77230 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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, postinjection 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: 

bayer.maryrose@epa.gov. 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 § 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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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 

UICPG#83 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 § 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 Directorapproved 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 longterm 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 

mstockstill on DSKH9S0YB1PROD with RULES2

77232 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

at § 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 §§ 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 § 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 § 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°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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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 fossilfueled 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 organicrich 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 

mstockstill on DSKH9S0YB1PROD with RULES2

77234 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 (ßF) 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 (0.24ßF per 

decade) is almost double the rate of 

warming over the last 100 years (0.13ßF 

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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 77235 

1Reference to ‘‘States’’ includes Tribes and 

Territories pursuant to 40 CFR 144.3. 

2The Submerged Lands Act and Territorial 

Submerged Lands Act define the scope of territorial 

jurisdiction of States and Territories respectively. 

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 State1 UIC 

programs that regulate the subsurface 

injection of fluids onshore and offshore 

under submerged lands within the 

territorial jurisdiction of States2. 

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 

mstockstill on DSKH9S0YB1PROD with RULES2

77236 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 onsite .................................................................................................................... Yes ................... N/A. 

Quantity (flow rate) of CO2 injected .................................................................................................................. Yes ................... Yes. 

Fugitive and vented emissions from surface equipment ................................................................................... Yes ................... N/A. 

Quantity of CO2 produced with oil or natural gas (ER) ..................................................................................... Yes ................... N/A. 

Percent of CO2 estimated to remain with the oil and gas (ER) ........................................................................ Yes ................... N/A. 

Quantity of CO2 emitted from the subsurface ................................................................................................... Yes ................... N/A. 

Quantity of CO2 sequestered in the subsurface ............................................................................................... Yes ................... N/A. 

Cumulative mass of CO2 sequestered in the subsurface ................................................................................. Yes ................... N/A. 

Monitoring plan for detecting air emissions ....................................................................................................... Yes ................... Yes.1

Monitoring plan for quantifying air emissions .................................................................................................... Yes ................... N/A. 

(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-acomprehensive-Federal-strategy-carboncapture-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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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 

mstockstill on DSKH9S0YB1PROD with RULES2

77238 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 IllinoisUrbana); 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, 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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 multipurpose 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 coregulators 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. 

mstockstill on DSKH9S0YB1PROD with RULES2

77240 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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 

mstockstill on DSKH9S0YB1PROD with RULES2

77242 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 § 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 offfacility 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 § 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 § 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 

§ 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 §§ 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 Federallyenforceable requirements applicable to 

GS projects will be in place nationwide 

as soon as possible after rule 

finalization. Further, a clear, nationallyconsistent 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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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 repermitted 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 § 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 §§ 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 § 145.23(f) 

includes new language describing the 

requirements for Class VI State program 

descriptions. Specifically, § 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 § 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 § 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 

§ 146.81(c) within one year of December 

10, 2011. § 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 § 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 

§ 145.23 may help ensure expeditious 

implementation of Class VI 

requirements across the country. 

Today’s rule, at § 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 § 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 longterm 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 nonhazardous 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 

mstockstill on DSKH9S0YB1PROD with RULES2

77244 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 Stateapproved ground water remediation 

project. 

• Class V includes all injection wells 

that are not included in Classes I–IV. In 

general, Class V wells inject nonhazardous 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 § 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 reinjected), 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 longterm 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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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, riskbased 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, sitespecific 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 § 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 (§ 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 § 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 

§ 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 § 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 repermitted 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 § 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 § 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 nonexperimental GS operations under 

§ 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 

mstockstill on DSKH9S0YB1PROD with RULES2

77246 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 (§ 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 § 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 nonhazardous waste well specifications. In 

today’s final rule, at § 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 § 146.86(a) and ensure 

protection of USDWs from 

endangerment in lieu of requirements at 

§ 146.86(b) and § 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, § 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 longterm 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 § 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 

§ 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 (§ 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 (§ 146.82(a)) and 

information that must be submitted 

before well operation is authorized 

(§ 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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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 (§ 146.84(e), 

§ 146.90(j), and § 146.94(d)). Any 

significant changes to the plans require 

a permit modification (under 

§ 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 § 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 § 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 § 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 sitespecific 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 longstanding site characterization 

requirements of the UIC program, and 

are tailored to address the unique nature 

of GS. Specifically, § 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 

§ 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 § 146.83. 

