonment plan pursuant to Sec. Sec.
144.51(o), 146.10, and 146.92 of this chapter, and submitted a plugging
and abandonment report pursuant to Sec. 144.51(p); or
* * * * *
(ii) The permittee shall show evidence of such financial
responsibility to the Director by the submission of a surety bond, or
other adequate assurance, such as a financial statement or other
materials acceptable to the Director. For EPA administered programs,
the Regional Administrator may on a periodic basis require the holder
of a lifetime permit to submit an estimate of the resources needed to
plug and abandon the well revised to reflect inflation of such costs,
and a revised demonstration of financial responsibility, if necessary.
The owner or operator of a well injecting hazardous waste must comply
with the financial responsibility requirements of subpart F of this
part. For Class VI wells, the permittee shall show evidence of such
financial responsibility to the Director by the submission of a
qualifying instrument (see Sec. 146.85(a) of this chapter), such as a
financial statement or other materials acceptable to the Director. The
owner or operator of a Class VI well must comply with the financial
responsibility requirements set forth in Sec. 146.85 of this chapter.
(8) Mechanical integrity. A permit for any Class I, II, III or VI
well or injection project which lacks mechanical integrity shall
include, and for any Class V well may include, a condition prohibiting
injection operations until the permittee shows to the satisfaction of
the Director under Sec. 146.8, or Sec. 146.89 of this chapter for
Class VI, that the well has mechanical integrity.
* * * * *
[[Page 77290]]
Subpart G--Requirements for Owners and Operators of Class V
Injection Wells
0
22. Section 144.80 is amended by revising the first sentence in
paragraph (e) and by adding paragraph (f) to read as follows:
Sec. 144.80 What is a Class V injection well?
* * * * *
(e) Class V. Injection wells not included in Class I, II, III, IV
or VI. * * *
(f) Class VI. Wells used for geologic sequestration of carbon
dioxide beneath the lowermost formation containing a USDW, except those
wells that are experimental in nature; or, wells used for geologic
sequestration of carbon dioxide that have been granted a waiver of the
injection depth requirements pursuant to requirements at Sec. 146.95
of this chapter; or, wells used for geologic sequestration of carbon
dioxide that have received an expansion to the areal extent of a
existing Class II enhanced oil recovery or enhanced gas recovery
aquifer exemption pursuant to Sec. 146.4 of this chapter and Sec.
144.7(d).
PART 145--STATE UIC PROGRAM REQUIREMENTS
0
23. The authority citation for part 145 continues to read as follows:
Authority: 42 U.S.C. 300f et seq.
Subpart A--General Program Requirements
0
24. Section 145.1 is amended by adding paragraph (i) to read as
follows:
Sec. 145.1 Purpose and scope.
* * * * *
(i) States seeking primary enforcement responsibility for Class VI
wells must submit a primacy application in accordance with subpart C of
this part and meet all requirements of this part. States may apply for
primary enforcement responsibility for Class VI wells independently of
other injection well classes.
Subpart C--State Program Submissions
0
25. Section 145.21 is amended by adding paragraph (h) to read as
follows:
Sec. 145.21 General requirements for program approvals.
* * * * *
(h) To establish a Federal UIC Class VI program in States not
seeking full UIC primary enforcement responsibility approval, pursuant
to the SDWA section 1422(c), States shall, by September 6, 2011, submit
to the Administrator a new or revised State UIC program complying with
Sec. Sec. 145.22 or 145.32 of this part. Beginning on September 6,
2011 the requirements of subpart H of part 146 of this chapter will be
applicable and enforceable by EPA in each State that has not received
approval of a new Class VI program application under section 1422 of
the Safe Drinking Water Act or a revision of its UIC program under
section 1422 of the Safe Drinking Water Act to incorporate subpart H of
part 146. Following September 6, 2011, EPA will publish a list of the
States where subpart H of part 146 has become applicable.
0
26. Section 145.22 is amended by revising paragraphs (a) introductory
text and (a)(5) to read as follows:
Sec. 145.22 Elements of a program submission.
(a) Any State that seeks to administer a program under this part
shall submit to the Administrator at least three copies of a program
submission. For Class VI programs, the entire submission can be sent
electronically. The submission shall contain the following:
* * * * *
(5) Copies of all applicable State statutes and regulations,
including those governing State administrative procedures;
* * * * *
0
27. Section 145.23 is amended as follows:
0
a. By revising the introductory text;
0
b. Revising paragraph (c);
0
c. Revising paragraph (d);
0
d. Revising paragraphs (f)(1), (f)(2), (f)(3), (f)(4), and (f)(9); and
0
e. Adding paragraph (f)(13) to read as follows:
Sec. 145.23 Program description.
Any State that seeks to administer a program under this part shall
submit a description of the program it proposes to administer in lieu
of the Federal program under State law or under an interstate compact.
For Class VI programs, the entire submission can be sent
electronically. The program description shall include:
* * * * *
(c) A description of applicable State procedures, including
permitting procedures and any State administrative or judicial review
procedures.
(d) Copies of the permit form(s), application form(s), reporting
form(s), and manifest format the State intends to employ in its
program. Forms used by States need not be identical to the forms used
by EPA but should require the same basic information. The State need
not provide copies of uniform national forms it intends to use but
should note its intention to use such forms. For Class VI programs,
submit copies of the current forms in use by the State, if any.
* * * * *
(f) * * *
(1) A schedule for issuing permits within five years after program
approval to all injection wells within the State which are required to
have permits under this part and 40 CFR part 144. For Class VI
programs, a schedule for issuing permits within two years after program
approval;
(2) The priorities (according to criteria set forth in Sec. 146.9
of this chapter) for issuing permits, including the number of permits
in each class of injection well which will be issued each year during
the first five years of program operation. For Class VI programs,
include the priorities for issuing permits and the number of permits
which will be issued during the first two years of program operation;
(3) A description of how the Director will implement the mechanical
integrity testing requirements of Sec. 146.8 of this chapter, or, for
Class VI wells, the mechanical integrity testing requirements of Sec.
146.89 of this chapter, including the frequency of testing that will be
required and the number of tests that will be reviewed by the Director
each year;
(4) A description of the procedure whereby the Director will notify
owners or operators of injection wells of the requirement that they
apply for and obtain a permit. The notification required by this
paragraph shall require applications to be filed as soon as possible,
but not later than four years after program approval for all injection
wells requiring a permit. For Class VI programs approved before
December 10, 2011, a description of the procedure whereby the Director
will notify owners or operators of any Class I wells previously
permitted for the purpose of geologic sequestration or Class V
experimental technology wells no longer being used for experimental
purposes that will continue injection of carbon dioxide for the purpose
of GS that they must apply for a Class VI permit pursuant to
requirements at Sec. 146.81(c) within one year of December 10, 2011.
For Class VI programs approved following December 10, 2011, a
description of the procedure whereby the Director will notify owners or
operators of any Class I wells previously permitted for the purpose of
geologic sequestration or Class V experimental technology wells no
longer being used
[[Page 77291]]
for experimental purposes that will continue injection of carbon
dioxide for the purpose of GS or Class VI wells previously permitted by
EPA that they must apply for a Class VI permit pursuant to requirements
at Sec. 146.81(c) within one year of Class VI program approval;
* * * * *
(9) A description of aquifers, or parts thereof, which the Director
has identified under Sec. 144.7(b) as exempted aquifers, and a summary
of supporting data. For Class VI programs only, States must incorporate
information related to any EPA approved exemptions expanding the areal
extent of existing aquifer exemptions for Class II enhanced oil
recovery or enhanced gas recovery wells transitioning to Class VI
injection for geologic sequestration pursuant to requirements at
Sec. Sec. 146.4(d) and 144.7(d), including a summary of supporting
data and the specific location of the aquifer exemption expansions.
Other than expansions of the areal extent of Class II enhanced oil
recovery or enhanced gas recovery well aquifer exemptions for Class VI
injection, new aquifer exemptions shall not be issued for Class VI
wells or injection activities;
* * * * *
(13) For Class VI programs, a description of the procedure whereby
the Director must notify, in writing, any States, Tribes, and
Territories of any permit applications for geologic sequestration of
carbon dioxide wherein the area of review crosses State, Tribal, or
Territory boundaries, resulting in the need for trans-boundary
coordination related to an injection operation.
0
28. Section 145.32 is amended by adding a sentence at the end of
paragraph (b)(2) to read as follows:
Sec. 145.32 Procedures for revision of State programs.
* * * * *
(b) * * *
(2) * * * All requests for expansions to the areal extent of Class
II enhanced oil recovery or enhanced gas recovery aquifer exemptions
for Class VI wells must be treated as substantial program revisions.
* * * * *
PART 146--UNDERGROUND INJECTION CONTROL PROGRAM: CRITERIA AND
STANDARDS
0
29. The authority citation for part 146 continues to read as follows:
Authority: Safe Drinking Water Act 42, U.S.C. 300f et seq.;
Resource Conservation and Recovery Act, 42 U.S.C. 6901 et seq.
0
30. Section 146.4 is amended by revising the introductory text and
adding paragraph (d) to read as follows:
Sec. 146.4 Criteria for exempted aquifers.
An aquifer or a portion thereof which meets the criteria for an
``underground source of drinking water'' in Sec. 146.3 may be
determined under Sec. 144.7 of this chapter to be an ``exempted
aquifer'' for Class I-V wells if it meets the criteria in paragraphs
(a) through (c) of this section. Class VI wells must meet the criteria
under paragraph (d) of this section:
* * * * *
(d) The areal extent of an aquifer exemption for a Class II
enhanced oil recovery or enhanced gas recovery well may be expanded for
the exclusive purpose of Class VI injection for geologic sequestration
under Sec. 144.7(d) of this chapter if it meets the following
criteria:
(1) It does not currently serve as a source of drinking water; and
(2) The total dissolved solids content of the ground water is more
than 3,000 mg/l and less than 10,000 mg/l; and
(3) It is not reasonably expected to supply a public water system.