Today’s rule at § 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 

(§ 146.83(b)). 

Today’s rule at § 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 

mstockstill on DSKH9S0YB1PROD with RULES2

77248 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 sitespecific 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 § 146.82 will be available at the time 

the operator develops their initial 

permit application. In response to 

comments, EPA revised § 146.82 so that 

the final regulation specifies separate 

requirements for information to be 

submitted with the permit application 

(§ 146.82(a)) and information that must 

be submitted before well operation is 

authorized (§ 146.82(c)). 

Today’s final rule includes 

requirements at § 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 § 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 (§ 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/StateTribal 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 § 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 sitespecific 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 § 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 (§ 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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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 § 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 § 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 

mstockstill on DSKH9S0YB1PROD with RULES2

77250 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 sitecharacterization 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 § 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 

§ 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 longstring 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 longstring 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 

§ 146.86(b) to provide owners or 

operators flexibility regarding how to 

complete the surface casing in situations 

where the cement cannot be recirculated to the surface. The regulation 

does not specify how the cementing 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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 § 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 degradationresistant 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/corrosionresistant 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 § 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 

§ 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 

§ 146.86(c) offers the best multiplebarrier 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 § 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 

mstockstill on DSKH9S0YB1PROD with RULES2

77252 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 §§ 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 § 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 § 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 § 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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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. 

mstockstill on DSKH9S0YB1PROD with RULES2

77254 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 

§ 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 nonUSDWs 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 § 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 § 146.82(a) 

for the site-specific characterization of 

geologic, hydrogeologic, geochemical, 

and geomechanical properties and 

§ 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 § 146.82(d) and 

outlined at § 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 

§ 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 § 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 § 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 

§ 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 § 146.95(c) and pursuant to 

requirements at § 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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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 § 146.95(c) requires 

the Director to provide the public with 

appropriate, site-specific and waiverspecific 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 

§ 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 § 146.95(d), the 

Regional Administrator will provide 

written concurrence or non-concurrence 

regarding waiver issuance. The 

requirements at § 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 § 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 § 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 § 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 

§ 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 § 146.95(a)), 

• Supplementing specific 

requirements that are not applicable due 

to the fact that certain Class VI 

requirements (e.g., at § 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 projectspecific 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 § 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 §§ 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 § 146.81(c). 

If an owner or operator applies for a 

Class VI permit to inject CO2 into a 

previously exempted aquifer (nonUSDW) that is located above and/or 

between USDWs, the permit applicant 

must also apply for a waiver of the 

injection depth requirements pursuant 

to § 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 

mstockstill on DSKH9S0YB1PROD with RULES2

77256 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 repermitted 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 

§ 144.7(b)(3). In addition, today’s rule 

requires that all such aquifer exemption 

expansion requests be treated as 

substantial program revisions under 

§ 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 sitespecific 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 

§ 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 § 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 § 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., § 144.12; 

§ 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 § 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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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 § 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 § 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 

(§ 146.88(a)). The calculated fracture 

pressure—and therefore, the injection 

pressure limit—are based on sitespecific 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 § 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 downhole 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 downhole 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 

mstockstill on DSKH9S0YB1PROD with RULES2

77258 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 

§ 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 downhole 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 § 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 downhole 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 § 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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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 § 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 lifespans. 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 

§ 146.90 incorporate elements of preexisting 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 sitecharacterization 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 

(§ 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 projectspecific 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 

mstockstill on DSKH9S0YB1PROD with RULES2

77260 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

their UIC permit application 

(§ 146.82(a)(7)), and throughout the 

operational life of the injection facility 

(§ 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 

§ 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 

§ 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 § 146.85). 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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 deepwell 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 § 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 

(§ 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 

(§ 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 § 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 § 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. 

mstockstill on DSKH9S0YB1PROD with RULES2

77262 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 § 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 § 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 § 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 § 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 § 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 sitespecific geology that such methods are 

not appropriate (§ 146.90(g)). 

The purpose of monitoring in the 

injection zone (§ 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 § 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, § 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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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 § 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 § 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 § 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 § 146.90(h) 

and an owner or operator demonstrates 

that monitoring employed under 

§§ 98.440 to 98.449 of subpart RR meets 

the requirements at § 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 

§ 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 

§ 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 

mstockstill on DSKH9S0YB1PROD with RULES2

77264 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

necessary based on review of projectspecific information submitted. 

The final rule, at § 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 § 1445(a)(1) of the SDWA, 

today’s final rule at § 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 § 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 § 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 § 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 coregulators. 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 § 146.91(e), 

information to the Director to support 

Class VI permit applications (this 

information is enumerated at § 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 § 146.91, requires 

owners or operators to submit project 

monitoring and operational data at 

varying intervals, including semiannually 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 (§ 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 (§ 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 

(§ 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 (§ 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 

§ 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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 77265 

believes that the reporting required at 

§ 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 postinjection 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 (§ 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 § 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 

§ 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 § 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 (§ 146.91(f)(5)). Well plugging 

reports, PISC data, and site closure 

reports must be kept for 10 years after 

site closure (§§ 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, semiannual 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 § 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 

mstockstill on DSKH9S0YB1PROD with RULES2

77266 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 § 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 § 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 § 146.92. The owners or 

operators must prepare and comply 

with a Director-approved injection well 

plugging plan submitted with their 

permit application (§ 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 (§ 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 § 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 

(§ 146.93) with an additional 

requirement at § 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 

§ 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 (§ 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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 77267 

reports, and existing environmental 

programs. In order to support sitespecific 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 sitespecific data, pursuant to requirements 

at § 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 § 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 § 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 § 146.93(c), 

affords the Director discretion to 

approve a demonstration during the 

permitting process (per requirements at 

§ 146.82(a)(18)) that an alternative postinjection 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 § 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 § 146.84) and 

information that supports the PISC and 

site closure plan development required 

at § 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 

§ 146.82(a)(3)); the presence of potential 

conduits for fluid movement near the 

injection well (per § 146.84(c)(2)); the 

quality of wells and well plugs in wells 

within the AoR (per § 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 § 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 § 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 § 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 

§ 146.93(a)(2)(iv); and, must be 

incorporated in the permit as part of the 

PISC and site closure plan as required 

at § 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 § 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 § 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 

mstockstill on DSKH9S0YB1PROD with RULES2

77268 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 (§ 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 postinjection 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 § 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 

§ 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 

§§ 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 

§ 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 postinjection 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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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 ratebased 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 § 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 

mstockstill on DSKH9S0YB1PROD with RULES2

77270 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 selfinsurance 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 

§ 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 ‘‘payin 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 § 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 newlyidentified 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 postinjection 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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 77271 

instruments for well plugging and PISC 

(§ 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 

(§ 146.85(a)(5)(i)). 

EPA adds that under today’s final 

rulemaking at § 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 

§ 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 § 146.85(c), also requires 

that the owner or operator adjust the 

cost estimates to address amendments to 

the AoR and corrective action plan 

(§ 146.84), the injection well plugging 

plan (§ 146.92), the PISC and site 

closure plan (§ 146.93), and the 

emergency and remedial response plan 

(§ 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 § 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 postinjection 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 

§ 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 

§ 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 § 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 

mstockstill on DSKH9S0YB1PROD with RULES2

77272 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 § 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 § 146.93, 

under section 1423 of the SDWA for 

violating § 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. §§ 7401–7671; 

CERCLA, 42 U.S.C. § 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 § 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 (§ 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 § 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 sitespecific 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. 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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 eventspecific. 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 § 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 § 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 

§ 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 

(§ 144.36). In lieu of the periodic permit 

reissuance required for most other deepwell 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 

mstockstill on DSKH9S0YB1PROD with RULES2

77274 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 

(§ 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 (§ 146.84(e), 

§ 146.90(j), and § 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 §§ 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 

§ 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 § 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 § 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 § 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 (§ 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 § 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 

(§ 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 § 146.86(a) and ensure 

protection of USDWs from 

endangerment in lieu of requirements at 

§ 146.86(b) and § 146.87(a). 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 77275 

3Note 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. 

4Although 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. 

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 § 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 postinjection 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. 

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

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. 

mstockstill on DSKH9S0YB1PROD with RULES2

77276 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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

Requirements 

Direction of change in 

risk for selected RA 

(relative to baseline) 

1. Geologic Characterization 

Baseline 

Identify a geologic system consisting of a 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.