0
31. Section 146.5 is amended by revising the first sentence in
paragraph (e) introductory text and by adding paragraph (f) to read as
follows:
Sec. 146.5 Classification of injection wells.
* * * * *
(e) Class V. Injection wells not included in Class I, II, III, IV
or VI. * * *
* * * * *
(f) Class VI. Wells that are not experimental in nature that are
used for geologic sequestration of carbon dioxide beneath the lowermost
formation containing a USDW; or, wells used for geologic sequestration
of carbon dioxide that have been granted a waiver of the injection
depth requirements pursuant to requirements at Sec. 146.95; or, wells
used for geologic sequestration of carbon dioxide that have received an
expansion to the areal extent of an existing Class II enhanced oil
recovery or enhanced gas recovery aquifer exemption pursuant to Sec.
146.4 and Sec. 144.7(d) of this chapter.
0
32. Subpart H is added to read as follows:
Subpart H--Criteria and Standards Applicable to Class VI Wells
Sec.
146.81 Applicability.
146.82 Required Class VI permit information.
146.83 Minimum criteria for siting.
146.84 Area of review and corrective action.
146.85 Financial responsibility.
146.86 Injection well construction requirements.
146.87 Logging, sampling, and testing prior to injection well
operation.
146.88 Injection well operating requirements.
146.89 Mechanical integrity.
146.90 Testing and monitoring requirements.
146.91 Reporting requirements.
146.92 Injection well plugging.
146.93 Post-injection site care and site closure.
146.94 Emergency and remedial response.
146.95 Class VI injection depth waiver requirements.
Subpart H--Criteria and Standards Applicable to Class VI Wells
Sec. 146.81 Applicability.
(a) This subpart establishes criteria and standards for underground
injection control programs to regulate any Class VI carbon dioxide
geologic sequestration injection wells.
(b) This subpart applies to any wells used to inject carbon dioxide
specifically for the purpose of geologic sequestration, i.e., the long-
term containment of a gaseous, liquid, or supercritical carbon dioxide
stream in subsurface geologic formations.
(c) This subpart also applies to owners or operators of permit- or
rule-authorized Class I, Class II, or Class V experimental carbon
dioxide injection projects who seek to apply for a Class VI geologic
sequestration permit for their well or wells. Owners or operators
seeking to convert existing Class I, Class II, or Class V experimental
wells to Class VI geologic sequestration wells must demonstrate to the
Director that the wells were engineered and constructed to meet the
requirements at Sec. 146.86(a) and ensure protection of USDWs, in lieu
of requirements at Sec. Sec. 146.86(b) and 146.87(a). By December 10,
2011, owners or operators of either Class I wells previously permitted
for the purpose of geologic sequestration or Class V experimental
technology wells no longer being used for experimental purposes that
will continue injection of carbon dioxide for the purpose of GS must
apply for a Class VI permit. A converted well must still meet all other
requirements under part 146.
(d) Definitions. The following definitions apply to this subpart.
To the extent that these definitions conflict with those in Sec. Sec.
144.3 or 146.3 of this chapter these definitions govern for Class VI
wells:
Area of review means the region surrounding the geologic
sequestration project where USDWs may be endangered by the injection
activity. The area of review is delineated using
[[Page 77292]]
computational modeling that accounts for the physical and chemical
properties of all phases of the injected carbon dioxide stream and
displaced fluids, and is based on available site characterization,
monitoring, and operational data as set forth in Sec. 146.84.
Carbon dioxide plume means the extent underground, in three
dimensions, of an injected carbon dioxide stream.
Carbon dioxide stream means carbon dioxide that has been captured
from an emission source (e.g., a power plant), plus incidental
associated substances derived from the source materials and the capture
process, and any substances added to the stream to enable or improve
the injection process. This subpart does not apply to any carbon
dioxide stream that meets the definition of a hazardous waste under 40
CFR part 261.
Confining zone means a geologic formation, group of formations, or
part of a formation stratigraphically overlying the injection zone(s)
that acts as barrier to fluid movement. For Class VI wells operating
under an injection depth waiver, confining zone means a geologic
formation, group of formations, or part of a formation
stratigraphically overlying and underlying the injection zone(s).
Corrective action means the use of Director-approved methods to
ensure that wells within the area of review do not serve as conduits
for the movement of fluids into underground sources of drinking water
(USDW).
Geologic sequestration means the long-term containment of a
gaseous, liquid, or supercritical carbon dioxide stream in subsurface
geologic formations. This term does not apply to carbon dioxide capture
or transport.
Geologic sequestration project means an injection well or wells
used to emplace a carbon dioxide stream beneath the lowermost formation
containing a USDW; or, wells used for geologic sequestration of carbon
dioxide that have been granted a waiver of the injection depth
requirements pursuant to requirements at Sec. 146.95; or, wells used
for geologic sequestration of carbon dioxide that have received an
expansion to the areal extent of an existing Class II enhanced oil
recovery or enhanced gas recovery aquifer exemption pursuant to Sec.
146.4 and Sec. 144.7(d) of this chapter. It includes the subsurface
three-dimensional extent of the carbon dioxide plume, associated area
of elevated pressure, and displaced fluids, as well as the surface area
above that delineated region.
Injection zone means a geologic formation, group of formations, or
part of a formation that is of sufficient areal extent, thickness,
porosity, and permeability to receive carbon dioxide through a well or
wells associated with a geologic sequestration project.
Post-injection site care means appropriate monitoring and other
actions (including corrective action) needed following cessation of
injection to ensure that USDWs are not endangered, as required under
Sec. 146.93.
Pressure front means the zone of elevated pressure that is created
by the injection of carbon dioxide into the subsurface. For the
purposes of this subpart, the pressure front of a carbon dioxide plume
refers to a zone where there is a pressure differential sufficient to
cause the movement of injected fluids or formation fluids into a USDW.
Site closure means the point/time, as determined by the Director
following the requirements under Sec. 146.93, at which the owner or
operator of a geologic sequestration site is released from post-
injection site care responsibilities.
Transmissive fault or fracture means a fault or fracture that has
sufficient permeability and vertical extent to allow fluids to move
between formations.
Sec. 146.82 Required Class VI permit information.
This section sets forth the information which must be considered by
the Director in authorizing Class VI wells. For converted Class I,
Class II, or Class V experimental wells, certain maps, cross-sections,
tabulations of wells within the area of review and other data may be
included in the application by reference provided they are current,
readily available to the Director, and sufficiently identified to be
retrieved. In cases where EPA issues the permit, all the information in
this section must be submitted to the Regional Administrator.
(a) Prior to the issuance of a permit for the construction of a new
Class VI well or the conversion of an existing Class I, Class II, or
Class V well to a Class VI well, the owner or operator shall submit,
pursuant to Sec. 146.91(e), and the Director shall consider the
following:
(1) Information required in Sec. 144.31(e)(1) through (6) of this
chapter;
(2) A map showing the injection well for which a permit is sought
and the applicable area of review consistent with Sec. 146.84. Within
the area of review, the map must show the number or name, and location
of all injection wells, producing wells, abandoned wells, plugged wells
or dry holes, deep stratigraphic boreholes, State- or EPA-approved
subsurface cleanup sites, surface bodies of water, springs, mines
(surface and subsurface), quarries, water wells, other pertinent
surface features including structures intended for human occupancy,
State, Tribal, and Territory boundaries, and roads. The map should also
show faults, if known or suspected. Only information of public record
is required to be included on this map;
(3) Information on the geologic structure and hydrogeologic
properties of the proposed storage site and overlying formations,
including:
(i) Maps and cross sections of the area of review;
(ii) The location, orientation, and properties of known or
suspected faults and fractures that may transect the confining zone(s)
in the area of review and a determination that they would not interfere
with containment;
(iii) Data on the depth, areal extent, thickness, mineralogy,
porosity, permeability, and capillary pressure of the injection and
confining zone(s); including geology/facies changes based on field data
which may include geologic cores, outcrop data, seismic surveys, well
logs, and names and lithologic descriptions;
(iv) Geomechanical information on fractures, stress, ductility,
rock strength, and in situ fluid pressures within the confining
zone(s);
(v) Information on the seismic history including the presence and
depth of seismic sources and a determination that the seismicity would
not interfere with containment; and
(vi) Geologic and topographic maps and cross sections illustrating
regional geology, hydrogeology, and the geologic structure of the local
area.
(4) A tabulation of all wells within the area of review which
penetrate the injection or confining zone(s). Such data must include a
description of each well's type, construction, date drilled, location,
depth, record of plugging and/or completion, and any additional
information the Director may require;
(5) Maps and stratigraphic cross sections indicating the general
vertical and lateral limits of all USDWs, water wells and springs
within the area of review, their positions relative to the injection
zone(s), and the direction of water movement, where known;
(6) Baseline geochemical data on subsurface formations, including
all USDWs in the area of review;
(7) Proposed operating data for the proposed geologic sequestration
site:
(i) Average and maximum daily rate and volume and/or mass and total
anticipated volume and/or mass of the carbon dioxide stream;
[[Page 77293]]
(ii) Average and maximum injection pressure;
(iii) The source(s) of the carbon dioxide stream; and
(iv) An analysis of the chemical and physical characteristics of
the carbon dioxide stream.
(8) Proposed pre-operational formation testing program to obtain an
analysis of the chemical and physical characteristics of the injection
zone(s) and confining zone(s) and that meets the requirements at Sec.
146.87;
(9) Proposed stimulation program, a description of stimulation
fluids to be used and a determination that stimulation will not
interfere with containment;
(10) Proposed procedure to outline steps necessary to conduct
injection operation;
(11) Schematics or other appropriate drawings of the surface and
subsurface construction details of the well;
(12) Injection well construction procedures that meet the
requirements of Sec. 146.86;
(13) Proposed area of review and corrective action plan that meets
the requirements under Sec. 146.84;
(14) A demonstration, satisfactory to the Director, that the
applicant has met the financial responsibility requirements under Sec.
146.85;
(15) Proposed testing and monitoring plan required by Sec. 146.90;
(16) Proposed injection well plugging plan required by Sec.
146.92(b);
(17) Proposed post-injection site care and site closure plan
required by Sec. 146.93(a);
(18) At the Director's discretion, a demonstration of an
alternative post-injection site care timeframe required by Sec.
146.93(c);
(19) Proposed emergency and remedial response plan required by
Sec. 146.94(a);
(20) A list of contacts, submitted to the Director, for those
States, Tribes, and Territories identified to be within the area of
review of the Class VI project based on information provided in
paragraph (a)(2) of this section; and
(21) Any other information requested by the Director.
(b) The Director shall notify, in writing, any States, Tribes, or
Territories within the area of review of the Class VI project based on
information provided in paragraphs (a)(2) and (a)(20) of this section
of the permit application and pursuant to the requirements at Sec.
145.23(f)(13) of this chapter.
(c) Prior to granting approval for the operation of a Class VI
well, the Director shall consider the following information:
(1) The final area of review based on modeling, using data obtained
during logging and testing of the well and the formation as required by
paragraphs (c)(2), (3), (4), (6), (7), and (10) of this section;
(2) Any relevant updates, based on data obtained during logging and
testing of the well and the formation as required by paragraphs (c)(3),
(4), (6), (7), and (10) of this section, to the information on the
geologic structure and hydrogeologic properties of the proposed storage
site and overlying formations, submitted to satisfy the requirements of
paragraph (a)(3) of this section;
(3) Information on the compatibility of the carbon dioxide stream
with fluids in the injection zone(s) and minerals in both the injection
and the confining zone(s), based on the results of the formation
testing program, and with the materials used to construct the well;
(4) The results of the formation testing program required at
paragraph (a)(8) of this section;
(5) Final injection well construction procedures that meet the
requirements of Sec. 146.86;
(6) The status of corrective action on wells in the area of review;
(7) All available logging and testing program data on the well
required by Sec. 146.87;
(8) A demonstration of mechanical integrity pursuant to Sec.
146.89;
(9) Any updates to the proposed area of review and corrective
action plan, testing and monitoring plan, injection well plugging plan,
post-injection site care and site closure plan, or the emergency and
remedial response plan submitted under paragraph (a) of this section,
which are necessary to address new information collected during logging
and testing of the well and the formation as required by all paragraphs
of this section, and any updates to the alternative post-injection site
care timeframe demonstration submitted under paragraph (a) of this
section, which are necessary to address new information collected
during the logging and testing of the well and the formation as
required by all paragraphs of this section; and
(10) Any other information requested by the Director.
(d) Owners or operators seeking a waiver of the requirement to
inject below the lowermost USDW must also refer to Sec. 146.95 and
submit a supplemental report, as required at Sec. 146.95(a). The
supplemental report is not part of the permit application.
Sec. 146.83 Minimum criteria for siting.
(a) Owners or operators of Class VI wells must demonstrate to the
satisfaction of the Director that the wells will be sited in areas with
a suitable geologic system. The owners or operators must demonstrate
that the geologic system comprises:
(1) An injection zone(s) of sufficient areal extent, thickness,
porosity, and permeability to receive the total anticipated volume of
the carbon dioxide stream;
(2) Confining zone(s) free of transmissive faults or fractures and
of sufficient areal extent and integrity to contain the injected carbon
dioxide stream and displaced formation fluids and allow injection at
proposed maximum pressures and volumes without initiating or
propagating fractures in the confining zone(s).
(b) The Director may require owners or operators of Class VI wells
to identify and characterize additional zones that will impede vertical
fluid movement, are free of faults and fractures that may interfere
with containment, allow for pressure dissipation, and provide
additional opportunities for monitoring, mitigation, and remediation.
Sec. 146.84 Area of review and corrective action.
(a) The area of review is the region surrounding the geologic
sequestration project where USDWs may be endangered by the injection
activity. The area of review is delineated using computational modeling
that accounts for the physical and chemical properties of all phases of
the injected carbon dioxide stream and is based on available site
characterization, monitoring, and operational data.
(b) The owner or operator of a Class VI well must prepare,
maintain, and comply with a plan to delineate the area of review for a
proposed geologic sequestration project, periodically reevaluate the
delineation, and perform corrective action that meets the requirements
of this section and is acceptable to the Director. The requirement to
maintain and implement an approved plan is directly enforceable
regardless of whether the requirement is a condition of the permit. As
a part of the permit application for approval by the Director, the
owner or operator must submit an area of review and corrective action
plan that includes the following information:
(1) The method for delineating the area of review that meets the
requirements of paragraph (c) of this section, including the model to
be used, assumptions that will be made, and the site characterization
data on which the model will be based;
(2) A description of:
(i) The minimum fixed frequency, not to exceed five years, at which
the owner
[[Page 77294]]
or operator proposes to reevaluate the area of review;
(ii) The monitoring and operational conditions that would warrant a
reevaluation of the area of review prior to the next scheduled
reevaluation as determined by the minimum fixed frequency established
in paragraph (b)(2)(i) of this section.
(iii) How monitoring and operational data (e.g., injection rate and
pressure) will be used to inform an area of review reevaluation; and
(iv) How corrective action will be conducted to meet the
requirements of paragraph (d) of this section, including what
corrective action will be performed prior to injection and what, if
any, portions of the area of review will have corrective action
addressed on a phased basis and how the phasing will be determined; how
corrective action will be adjusted if there are changes in the area of
review; and how site access will be guaranteed for future corrective
action.
(c) Owners or operators of Class VI wells must perform the
following actions to delineate the area of review and identify all
wells that require corrective action:
(1) Predict, using existing site characterization, monitoring and
operational data, and computational modeling, the projected lateral and
vertical migration of the carbon dioxide plume and formation fluids in
the subsurface from the commencement of injection activities until the
plume movement ceases, until pressure differentials sufficient to cause
the movement of injected fluids or formation fluids into a USDW are no
longer present, or until the end of a fixed time period as determined
by the Director. The model must:
(i) Be based on detailed geologic data collected to characterize
the injection zone(s), confining zone(s) and any additional zones; and
anticipated operating data, including injection pressures, rates, and
total volumes over the proposed life of the geologic sequestration
project;
(ii) Take into account any geologic heterogeneities, other
discontinuities, data quality, and their possible impact on model
predictions; and
(iii) Consider potential migration through faults, fractures, and
artificial penetrations.
(2) Using methods approved by the Director, identify all
penetrations, including active and abandoned wells and underground
mines, in the area of review that may penetrate the confining zone(s).
Provide a description of each well's type, construction, date drilled,
location, depth, record of plugging and/or completion, and any
additional information the Director may require; and
(3) Determine which abandoned wells in the area of review have been
plugged in a manner that prevents the movement of carbon dioxide or
other fluids that may endanger USDWs, including use of materials
compatible with the carbon dioxide stream.
(d) Owners or operators of Class VI wells must perform corrective
action on all wells in the area of review that are determined to need
corrective action, using methods designed to prevent the movement of
fluid into or between USDWs, including use of materials compatible with
the carbon dioxide stream, where appropriate.
(e) At the minimum fixed frequency, not to exceed five years, as
specified in the area of review and corrective action plan, or when
monitoring and operational conditions warrant, owners or operators
must:
(1) Reevaluate the area of review in the same manner specified in
paragraph (c)(1) of this section;
(2) Identify all wells in the reevaluated area of review that
require corrective action in the same manner specified in paragraph (c)
of this section;
(3) Perform corrective action on wells requiring corrective action
in the reevaluated area of review in the same manner specified in
paragraph (d) of this section; and
(4) Submit an amended area of review and corrective action plan or
demonstrate to the Director through monitoring data and modeling
results that no amendment to the area of review and corrective action
plan is needed. Any amendments to the area of review and corrective
action plan must be approved by the Director, must be incorporated into
the permit, and are subject to the permit modification requirements at
Sec. Sec. 144.39 or 144.41 of this chapter, as appropriate.
(f) The emergency and remedial response plan (as required by Sec.
146.94) and the demonstration of financial responsibility (as described
by Sec. 146.85) must account for the area of review delineated as
specified in paragraph (c)(1) of this section or the most recently
evaluated area of review delineated under paragraph (e) of this
section, regardless of whether or not corrective action in the area of
review is phased.
(g) All modeling inputs and data used to support area of review
reevaluations under paragraph (e) of this section shall be retained for
10 years.
Sec. 146.85 Financial responsibility.
(a) The owner or operator must demonstrate and maintain financial
responsibility as determined by the Director that meets the following
conditions:
(1) The financial responsibility instrument(s) used must be from
the following list of qualifying instruments:
(i) Trust Funds.
(ii) Surety Bonds.
(iii) Letter of Credit.
(iv) Insurance.
(v) Self Insurance (i.e., Financial Test and Corporate Guarantee).
(vi) Escrow Account.
(vii) Any other instrument(s) satisfactory to the Director.
(2) The qualifying instrument(s) must be sufficient to cover the
cost of:
(i) Corrective action (that meets the requirements of Sec.
146.84);
(ii) Injection well plugging (that meets the requirements of Sec.
146.92);
(iii) Post injection site care and site closure (that meets the
requirements of Sec. 146.93); and
(iv) Emergency and remedial response (that meets the requirements
of Sec. 146.94).
(3) The financial responsibility instrument(s) must be sufficient
to address endangerment of underground sources of drinking water.
(4) The qualifying financial responsibility instrument(s) must
comprise protective conditions of coverage.
(i) Protective conditions of coverage must include at a minimum
cancellation, renewal, and continuation provisions, specifications on
when the provider becomes liable following a notice of cancellation if
there is a failure to renew with a new qualifying financial instrument,
and requirements for the provider to meet a minimum rating, minimum
capitalization, and ability to pass the bond rating when applicable.
(A) Cancellation--for purposes of this part, an owner or operator
must provide that their financial mechanism may not cancel, terminate
or fail to renew except for failure to pay such financial instrument.