Decrease. 

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 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.

Decrease. 

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 prevent movement of fluids into or between USDWs and to withstand the injected materials at the anticipated pressure, temperature and other operational conditions. Wells must be constructed 

to inject below the lowermost USDW.

Decrease (enhanced 

well construction requirements); 

Increase (A waiver to 

inject above the 

lowermost USDW in 

limited cases). 

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 initiating new fractures or propagating existing fractures in the confining zone adjacent 

to the USDWs.

Decrease. 

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, and conduct a pressure fall-off test every 5 years ............................................. Decrease. 

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 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.

Decrease. 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 77277 

TABLE IV–1—RELATIVE RISK OF REGULATORY COMPONENTS FOR SELECTED RA VERSUS THE CURRENT

REGULATIONS 5—Continued 

Requirements 

Direction of change in 

risk for selected RA 

(relative to baseline) 

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 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.

Decrease. 

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 responsibility and resources to plug and abandon the injection well ........................... Decrease. 

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. 

5The 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 onetime, 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). 

mstockstill on DSKH9S0YB1PROD with RULES2

77278 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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. 


mstockstill on DSKH9S0YB1PROD with RULES2EP10DE10.091</GPH>
Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 77279 

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 


mstockstill on DSKH9S0YB1PROD with RULES2EP10DE10.092</GPH>
77280 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

6A 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. 

7A more detailed discussion of these projects can 

be found in the Cost Analysis. 

8A 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. 

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 commercialsize 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. 

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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 77281 

7A more detailed discussion of these projects can 

be found in the Cost Analysis. 

8A 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. 

9Of 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. 

10Potential increase in costs due to increased 

deployment rates and an associated rise in demand 

for labor or services in the field were considered in 

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). 

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 projectspecific 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. 

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. 

mstockstill on DSKH9S0YB1PROD with RULES2

77282 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 


mstockstill on DSKH9S0YB1PROD with RULES2EP10DE10.093</GPH>
Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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. 

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 


mstockstill on DSKH9S0YB1PROD with RULES2EP10DE10.094</GPH>
77284 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 costeffective for the regulated community; it 

is also intended to encourage innovation 

in analytical technology and improved 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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, 

mstockstill on DSKH9S0YB1PROD with RULES2

77286 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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. 

■ 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 

■ 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 

■ 2. Section 124.10 is amended by 

revising paragraph (c) introductory text 

and by adding paragraph (c)(1)(xi) to 

read as follows: 

§ 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 

■ 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 

■ 4. Section 144.1 is amended by adding 

paragraph (f)(1)(viii) and by revising 

paragraph (g) introductory text to read 

as follows. 

§ 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,’’ § 144.3). The six classes of 

wells are set forth in § 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 § 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 (§ 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 (§ 144.13). For Class V 

wells, if remedial action appears 

necessary, a permit may be required 

(§ 144.25) or the Director must require 

remedial action or closure by order 

(§ 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 

§ 144.3, even if it has not been 

‘‘identified.’’ The Director may also 

designate ‘‘exempted aquifers’’ using the 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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 § 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 

§ 145.23(f)(9). 

* * * * * 

■ 5. Section 144.3 is amended by adding 

in alphabetic order the definition 

‘‘geologic sequestration’’ to read as 

follows: 

§ 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. 

* * * * * 

■ 6. Section 144.6 is amended by 

revising paragraph (e) and adding 

paragraph (f) to read as follows: 

§ 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 § 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 § 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 §§ 146.4 

of this chapter and 144.7(d). 

■ 7. Section 144.7 is amended as 

follows: 

■ a. Revising paragraph (a); 

■ b. Revising paragraphs (b)(1) and 

(b)(2); and 

■ c. Adding paragraph (d) as follows: 

§ 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 § 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 § 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 

§ 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 

§ 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 

§ 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 § 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 § 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 

§ 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 § 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 § 146.84(e); and 

(iv) Any information submitted to 

support a waiver request made by the 

owner or operator under § 146.95, if 

appropriate. 

■ 8. Section 144.8 is amended by adding 

paragraph (b)(2)(iii) to read as follows: 

mstockstill on DSKH9S0YB1PROD with RULES2

77288 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

§ 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 § 146.91 of this 

chapter. 

* * * * * 

Subpart B—General Program 

Requirements 

■ 9. Section 144.12 is amended by 

revising the first sentence in paragraph 

(b) to read as follows: 

§ 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. * * * 

* * * * * 

■ 10. Section 144.15 is added to read as 

follows: 

§ 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. 

■ 11. Section 144.18 is added to subpart 

B to read as follows: 

§ 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. 

■ 12. Section 144.19 is added to subpart 

B to read as follows: 

§ 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 § 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 

■ 13. Section 144.22 is amended by 

revising paragraph (b) to read as follows: 

§ 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 §§ 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 

§§ 144.28(c) and 146.10 of this chapter; 

and upon submission of a plugging and 

abandonment report pursuant to 

§ 144.28(k); or upon conversion in 

compliance with § 144.28(j). 

Subpart D—Authorization by Permit 

■ 14. Section 144.31 is amended by 

revising paragraph (e) introductory text 

to read as follows: 

§ 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 

§ 146.82 of this chapter. 

* * * * * 

■ 15. Section 144.33 is amended by 

revising paragraph (a)(4) and adding 

paragraph (a)(5). 

§ 144.33 Area permits. 

(a) * * * 

(4) Used to inject other than 

hazardous waste; and 

(5) Other than Class VI wells. 

* * * * * 

■ 16. Section 144.36 is amended by 

revising paragraph (a) to read as follows: 

§ 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 §§ 144.39, 144.40, 

or 144.41. 

* * * * * 

■ 17. Section 144.38 is amended by 

revising paragraph (b) introductory text 

to read as follows: 

§ 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: 

* * * * * 

■ 18. Section 144.39 is amended as 

follows: 

■ a. Revising the second sentence in 

paragraph (a) introductory text; 

■ b. Revising the second sentence in 

paragraph (a)(3) introductory text; and 

■ c. Adding a new paragraph (a)(5) to 

read as follows: 

§ 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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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 

§ 146.84(e)(1) of this chapter; 

(ii) Any amendments to the testing 

and monitoring plan under § 146.90(j) of 

this chapter; 

(iii) Any amendments to the injection 

well plugging plan under § 146.92(c) of 

this chapter; 

(iv) Any amendments to the postinjection site care and site closure plan 

under § 146.93(a)(3) of this chapter; 

(v) Any amendments to the 

emergency and remedial response plan 

under § 146.94(d) of this chapter; or 

(vi) A review of monitoring and/or 

testing results conducted in accordance 

with permit requirements. 

* * * * * 

■ 19. Section 144.41 is amended by 

adding a new paragraph (h) to read as 

follows: 

§ 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 

■ 20. Section 144.51 is amended to read 

as follows: 

■ a. Adding a new paragraph (j)(4); 

■ b. Revising paragraph (o); and 

■ c. Removing the first sentence in 

paragraph (q)(1) and adding two 

sentences in its place; and 

■ d. Revising the first sentence in 

paragraph (q)(2). 

§ 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 

§§ 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 § 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 § 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 § 146.92 of this chapter. Where the 

plan meets the requirements of § 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 

§ 146.8 of this chapter and the owner or 

operator of Class VI wells must maintain 

mechanical integrity as defined in 

§ 146.89 of this chapter. * * * 

(2) When the Director determines that 

a Class I, II, III or VI well lacks 

mechanical integrity pursuant to 

§§ 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. 

* * * 

* * * * * 

■ 21. Section 144.52 is amended as 

follows: 

■ a. By revising paragraph (a) 

introductory text; 

■ b. Revising paragraph (a)(2); 

■ c. Revising paragraphs (a)(7)(i)(A) and 

(a)(7)(ii); and 

■ d. Revising paragraph (a)(8). 

§ 144.52 Establishing permit conditions. 

(a) In addition to conditions required 

in § 144.51, the Director shall establish 

conditions, as required on a case-bycase basis under § 144.36 (duration of 

permits), § 144.53(a) (schedules of 

compliance), § 144.54 (monitoring), and 

for EPA permits only § 144.53(b) 

(alternate schedules of compliance), and 

§ 144.4 (considerations under Federal 

law). Permits for owners or operators of 

hazardous waste injection wells shall 

include conditions meeting the 

requirements of § 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 

§§ 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 §§ 144.51(o), 146.10, 

and 146.92 of this chapter, and 

submitted a plugging and abandonment 

report pursuant to § 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 § 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 § 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 § 146.8, or § 146.89 of this chapter 

for Class VI, that the well has 

mechanical integrity. 