If there is a failure to pay the financial instrument, the financial
institution may elect to cancel, terminate, or fail to renew the
instrument by sending notice by certified mail to the owner or operator
and the Director. The cancellation must not be final for 120 days after
receipt of cancellation notice. The owner or operator must provide an
alternate financial responsibility demonstration within 60 days of
notice of cancellation, and if an alternate financial responsibility
demonstration is not acceptable (or possible), any funds from
[[Page 77295]]
the instrument being cancelled must be released within 60 days of
notification by the Director.
(B) Renewal--for purposes of this part, owners or operators must
renew all financial instruments, if an instrument expires, for the
entire term of the geologic sequestration project. The instrument may
be automatically renewed as long as the owner or operator has the
option of renewal at the face amount of the expiring instrument. The
automatic renewal of the instrument must, at a minimum, provide the
holder with the option of renewal at the face amount of the expiring
financial instrument.
(C) Cancellation, termination, or failure to renew may not occur
and the financial instrument will remain in full force and effect in
the event that on or before the date of expiration: The Director deems
the facility abandoned; or the permit is terminated or revoked or a new
permit is denied; or closure is ordered by the Director or a U.S.
district court or other court of competent jurisdiction; or the owner
or operator is named as debtor in a voluntary or involuntary proceeding
under Title 11 (Bankruptcy), U.S. Code; or the amount due is paid.
(5) The qualifying financial responsibility instrument(s) must be
approved by the Director.
(i) The Director shall consider and approve the financial
responsibility demonstration for all the phases of the geologic
sequestration project prior to issue a Class VI permit (Sec. 146.82).
(ii) The owner or operator must provide any updated information
related to their financial responsibility instrument(s) on an annual
basis and if there are any changes, the Director must evaluate, within
a reasonable time, the financial responsibility demonstration to
confirm that the instrument(s) used remain adequate for use. The owner
or operator must maintain financial responsibility requirements
regardless of the status of the Director's review of the financial
responsibility demonstration.
(iii) The Director may disapprove the use of a financial instrument
if he determines that it is not sufficient to meet the requirements of
this section.
(6) The owner or operator may demonstrate financial responsibility
by using one or multiple qualifying financial instruments for specific
phases of the geologic sequestration project.
(i) In the event that the owner or operator combines more than one
instrument for a specific geologic sequestration phase (e.g., well
plugging), such combination must be limited to instruments that are not
based on financial strength or performance (i.e., self insurance or
performance bond), for example trust funds, surety bonds guaranteeing
payment into a trust fund, letters of credit, escrow account, and
insurance. In this case, it is the combination of mechanisms, rather
than the single mechanism, which must provide financial responsibility
for an amount at least equal to the current cost estimate.
(ii) When using a third-party instrument to demonstrate financial
responsibility, the owner or operator must provide a proof that the
third-party providers either have passed financial strength
requirements based on credit ratings; or has met a minimum rating,
minimum capitalization, and ability to pass the bond rating when
applicable.
(iii) An owner or operator using certain types of third-party
instruments must establish a standby trust to enable EPA to be party to
the financial responsibility agreement without EPA being the
beneficiary of any funds. The standby trust fund must be used along
with other financial responsibility instruments (e.g., surety bonds,
letters of credit, or escrow accounts) to provide a location to place
funds if needed.
(iv) An owner or operator may deposit money to an escrow account to
cover financial responsibility requirements; this account must
segregate funds sufficient to cover estimated costs for Class VI
(geologic sequestration) financial responsibility from other accounts
and uses.
(v) An owner or operator or its guarantor may use self insurance to
demonstrate financial responsibility for geologic sequestration
projects. In order to satisfy this requirement the owner or operator
must meet a Tangible Net Worth of an amount approved by the Director,
have a Net working capital and tangible net worth each at least six
times the sum of the current well plugging, post injection site care
and site closure cost, have assets located in the United States
amounting to at least 90 percent of total assets or at least six times
the sum of the current well plugging, post injection site care and site
closure cost, and must submit a report of its bond rating and financial
information annually. In addition the owner or operator must either:
Have a bond rating test of AAA, AA, A, or BBB as issued by Standard &
Poor's or Aaa, Aa, A, or Baa as issued by Moody's; or meet all of the
following five financial ratio thresholds: A ratio of total liabilities
to net worth less than 2.0; a ratio of current assets to current
liabilities greater than 1.5; a ratio of the sum of net income plus
depreciation, depletion, and amortization to total liabilities greater
than 0.1; A ratio of current assets minus current liabilities to total
assets greater than -0.1; and a net profit (revenues minus expenses)
greater than 0.
(vi) An owner or operator who is not able to meet corporate
financial test criteria may arrange a corporate guarantee by
demonstrating that its corporate parent meets the financial test
requirements on its behalf. The parent's demonstration that it meets
the financial test requirement is insufficient if it has not also
guaranteed to fulfill the obligations for the owner or operator.
(vii) An owner or operator may obtain an insurance policy to cover
the estimated costs of geologic sequestration activities requiring
financial responsibility. This insurance policy must be obtained from a
third party provider.
(b) The requirement to maintain adequate financial responsibility
and resources is directly enforceable regardless of whether the
requirement is a condition of the permit.
(1) The owner or operator must maintain financial responsibility
and resources until:
(i) The Director receives and approves the completed post-injection
site care and site closure plan; and
(ii) The Director approves site closure.
(2) The owner or operator may be released from a financial
instrument in the following circumstances:
(i) The owner or operator has completed the phase of the geologic
sequestration project for which the financial instrument was required
and has fulfilled all its financial obligations as determined by the
Director, including obtaining financial responsibility for the next
phase of the GS project, if required; or
(ii) The owner or operator has submitted a replacement financial
instrument and received written approval from the Director accepting
the new financial instrument and releasing the owner or operator from
the previous financial instrument.
(c) The owner or operator must have a detailed written estimate, in
current dollars, of the cost of performing corrective action on wells
in the area of review, plugging the injection well(s), post-injection
site care and site closure, and emergency and remedial response.
(1) The cost estimate must be performed for each phase separately
and must be based on the costs to the regulatory agency of hiring a
third party to perform the required activities. A third party is a
party who is not within the corporate structure of the owner or
operator.
(2) During the active life of the geologic sequestration project,
the
[[Page 77296]]
owner or operator must adjust the cost estimate for inflation within 60
days prior to the anniversary date of the establishment of the
financial instrument(s) used to comply with paragraph (a) of this
section and provide this adjustment to the Director. The owner or
operator must also provide to the Director written updates of
adjustments to the cost estimate within 60 days of any amendments to
the area of review and corrective action plan (Sec. 146.84), the
injection well plugging plan (Sec. 146.92), the post-injection site
care and site closure plan (Sec. 146.93), and the emergency and
remedial response plan (Sec. 146.94).
(3) The Director must approve any decrease or increase to the
initial cost estimate. During the active life of the geologic
sequestration project, the owner or operator must revise the cost
estimate no later than 60 days after the Director has approved the
request to modify the area of review and corrective action plan (Sec.
146.84), the injection well plugging plan (Sec. 146.92), the post-
injection site care and site closure plan (Sec. 146.93), and the
emergency and response plan (Sec. 146.94), if the change in the plan
increases the cost. If the change to the plans decreases the cost, any
withdrawal of funds must be approved by the Director. Any decrease to
the value of the financial assurance instrument must first be approved
by the Director. The revised cost estimate must be adjusted for
inflation as specified at paragraph (c)(2) of this section.
(4) Whenever the current cost estimate increases to an amount
greater than the face amount of a financial instrument currently in
use, the owner or operator, within 60 days after the increase, must
either cause the face amount to be increased to an amount at least
equal to the current cost estimate and submit evidence of such increase
to the Director, or obtain other financial responsibility instruments
to cover the increase. Whenever the current cost estimate decreases,
the face amount of the financial assurance instrument may be reduced to
the amount of the current cost estimate only after the owner or
operator has received written approval from the Director.
(d) The owner or operator must notify the Director by certified
mail of adverse financial conditions such as bankruptcy that may affect
the ability to carry out injection well plugging and post-injection
site care and site closure.
(1) In the event that the owner or operator or the third party
provider of a financial responsibility instrument is going through a
bankruptcy, the owner or operator must notify the Director by certified
mail of the commencement of a voluntary or involuntary proceeding under
Title 11 (Bankruptcy), U.S. Code, naming the owner or operator as
debtor, within 10 days after commencement of the proceeding.
(2) A guarantor of a corporate guarantee must make such a
notification to the Director if he/she is named as debtor, as required
under the terms of the corporate guarantee.
(3) An owner or operator who fulfills the requirements of paragraph
(a) of this section by obtaining a trust fund, surety bond, letter of
credit, escrow account, or insurance policy will be deemed to be
without the required financial assurance in the event of bankruptcy of
the trustee or issuing institution, or a suspension or revocation of
the authority of the trustee institution to act as trustee of the
institution issuing the trust fund, surety bond, letter of credit,
escrow account, or insurance policy. The owner or operator must
establish other financial assurance within 60 days after such an event.
(e) The owner or operator must provide an adjustment of the cost
estimate to the Director within 60 days of notification by the
Director, if the Director determines during the annual evaluation of
the qualifying financial responsibility instrument(s) that the most
recent demonstration is no longer adequate to cover the cost of
corrective action (as required by Sec. 146.84), injection well
plugging (as required by Sec. 146.92), post-injection site care and
site closure (as required by Sec. 146.93), and emergency and remedial
response (as required by Sec. 146.94).
(f) The Director must approve the use and length of pay-in-periods
for trust funds or escrow accounts.
Sec. 146.86 Injection well construction requirements.
(a) General. The owner or operator must ensure that all Class VI
wells are constructed and completed to:
(1) Prevent the movement of fluids into or between USDWs or into
any unauthorized zones;
(2) Permit the use of appropriate testing devices and workover
tools; and
(3) Permit continuous monitoring of the annulus space between the
injection tubing and long string casing.
(b) Casing and Cementing of Class VI Wells.
(1) Casing and cement or other materials used in the construction
of each Class VI well must have sufficient structural strength and be
designed for the life of the geologic sequestration project. All well
materials must be compatible with fluids with which the materials may
be expected to come into contact and must meet or exceed standards
developed for such materials by the American Petroleum Institute, ASTM
International, or comparable standards acceptable to the Director. The
casing and cementing program must be designed to prevent the movement
of fluids into or between USDWs. In order to allow the Director to
determine and specify casing and cementing requirements, the owner or
operator must provide the following information:
(i) Depth to the injection zone(s);
(ii) Injection pressure, external pressure, internal pressure, and
axial loading;
(iii) Hole size;
(iv) Size and grade of all casing strings (wall thickness, external
diameter, nominal weight, length, joint specification, and construction
material);
(v) Corrosiveness of the carbon dioxide stream and formation
fluids;
(vi) Down-hole temperatures;
(vii) Lithology of injection and confining zone(s);
(viii) Type or grade of cement and cement additives; and
(ix) Quantity, chemical composition, and temperature of the carbon
dioxide stream.
(2) Surface casing must extend through the base of the lowermost
USDW and be cemented to the surface through the use of a single or
multiple strings of casing and cement.
(3) At least one long string casing, using a sufficient number of
centralizers, must extend to the injection zone and must be cemented by
circulating cement to the surface in one or more stages.
(4) Circulation of cement may be accomplished by staging. The
Director may approve an alternative method of cementing in cases where
the cement cannot be recirculated to the surface, provided the owner or
operator can demonstrate by using logs that the cement does not allow
fluid movement behind the well bore.
(5) Cement and cement additives must be compatible with the carbon
dioxide stream and formation fluids and of sufficient quality and
quantity to maintain integrity over the design life of the geologic
sequestration project. The integrity and location of the cement shall
be verified using technology capable of evaluating cement quality
radially and identifying the location of channels to ensure that USDWs
are not endangered.
(c) Tubing and packer.
(1) Tubing and packer materials used in the construction of each
Class VI well must be compatible with fluids with which the materials
may be expected to come into contact and must meet or
[[Page 77297]]
exceed standards developed for such materials by the American Petroleum
Institute, ASTM International, or comparable standards acceptable to
the Director.
(2) All owners or operators of Class VI wells must inject fluids
through tubing with a packer set at a depth opposite a cemented
interval at the location approved by the Director.
(3) In order for the Director to determine and specify requirements
for tubing and packer, the owner or operator must submit the following
information:
(i) Depth of setting;
(ii) Characteristics of the carbon dioxide stream (chemical
content, corrosiveness, temperature, and density) and formation fluids;
(iii) Maximum proposed injection pressure;
(iv) Maximum proposed annular pressure;
(v) Proposed injection rate (intermittent or continuous) and volume
and/or mass of the carbon dioxide stream;
(vi) Size of tubing and casing; and
(vii) Tubing tensile, burst, and collapse strengths.
Sec. 146.87 Logging, sampling, and testing prior to injection well
operation.
(a) During the drilling and construction of a Class VI injection
well, the owner or operator must run appropriate logs, surveys and
tests to determine or verify the depth, thickness, porosity,
permeability, and lithology of, and the salinity of any formation
fluids in all relevant geologic formations to ensure conformance with
the injection well construction requirements under Sec. 146.86 and to
establish accurate baseline data against which future measurements may
be compared. The owner or operator must submit to the Director a
descriptive report prepared by a knowledgeable log analyst that
includes an interpretation of the results of such logs and tests. At a
minimum, such logs and tests must include:
(1) Deviation checks during drilling on all holes constructed by
drilling a pilot hole which is enlarged by reaming or another method.
Such checks must be at sufficiently frequent intervals to determine the
location of the borehole and to ensure that vertical avenues for fluid
movement in the form of diverging holes are not created during
drilling; and
(2) Before and upon installation of the surface casing:
(i) Resistivity, spontaneous potential, and caliper logs before the
casing is installed; and
(ii) A cement bond and variable density log to evaluate cement
quality radially, and a temperature log after the casing is set and
cemented.
(3) Before and upon installation of the long string casing:
(i) Resistivity, spontaneous potential, porosity, caliper, gamma
ray, fracture finder logs, and any other logs the Director requires for
the given geology before the casing is installed; and
(ii) A cement bond and variable density log, and a temperature log
after the casing is set and cemented.
(4) A series of tests designed to demonstrate the internal and
external mechanical integrity of injection wells, which may include:
(i) A pressure test with liquid or gas;
(ii) A tracer survey such as oxygen-activation logging;
(iii) A temperature or noise log;
(iv) A casing inspection log; and
(5) Any alternative methods that provide equivalent or better
information and that are required by and/or approved of by the
Director.
(b) The owner or operator must take whole cores or sidewall cores
of the injection zone and confining system and formation fluid samples
from the injection zone(s), and must submit to the Director a detailed
report prepared by a log analyst that includes: Well log analyses
(including well logs), core analyses, and formation fluid sample
information. The Director may accept information on cores from nearby
wells if the owner or operator can demonstrate that core retrieval is
not possible and that such cores are representative of conditions at
the well. The Director may require the owner or operator to core other
formations in the borehole.
(c) The owner or operator must record the fluid temperature, pH,
conductivity, reservoir pressure, and static fluid level of the
injection zone(s).
(d) At a minimum, the owner or operator must determine or calculate
the following information concerning the injection and confining
zone(s):
(1) Fracture pressure;
(2) Other physical and chemical characteristics of the injection
and confining zone(s); and
(3) Physical and chemical characteristics of the formation fluids
in the injection zone(s).
(e) Upon completion, but prior to operation, the owner or operator
must conduct the following tests to verify hydrogeologic
characteristics of the injection zone(s):
(1) A pressure fall-off test; and,
(2) A pump test; or
(3) Injectivity tests.
(f) The owner or operator must provide the Director with the
opportunity to witness all logging and testing by this subpart. The
owner or operator must submit a schedule of such activities to the
Director 30 days prior to conducting the first test and submit any
changes to the schedule 30 days prior to the next scheduled test.
Sec. 146.88 Injection well operating requirements.
(a) Except during stimulation, the owner or operator must ensure
that injection pressure does not exceed 90 percent of the fracture
pressure of the injection zone(s) so as to ensure that the injection
does not initiate new fractures or propagate existing fractures in the
injection zone(s). In no case may injection pressure initiate fractures
in the confining zone(s) or cause the movement of injection or
formation fluids that endangers a USDW. Pursuant to requirements at
Sec. 146.82(a)(9), all stimulation programs must be approved by the
Director as part of the permit application and incorporated into the
permit.
(b) Injection between the outermost casing protecting USDWs and the
well bore is prohibited.
(c) The owner or operator must fill the annulus between the tubing
and the long string casing with a non-corrosive fluid approved by the
Director. The owner or operator must maintain on the annulus a pressure
that exceeds the operating injection pressure, unless the Director
determines that such requirement might harm the integrity of the well
or endanger USDWs.
(d) Other than during periods of well workover (maintenance)
approved by the Director in which the sealed tubing-casing annulus is
disassembled for maintenance or corrective procedures, the owner or
operator must maintain mechanical integrity of the injection well at
all times.
(e) The owner or operator must install and use:
(1) Continuous recording devices to monitor: The injection
pressure; the rate, volume and/or mass, and temperature of the carbon
dioxide stream; and the pressure on the annulus between the tubing and
the long string casing and annulus fluid volume; and
(2) Alarms and automatic surface shut-off systems or, at the
discretion of the Director, down-hole shut-off systems (e.g., automatic
shut-off, check valves) for onshore wells or, other mechanical devices
that provide equivalent protection; and
(3) Alarms and automatic down-hole shut-off systems for wells
located offshore but within State territorial waters, designed to alert
the operator and shut-in the well when operating parameters such as
annulus pressure,
[[Page 77298]]
injection rate, or other parameters diverge beyond permitted ranges
and/or gradients specified in the permit.
(f) If a shutdown (i.e., down-hole or at the surface) is triggered
or a loss of mechanical integrity is discovered, the owner or operator
must immediately investigate and identify as expeditiously as possible
the cause of the shutoff. If, upon such investigation, the well appears
to be lacking mechanical integrity, or if monitoring required under
paragraph (e) of this section otherwise indicates that the well may be
lacking mechanical integrity, the owner or operator must:
(1) Immediately cease injection;
(2) Take all steps reasonably necessary to determine whether there
may have been a release of the injected carbon dioxide stream or
formation fluids into any unauthorized zone;
(3) Notify the Director within 24 hours;
(4) Restore and demonstrate mechanical integrity to the
satisfaction of the Director prior to resuming injection; and
(5) Notify the Director when injection can be expected to resume.
Sec. 146.89 Mechanical integrity.
(a) A Class VI well has mechanical integrity if:
(1) There is no significant leak in the casing, tubing, or packer;
and
(2) There is no significant fluid movement into a USDW through
channels adjacent to the injection well bore.
(b) To evaluate the absence of significant leaks under paragraph
(a)(1) of this section, owners or operators must, following an initial
annulus pressure test, continuously monitor injection pressure, rate,
injected volumes; pressure on the annulus between tubing and long-
string casing; and annulus fluid volume as specified in Sec. 146.88
(e);
(c) At least once per year, the owner or operator must use one of
the following methods to determine the absence of significant fluid
movement under paragraph (a)(2) of this section:
(1) An approved tracer survey such as an oxygen-activation log; or
(2) A temperature or noise log.
(d) If required by the Director, at a frequency specified in the
testing and monitoring plan required at Sec. 146.90, the owner or
operator must run a casing inspection log to determine the presence or
absence of corrosion in the long-string casing.
(e) The Director may require any other test to evaluate mechanical
integrity under paragraphs (a)(1) or (a)(2) of this section. Also, the
Director may allow the use of a test to demonstrate mechanical
integrity other than those listed above with the written approval of
the Administrator. To obtain approval for a new mechanical integrity
test, the Director must submit a written request to the Administrator
setting forth the proposed test and all technical data supporting its
use. The Administrator may approve the request if he or she determines
that it will reliably demonstrate the mechanical integrity of wells for
which its use is proposed. Any alternate method approved by the
Administrator will be published in the Federal Register and may be used
in all States in accordance with applicable State law unless its use is
restricted at the time of approval by the Administrator.