* * * * * 

mstockstill on DSKH9S0YB1PROD with RULES2

77290 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

Subpart G—Requirements for Owners 

and Operators of Class V Injection 

Wells 

■ 22. Section 144.80 is amended by 

revising the first sentence in paragraph 

(e) and by adding paragraph (f) to read 

as follows: 

§ 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 § 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 § 146.4 of 

this chapter and § 144.7(d). 

PART 145—STATE UIC PROGRAM 

REQUIREMENTS 

■ 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 

■ 24. Section 145.1 is amended by 

adding paragraph (i) to read as follows: 

§ 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 

■ 25. Section 145.21 is amended by 

adding paragraph (h) to read as follows: 

§ 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 §§ 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. 

■ 26. Section 145.22 is amended by 

revising paragraphs (a) introductory text 

and (a)(5) to read as follows: 

§ 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; 

* * * * * 

■ 27. Section 145.23 is amended as 

follows: 

■ a. By revising the introductory text; 

■ b. Revising paragraph (c); 

■ c. Revising paragraph (d); 

■ d. Revising paragraphs (f)(1), (f)(2), 

(f)(3), (f)(4), and (f)(9); and 

■ e. Adding paragraph (f)(13) to read as 

follows: 

§ 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 § 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 § 146.8 of this 

chapter, or, for Class VI wells, the 

mechanical integrity testing 

requirements of § 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 

§ 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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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 § 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 § 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 §§ 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. 

■ 28. Section 145.32 is amended by 

adding a sentence at the end of 

paragraph (b)(2) to read as follows: 

§ 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 

■ 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. 

■ 30. Section 146.4 is amended by 

revising the introductory text and 

adding paragraph (d) to read as follows: 

§ 146.4 Criteria for exempted aquifers. 

An aquifer or a portion thereof which 

meets the criteria for an ‘‘underground 

source of drinking water’’ in § 146.3 may 

be determined under § 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 § 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. 

■ 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: 

§ 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 § 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 § 146.4 and 

§ 144.7(d) of this chapter. 

■ 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 

§ 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 ruleauthorized 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 

§ 146.86(a) and ensure protection of 

USDWs, in lieu of requirements at 

§§ 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 §§ 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 

mstockstill on DSKH9S0YB1PROD with RULES2

77292 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 § 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 § 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 § 146.4 and 

§ 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 § 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 § 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. 

§ 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 § 146.91(e), and the 

Director shall consider the following: 

(1) Information required in 

§ 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 § 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 EPAapproved 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; 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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 § 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 § 146.86; 

(13) Proposed area of review and 

corrective action plan that meets the 

requirements under § 146.84; 

(14) A demonstration, satisfactory to 

the Director, that the applicant has met 

the financial responsibility 

requirements under § 146.85; 

(15) Proposed testing and monitoring 

plan required by § 146.90; 

(16) Proposed injection well plugging 

plan required by § 146.92(b); 

(17) Proposed post-injection site care 

and site closure plan required by 

§ 146.93(a); 

(18) At the Director’s discretion, a 

demonstration of an alternative postinjection site care timeframe required by 

§ 146.93(c); 

(19) Proposed emergency and 

remedial response plan required by 

§ 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 

§ 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 § 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 

§ 146.87; 

(8) A demonstration of mechanical 

integrity pursuant to § 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 § 146.95 and submit a 

supplemental report, as required at 

§ 146.95(a). The supplemental report is 

not part of the permit application. 

§ 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. 

§ 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 

mstockstill on DSKH9S0YB1PROD with RULES2

77294 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 §§ 144.39 or 144.41 of 

this chapter, as appropriate. 

(f) The emergency and remedial 

response plan (as required by § 146.94) 

and the demonstration of financial 

responsibility (as described by § 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. 