(f) In conducting and evaluating the tests enumerated in this
section or others to be allowed by the Director, the owner or operator
and the Director must apply methods and standards generally accepted in
the industry. When the owner or operator reports the results of
mechanical integrity tests to the Director, he/she shall include a
description of the test(s) and the method(s) used. In making his/her
evaluation, the Director must review monitoring and other test data
submitted since the previous evaluation.
(g) The Director may require additional or alternative tests if the
results presented by the owner or operator under paragraphs (a) through
(d) of this section are not satisfactory to the Director to demonstrate
that there is no significant leak in the casing, tubing, or packer, or
to demonstrate that there is no significant movement of fluid into a
USDW resulting from the injection activity as stated in paragraphs
(a)(1) and (2) of this section.
Sec. 146.90 Testing and monitoring requirements.
The owner or operator of a Class VI well must prepare, maintain,
and comply with a testing and monitoring plan to verify that the
geologic sequestration project is operating as permitted and is not
endangering USDWs. The requirement to maintain and implement an
approved plan is directly enforceable regardless of whether the
requirement is a condition of the permit. The testing and monitoring
plan must be submitted with the permit application, for Director
approval, and must include a description of how the owner or operator
will meet the requirements of this section, including accessing sites
for all necessary monitoring and testing during the life of the
project. Testing and monitoring associated with geologic sequestration
projects must, at a minimum, include:
(a) Analysis of the carbon dioxide stream with sufficient frequency
to yield data representative of its chemical and physical
characteristics;
(b) Installation and use, except during well workovers as defined
in Sec. 146.88(d), of continuous recording devices to monitor
injection pressure, rate, and volume; the pressure on the annulus
between the tubing and the long string casing; and the annulus fluid
volume added;
(c) Corrosion monitoring of the well materials for loss of mass,
thickness, cracking, pitting, and other signs of corrosion, which must
be performed on a quarterly basis to ensure that the well components
meet the minimum standards for material strength and performance set
forth in Sec. 146.86(b), by:
(1) Analyzing coupons of the well construction materials placed in
contact with the carbon dioxide stream; or
(2) Routing the carbon dioxide stream through a loop constructed
with the material used in the well and inspecting the materials in the
loop; or
(3) Using an alternative method approved by the Director;
(d) Periodic monitoring of the ground water quality and geochemical
changes above the confining zone(s) that may be a result of carbon
dioxide movement through the confining zone(s) or additional identified
zones including:
(1) The location and number of monitoring wells based on specific
information about the geologic sequestration project, including
injection rate and volume, geology, the presence of artificial
penetrations, and other factors; and
(2) The monitoring frequency and spatial distribution of monitoring
wells based on baseline geochemical data that has been collected under
Sec. 146.82(a)(6) and on any modeling results in the area of review
evaluation required by Sec. 146.84(c).
(e) A demonstration of external mechanical integrity pursuant to
Sec. 146.89(c) at least once per year until the injection well is
plugged; and, if required by the Director, a casing inspection log
pursuant to requirements at Sec. 146.89(d) at a frequency established
in the testing and monitoring plan;
(f) A pressure fall-off test at least once every five years unless
more frequent testing is required by the Director based on site-
specific information;
(g) Testing and monitoring to track the extent of the carbon
dioxide plume and the presence or absence of elevated pressure (e.g.,
the pressure front) by using:
[[Page 77299]]
(1) Direct methods in the injection zone(s); and,
(2) Indirect methods (e.g., seismic, electrical, gravity, or
electromagnetic surveys and/or down-hole carbon dioxide detection
tools), unless the Director determines, based on site-specific geology,
that such methods are not appropriate;
(h) The Director may require surface air monitoring and/or soil gas
monitoring to detect movement of carbon dioxide that could endanger a
USDW.
(1) Design of Class VI surface air and/or soil gas monitoring must
be based on potential risks to USDWs within the area of review;
(2) The monitoring frequency and spatial distribution of surface
air monitoring and/or soil gas monitoring must be decided using
baseline data, and the monitoring plan must describe how the proposed
monitoring will yield useful information on the area of review
delineation and/or compliance with standards under Sec. 144.12 of this
chapter;
(3) If an owner or operator demonstrates that monitoring employed
under Sec. Sec. 98.440 to 98.449 of this chapter (Clean Air Act, 42
U.S.C. 7401 et seq.) accomplishes the goals of paragraphs (h)(1) and
(2) of this section, and meets the requirements pursuant to Sec.
146.91(c)(5), a Director that requires surface air/soil gas monitoring
must approve the use of monitoring employed under Sec. Sec. 98.440 to
98.449 of this chapter. Compliance with Sec. Sec. 98.440 to 98.449 of
this chapter pursuant to this provision is considered a condition of
the Class VI permit;
(i) Any additional monitoring, as required by the Director,
necessary to support, upgrade, and improve computational modeling of
the area of review evaluation required under Sec. 146.84(c) and to
determine compliance with standards under Sec. 144.12 of this chapter;
(j) The owner or operator shall periodically review the testing and
monitoring plan to incorporate monitoring data collected under this
subpart, operational data collected under Sec. 146.88, and the most
recent area of review reevaluation performed under Sec. 146.84(e). In
no case shall the owner or operator review the testing and monitoring
plan less often than once every five years. Based on this review, the
owner or operator shall submit an amended testing and monitoring plan
or demonstrate to the Director that no amendment to the testing and
monitoring plan is needed. Any amendments to the testing and monitoring
plan must be approved by the Director, must be incorporated into the
permit, and are subject to the permit modification requirements at
Sec. Sec. 144.39 or 144.41 of this chapter, as appropriate. Amended
plans or demonstrations shall be submitted to the Director as follows:
(1) Within one year of an area of review reevaluation;
(2) Following any significant changes to the facility, such as
addition of monitoring wells or newly permitted injection wells within
the area of review, on a schedule determined by the Director; or
(3) When required by the Director.
(k) A quality assurance and surveillance plan for all testing and
monitoring requirements.
Sec. 146.91 Reporting requirements.
The owner or operator must, at a minimum, provide, as specified in
paragraph (e) of this section, the following reports to the Director,
for each permitted Class VI well:
(a) Semi-annual reports containing:
(1) Any changes to the physical, chemical, and other relevant
characteristics of the carbon dioxide stream from the proposed
operating data;
(2) Monthly average, maximum, and minimum values for injection
pressure, flow rate and volume, and annular pressure;
(3) A description of any event that exceeds operating parameters
for annulus pressure or injection pressure specified in the permit;
(4) A description of any event which triggers a shut-off device
required pursuant to Sec. 146.88(e) and the response taken;
(5) The monthly volume and/or mass of the carbon dioxide stream
injected over the reporting period and the volume injected cumulatively
over the life of the project;
(6) Monthly annulus fluid volume added; and
(7) The results of monitoring prescribed under Sec. 146.90.
(b) Report, within 30 days, the results of:
(1) Periodic tests of mechanical integrity;
(2) Any well workover; and,
(3) Any other test of the injection well conducted by the permittee
if required by the Director.
(c) Report, within 24 hours:
(1) Any evidence that the injected carbon dioxide stream or
associated pressure front may cause an endangerment to a USDW;
(2) Any noncompliance with a permit condition, or malfunction of
the injection system, which may cause fluid migration into or between
USDWs;
(3) Any triggering of a shut-off system (i.e., down-hole or at the
surface);
(4) Any failure to maintain mechanical integrity; or.
(5) Pursuant to compliance with the requirement at Sec. 146.90(h)
for surface air/soil gas monitoring or other monitoring technologies,
if required by the Director, any release of carbon dioxide to the
atmosphere or biosphere.
(d) Owners or operators must notify the Director in writing 30 days
in advance of:
(1) Any planned well workover;
(2) Any planned stimulation activities, other than stimulation for
formation testing conducted under Sec. 146.82; and
(3) Any other planned test of the injection well conducted by the
permittee.
(e) Regardless of whether a State has primary enforcement
responsibility, owners or operators must submit all required reports,
submittals, and notifications under subpart H of this part to EPA in an
electronic format approved by EPA.
(f) Records shall be retained by the owner or operator as follows:
(1) All data collected under Sec. 146.82 for Class VI permit
applications shall be retained throughout the life of the geologic
sequestration project and for 10 years following site closure.
(2) Data on the nature and composition of all injected fluids
collected pursuant to Sec. 146.90(a) shall be retained until 10 years
after site closure. The Director may require the owner or operator to
deliver the records to the Director at the conclusion of the retention
period.
(3) Monitoring data collected pursuant to Sec. 146.90(b) through
(i) shall be retained for 10 years after it is collected.
(4) Well plugging reports, post-injection site care data,
including, if appropriate, data and information used to develop the
demonstration of the alternative post-injection site care timeframe,
and the site closure report collected pursuant to requirements at
Sec. Sec. 146.93(f) and (h) shall be retained for 10 years following
site closure.
(5) The Director has authority to require the owner or operator to
retain any records required in this subpart for longer than 10 years
after site closure.
Sec. 146.92 Injection well plugging.
(a) Prior to the well plugging, the owner or operator must flush
each Class VI injection well with a buffer fluid, determine bottomhole
reservoir pressure, and perform a final external mechanical integrity
test.
(b) Well plugging plan. The owner or operator of a Class VI well
must prepare, maintain, and comply with a plan that
[[Page 77300]]
is acceptable to the Director. The requirement to maintain and
implement an approved plan is directly enforceable regardless of
whether the requirement is a condition of the permit. The well plugging
plan must be submitted as part of the permit application and must
include the following information:
(1) Appropriate tests or measures for determining bottomhole
reservoir pressure;
(2) Appropriate testing methods to ensure external mechanical
integrity as specified in Sec. 146.89;
(3) The type and number of plugs to be used;
(4) The placement of each plug, including the elevation of the top
and bottom of each plug;
(5) The type, grade, and quantity of material to be used in
plugging. The material must be compatible with the carbon dioxide
stream; and
(6) The method of placement of the plugs.
(c) Notice of intent to plug. The owner or operator must notify the
Director in writing pursuant to Sec. 146.91(e), at least 60 days
before plugging of a well. At this time, if any changes have been made
to the original well plugging plan, the owner or operator must also
provide the revised well plugging plan. The Director may allow for a
shorter notice period. Any amendments to the injection well plugging
plan must be approved by the Director, must be incorporated into the
permit, and are subject to the permit modification requirements at
Sec. Sec. 144.39 or 144.41 of this chapter, as appropriate.
(d) Plugging report. Within 60 days after plugging, the owner or
operator must submit, pursuant to Sec. 146.91(e), a plugging report to
the Director. The report must be certified as accurate by the owner or
operator and by the person who performed the plugging operation (if
other than the owner or operator.) The owner or operator shall retain
the well plugging report for 10 years following site closure.
Sec. 146.93 Post-injection site care and site closure.
(a) The owner or operator of a Class VI well must prepare,
maintain, and comply with a plan for post-injection site care and site
closure that meets the requirements of paragraph (a)(2) of this section
and is acceptable to the Director. The requirement to maintain and
implement an approved plan is directly enforceable regardless of
whether the requirement is a condition of the permit.
(1) The owner or operator must submit the post-injection site care
and site closure plan as a part of the permit application to be
approved by the Director.
(2) The post-injection site care and site closure plan must include
the following information:
(i) The pressure differential between pre-injection and predicted
post-injection pressures in the injection zone(s);
(ii) The predicted position of the carbon dioxide plume and
associated pressure front at site closure as demonstrated in the area
of review evaluation required under Sec. 146.84(c)(1);
(iii) A description of post-injection monitoring location, methods,
and proposed frequency;
(iv) A proposed schedule for submitting post-injection site care
monitoring results to the Director pursuant to Sec. 146.91(e); and,
(v) The duration of the post-injection site care timeframe and, if
approved by the Director, the demonstration of the alternative post-
injection site care timeframe that ensures non-endangerment of USDWs.
(3) Upon cessation of injection, owners or operators of Class VI
wells must either submit an amended post-injection site care and site
closure plan or demonstrate to the Director through monitoring data and
modeling results that no amendment to the plan is needed. Any
amendments to the post-injection site care and site closure plan must
be approved by the Director, be incorporated into the permit, and are
subject to the permit modification requirements at Sec. Sec. 144.39 or
144.41 of this chapter, as appropriate.
(4) At any time during the life of the geologic sequestration
project, the owner or operator may modify and resubmit the post-
injection site care and site closure plan for the Director's approval
within 30 days of such change.
(b) The owner or operator shall monitor the site following the
cessation of injection to show the position of the carbon dioxide plume
and pressure front and demonstrate that USDWs are not being endangered.
(1) Following the cessation of injection, the owner or operator
shall continue to conduct monitoring as specified in the Director-
approved post-injection site care and site closure plan for at least 50
years or for the duration of the alternative timeframe approved by the
Director pursuant to requirements in paragraph (c) of this section,
unless he/she makes a demonstration under (b)(2) of this section. The
monitoring must continue until the geologic sequestration project no
longer poses an endangerment to USDWs and the demonstration under
(b)(2) of this section is submitted and approved by the Director.
(2) If the owner or operator can demonstrate to the satisfaction of
the Director before 50 years or prior to the end of the approved
alternative timeframe based on monitoring and other site-specific data,
that the geologic sequestration project no longer poses an endangerment
to USDWs, the Director may approve an amendment to the post-injection
site care and site closure plan to reduce the frequency of monitoring
or may authorize site closure before the end of the 50-year period or
prior to the end of the approved alternative timeframe, where he or she
has substantial evidence that the geologic sequestration project no
longer poses a risk of endangerment to USDWs.
(3) Prior to authorization for site closure, the owner or operator
must submit to the Director for review and approval a demonstration,
based on monitoring and other site-specific data, that no additional
monitoring is needed to ensure that the geologic sequestration project
does not pose an endangerment to USDWs.
(4) If the demonstration in paragraph (b)(3) of this section cannot
be made (i.e., additional monitoring is needed to ensure that the
geologic sequestration project does not pose an endangerment to USDWs)
at the end of the 50-year period or at the end of the approved
alternative timeframe, or if the Director does not approve the
demonstration, the owner or operator must submit to the Director a plan
to continue post-injection site care until a demonstration can be made
and approved by the Director.
(c) Demonstration of alternative post-injection site care
timeframe. At the Director's discretion, the Director may approve, in
consultation with EPA, an alternative post-injection site care
timeframe other than the 50 year default, if an owner or operator can
demonstrate during the permitting process that an alternative post-
injection site care timeframe is appropriate and ensures non-
endangerment of USDWs. The demonstration must be based on significant,
site-specific data and information including all data and information
collected pursuant to Sec. Sec. 146.82 and 146.83, and must contain
substantial evidence that the geologic sequestration project will no
longer pose a risk of endangerment to USDWs at the end of the
alternative post-injection site care timeframe.
(1) A demonstration of an alternative post-injection site care
timeframe must include consideration and documentation of:
[[Page 77301]]
(i) The results of computational modeling performed pursuant to
delineation of the area of review under Sec. 146.84;
(ii) The predicted timeframe for pressure decline within the
injection zone, and any other zones, such that formation fluids may not
be forced into any USDWs; and/or the timeframe for pressure decline to
pre-injection pressures;
(iii) The predicted rate of carbon dioxide plume migration within
the injection zone, and the predicted timeframe for the cessation of
migration;
(iv) A description of the site-specific processes that will result
in carbon dioxide trapping including immobilization by capillary
trapping, dissolution, and mineralization at the site;
(v) The predicted rate of carbon dioxide trapping in the immobile
capillary phase, dissolved phase, and/or mineral phase;
(vi) The results of laboratory analyses, research studies, and/or
field or site-specific studies to verify the information required in
paragraphs (iv) and (v) of this section;
(vii) A characterization of the confining zone(s) including a
demonstration that it is free of transmissive faults, fractures, and
micro-fractures and of appropriate thickness, permeability, and
integrity to impede fluid (e.g., carbon dioxide, formation fluids)
movement;
(viii) The presence of potential conduits for fluid movement
including planned injection wells and project monitoring wells
associated with the proposed geologic sequestration project or any
other projects in proximity to the predicted/modeled, final extent of
the carbon dioxide plume and area of elevated pressure;
(ix) A description of the well construction and an assessment of
the quality of plugs of all abandoned wells within the area of review;
(x) The distance between the injection zone and the nearest USDWs
above and/or below the injection zone; and
(xi) Any additional site-specific factors required by the Director.
(2) Information submitted to support the demonstration in paragraph
(c)(1) of this section must meet the following criteria:
(i) All analyses and tests performed to support the demonstration
must be accurate, reproducible, and performed in accordance with the
established quality assurance standards;
(ii) Estimation techniques must be appropriate and EPA-certified
test protocols must be used where available;
(iii) Predictive models must be appropriate and tailored to the
site conditions, composition of the carbon dioxide stream and injection
and site conditions over the life of the geologic sequestration
project;
(iv) Predictive models must be calibrated using existing
information (e.g., at Class I, Class II, or Class V experimental
technology well sites) where sufficient data are available;
(v) Reasonably conservative values and modeling assumptions must be
used and disclosed to the Director whenever values are estimated on the
basis of known, historical information instead of site-specific
measurements;
(vi) An analysis must be performed to identify and assess aspects
of the alternative post-injection site care timeframe demonstration
that contribute significantly to uncertainty. The owner or operator
must conduct sensitivity analyses to determine the effect that
significant uncertainty may contribute to the modeling demonstration.
(vii) An approved quality assurance and quality control plan must
address all aspects of the demonstration; and,
(viii) Any additional criteria required by the Director.
(d) Notice of intent for site closure. The owner or operator must
notify the Director in writing at least 120 days before site closure.
At this time, if any changes have been made to the original post-
injection site care and site closure plan, the owner or operator must
also provide the revised plan. The Director may allow for a shorter
notice period.
(e) After the Director has authorized site closure, the owner or
operator must plug all monitoring wells in a manner which will not
allow movement of injection or formation fluids that endangers a USDW.
(f) The owner or operator must submit a site closure report to the
Director within 90 days of site closure, which must thereafter be
retained at a location designated by the Director for 10 years. The
report must include:
(1) Documentation of appropriate injection and monitoring well
plugging as specified in Sec. 146.92 and paragraph (e) of this
section. The owner or operator must provide a copy of a survey plat
which has been submitted to the local zoning authority designated by
the Director. The plat must indicate the location of the injection well
relative to permanently surveyed benchmarks. The owner or operator must
also submit a copy of the plat to the Regional Administrator of the
appropriate EPA Regional Office;
(2) Documentation of appropriate notification and information to
such State, local and Tribal authorities that have authority over
drilling activities to enable such State, local, and Tribal authorities
to impose appropriate conditions on subsequent drilling activities that
may penetrate the injection and confining zone(s); and
(3) Records reflecting the nature, composition, and volume of the
carbon dioxide stream.
(g) Each owner or operator of a Class VI injection well 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 any potential purchaser of the property the following
information:
(1) The fact that land has been used to sequester carbon dioxide;
(2) The name of the State agency, local authority, and/or Tribe
with which the survey plat was filed, as well as the address of the
Environmental Protection Agency Regional Office to which it was
submitted; and
(3) The volume of fluid injected, the injection zone or zones into
which it was injected, and the period over which injection occurred.
(h) The owner or operator must retain for 10 years following site
closure, records collected during the post-injection site care period.
The owner or operator must deliver the records to the Director at the
conclusion of the retention period, and the records must thereafter be
retained at a location designated by the Director for that purpose.
Sec. 146.94 Emergency and remedial response.