§ 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 § 146.84); 

(ii) Injection well plugging (that meets 

the requirements of § 146.92); 

(iii) Post injection site care and site 

closure (that meets the requirements of 

§ 146.93); and 

(iv) Emergency and remedial response 

(that meets the requirements of 

§ 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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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 (§ 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 

mstockstill on DSKH9S0YB1PROD with RULES2

77296 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 

(§ 146.84), the injection well plugging 

plan (§ 146.92), the post-injection site 

care and site closure plan (§ 146.93), 

and the emergency and remedial 

response plan (§ 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 (§ 146.84), the injection well 

plugging plan (§ 146.92), the postinjection site care and site closure plan 

(§ 146.93), and the emergency and 

response plan (§ 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 postinjection 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 § 146.84), 

injection well plugging (as required by 

§ 146.92), post-injection site care and 

site closure (as required by § 146.93), 

and emergency and remedial response 

(as required by § 146.94). 

(f) The Director must approve the use 

and length of pay-in-periods for trust 

funds or escrow accounts. 

§ 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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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. 

§ 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 

§ 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 oxygenactivation 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. 

§ 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 § 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 tubingcasing 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, 

mstockstill on DSKH9S0YB1PROD with RULES2

77298 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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. 

§ 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 § 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 § 146.90, 

the owner or operator must run a casing 

inspection log to determine the presence 

or absence of corrosion in the longstring 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. 

§ 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 

§ 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 § 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 § 146.82(a)(6) 

and on any modeling results in the area 

of review evaluation required by 

§ 146.84(c). 

(e) A demonstration of external 

mechanical integrity pursuant to 

§ 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 § 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: 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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 sitespecific 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 § 144.12 of this chapter; 

(3) If an owner or operator 

demonstrates that monitoring employed 

under §§ 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 

§ 146.91(c)(5), a Director that requires 

surface air/soil gas monitoring must 

approve the use of monitoring employed 

under §§ 98.440 to 98.449 of this 

chapter. Compliance with §§ 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 

§ 146.84(c) and to determine compliance 

with standards under § 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 § 146.88, and the most recent area 

of review reevaluation performed under 

§ 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 §§ 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. 

§ 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 § 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 § 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 § 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 

§ 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 § 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 § 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 § 146.90(b) through (i) shall 

be retained for 10 years after it is 

collected. 

(4) Well plugging reports, postinjection 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 

§§ 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. 

§ 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 

mstockstill on DSKH9S0YB1PROD with RULES2

77300 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

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 § 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 § 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 §§ 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 § 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. 

§ 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 postinjection 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 

§ 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 § 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 nonendangerment of USDWs. 

(3) Upon cessation of injection, 

owners or operators of Class VI wells 

must either submit an amended postinjection 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 postinjection 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 §§ 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 postinjection 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 postinjection 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 postinjection site care until a demonstration 

can be made and approved by the 

Director. 

(c) Demonstration of alternative postinjection 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 

§§ 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: 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 77301 

(i) The results of computational 

modeling performed pursuant to 

delineation of the area of review under 

§ 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 sitespecific 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 § 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 postinjection 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. 

§ 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 postinjection 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. 

mstockstill on DSKH9S0YB1PROD with RULES2

77302 Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 

(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 §§ 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. 

§ 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 

§ 146.84, and is subject to requirements, 

as described in § 146.84(c), and periodic 

reevaluation, as described in § 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 §§ 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 

§ 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 

mstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 237 / Friday, December 10, 2010 / Rules and Regulations 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 §§ 146.84, 

146.85, 146.87, 146.88, 146.89, 146.91, 

146.92, and 146.94; 

(2) All requirements at § 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 § 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 § 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 § 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 downhole carbon dioxide detection tools), 

unless the Director determines, based on 

site-specific geology, that such methods 

are not appropriate. 

(4) All requirements at § 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 downhole 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 EPAADMINISTERED UNDERGROUND 

INJECTION CONTROL PROGRAMS 

■ 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. 

■ 34. Section 147.1 is amended by 

adding paragraph (f) to read as follows: 

§ 147.1 Purpose and scope. 

* * * * * 

(f) Class VI well owners or operators 

must comply with § 146.91(e) 

notwithstanding any State program 

approvals. 

[FR Doc. 2010–29954 Filed 12–9–10; 8:45 am] 

BILLING CODE 6560–50–P 

mstockstill on DSKH9S0YB1PROD with RULES2