(a) As part of the permit application, the owner or operator must
provide the Director with an emergency and remedial response plan that
describes actions the owner or operator must take to address movement
of the injection or formation fluids that may cause an endangerment to
a USDW during construction, operation, and post-injection site care
periods. The requirement to maintain and implement an approved plan is
directly enforceable regardless of whether the requirement is a
condition of the permit.
(b) If the owner or operator obtains evidence that the injected
carbon dioxide stream and associated pressure front may cause an
endangerment to a USDW, the owner or operator must:
(1) Immediately cease injection;
(2) Take all steps reasonably necessary to identify and
characterize any release;
(3) Notify the Director within 24 hours; and
(4) Implement the emergency and remedial response plan approved by
the Director.
[[Page 77302]]
(c) The Director may allow the operator to resume injection prior
to remediation if the owner or operator demonstrates that the injection
operation will not endanger USDWs.
(d) The owner or operator shall periodically review the emergency
and remedial response plan developed under paragraph (a) of this
section. In no case shall the owner or operator review the emergency
and remedial response plan less often than once every five years. Based
on this review, the owner or operator shall submit an amended emergency
and remedial response plan or demonstrate to the Director that no
amendment to the emergency and remedial response plan is needed. Any
amendments to the emergency and remedial response plan must be approved
by the Director, must be incorporated into the permit, and are subject
to the permit modification requirements at Sec. Sec. 144.39 or 144.41
of this chapter, as appropriate. Amended plans or demonstrations shall
be submitted to the Director as follows:
(1) Within one year of an area of review reevaluation;
(2) Following any significant changes to the facility, such as
addition of injection or monitoring wells, on a schedule determined by
the Director; or
(3) When required by the Director.
Sec. 146.95 Class VI injection depth waiver requirements.
This section sets forth information which an owner or operator
seeking a waiver of the Class VI injection depth requirements must
submit to the Director; information the Director must consider in
consultation with all affected Public Water System Supervision
Directors; the procedure for Director--Regional Administrator
communication and waiver issuance; and the additional requirements that
apply to owners or operators of Class VI wells granted a waiver of the
injection depth requirements.
(a) In seeking a waiver of the requirement to inject below the
lowermost USDW, the owner or operator must submit a supplemental report
concurrent with permit application. The supplemental report must
include the following,
(1) A demonstration that the injection zone(s) is/are laterally
continuous, is not a USDW, and is not hydraulically connected to USDWs;
does not outcrop; has adequate injectivity, volume, and sufficient
porosity to safely contain the injected carbon dioxide and formation
fluids; and has appropriate geochemistry.
(2) A demonstration that the injection zone(s) is/are bounded by
laterally continuous, impermeable confining units above and below the
injection zone(s) adequate to prevent fluid movement and pressure
buildup outside of the injection zone(s); and that the confining
unit(s) is/are free of transmissive faults and fractures. The report
shall further characterize the regional fracture properties and contain
a demonstration that such fractures will not interfere with injection,
serve as conduits, or endanger USDWs.
(3) A demonstration, using computational modeling, that USDWs above
and below the injection zone will not be endangered as a result of
fluid movement. This modeling should be conducted in conjunction with
the area of review determination, as described in Sec. 146.84, and is
subject to requirements, as described in Sec. 146.84(c), and periodic
reevaluation, as described in Sec. 146.84(e).
(4) A demonstration that well design and construction, in
conjunction with the waiver, will ensure isolation of the injectate in
lieu of requirements at 146.86(a)(1) and will meet well construction
requirements in paragraph (f) of this section.
(5) A description of how the monitoring and testing and any
additional plans will be tailored to the geologic sequestration project
to ensure protection of USDWs above and below the injection zone(s), if
a waiver is granted.
(6) Information on the location of all the public water supplies
affected, reasonably likely to be affected, or served by USDWs in the
area of review.
(7) Any other information requested by the Director to inform the
Regional Administrator's decision to issue a waiver.
(b) To inform the Regional Administrator's decision on whether to
grant a waiver of the injection depth requirements at Sec. Sec. 144.6
of this chapter, 146.5(f), and 146.86(a)(1), the Director must submit,
to the Regional Administrator, documentation of the following:
(1) An evaluation of the following information as it relates to
siting, construction, and operation of a geologic sequestration project
with a waiver:
(i) The integrity of the upper and lower confining units;
(ii) The suitability of the injection zone(s) (e.g., lateral
continuity; lack of transmissive faults and fractures; knowledge of
current or planned artificial penetrations into the injection zone(s)
or formations below the injection zone);
(iii) The potential capacity of the geologic formation(s) to
sequester carbon dioxide, accounting for the availability of
alternative injection sites;
(iv) All other site characterization data, the proposed emergency
and remedial response plan, and a demonstration of financial
responsibility;
(v) Community needs, demands, and supply from drinking water
resources;
(vi) Planned needs, potential and/or future use of USDWs and non-
USDWs in the area;
(vii) Planned or permitted water, hydrocarbon, or mineral resource
exploitation potential of the proposed injection formation(s) and other
formations both above and below the injection zone to determine if
there are any plans to drill through the formation to access resources
in or beneath the proposed injection zone(s)/formation(s);
(viii) The proposed plan for securing alternative resources or
treating USDW formation waters in the event of contamination related to
the Class VI injection activity; and,
(ix) Any other applicable considerations or information requested
by the Director.
(2) Consultation with the Public Water System Supervision Directors
of all States and Tribes having jurisdiction over lands within the area
of review of a well for which a waiver is sought.
(3) Any written waiver-related information submitted by the Public
Water System Supervision Director(s) to the (UIC) Director.
(c) Pursuant to requirements at Sec. 124.10 of this chapter and
concurrent with the Class VI permit application notice process, the
Director shall give public notice that a waiver application has been
submitted. The notice shall clearly state:
(1) The depth of the proposed injection zone(s);
(2) The location of the injection well(s);
(3) The name and depth of all USDWs within the area of review;
(4) A map of the area of review;
(5) The names of any public water supplies affected, reasonably
likely to be affected, or served by USDWs in the area of review; and,
(6) The results of UIC-Public Water System Supervision consultation
required under paragraph (b)(2) of this section.
(d) Following public notice, the Director shall provide all
information received through the waiver application process to the
Regional Administrator. Based on the information provided, the Regional
Administrator shall provide written concurrence or non-concurrence
regarding waiver issuance.
(1) If the Regional Administrator determines that additional
information
[[Page 77303]]
is required to support a decision, the Director shall provide the
information. At his or her discretion, the Regional Administrator may
require that public notice of the new information be initiated.
(2) In no case shall a Director of a State-approved program issue a
waiver without receipt of written concurrence from the Regional
Administrator.
(e) If a waiver is issued, within 30 days of waiver issuance, EPA
shall post the following information on the Office of Water's Web site:
(1) The depth of the proposed injection zone(s);
(2) The location of the injection well(s);
(3) The name and depth of all USDWs within the area of review;
(4) A map of the area of review;
(5) The names of any public water supplies affected, reasonably
likely to be affected, or served by USDWs in the area of review; and
(6) The date of waiver issuance.
(f) Upon receipt of a waiver of the requirement to inject below the
lowermost USDW for geologic sequestration, the owner or operator of the
Class VI well must comply with:
(1) All requirements at Sec. Sec. 146.84, 146.85, 146.87, 146.88,
146.89, 146.91, 146.92, and 146.94;
(2) All requirements at Sec. 146.86 with the following modified
requirements:
(i) The owner or operator must ensure that Class VI wells with a
waiver are constructed and completed to prevent movement of fluids into
any unauthorized zones including USDWs, in lieu of requirements at
Sec. 146.86(a)(1).
(ii) The casing and cementing program must be designed to prevent
the movement of fluids into any unauthorized zones including USDWs in
lieu of requirements at Sec. 146.86(b)(1).
(iii) The surface casing must extend through the base of the
nearest USDW directly above the injection zone and be cemented to the
surface; or, at the Director's discretion, another formation above the
injection zone and below the nearest USDW above the injection zone.
(3) All requirements at Sec. 146.90 with the following modified
requirements:
(i) The owner or operator shall monitor the groundwater quality,
geochemical changes, and pressure in the first USDWs immediately above
and below the injection zone(s); and in any other formations at the
discretion of the Director.
(ii) Testing and monitoring to track the extent of the carbon
dioxide plume and the presence or absence of elevated pressure (e.g.,
the pressure front) by using direct methods to monitor for pressure
changes in the injection zone(s); and, indirect methods (e.g., seismic,
electrical, gravity, or electromagnetic surveys and/or down-hole carbon
dioxide detection tools), unless the Director determines, based on
site-specific geology, that such methods are not appropriate.
(4) All requirements at Sec. 146.93 with the following, modified
post-injection site care monitoring requirements:
(i) The owner or operator shall monitor the groundwater quality,
geochemical changes and pressure in the first USDWs immediately above
and below the injection zone; and in any other formations at the
discretion of the Director.
(ii) Testing and monitoring to track the extent of the carbon
dioxide plume and the presence or absence of elevated pressure (e.g.,
the pressure front) by using direct methods in the injection zone(s);
and indirect methods (e.g., seismic, electrical, gravity, or
electromagnetic surveys and/or down-hole carbon dioxide detection
tools), unless the Director determines based on site-specific geology,
that such methods are not appropriate;
(5) Any additional requirements requested by the Director designed
to ensure protection of USDWs above and below the injection zone(s).
PART 147--STATE, TRIBAL, AND EPA-ADMINISTERED UNDERGROUND INJECTION
CONTROL PROGRAMS
0
33. The authority citation for part 147 continues to read as follows:
Authority: 42, U.S.C. 300f et seq.; 42 U.S.C. 6901 et seq.
0
34. Section 147.1 is amended by adding paragraph (f) to read as
follows:
Sec. 147.1 Purpose and scope.
* * * * *
(f) Class VI well owners or operators must comply with Sec.
146.91(e) notwithstanding any State program approvals.
[FR Doc. 2010-29954 Filed 12-9-10; 8:45 am]
BILLING CODE 6560-50-P