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1 ENVIRONMENTAL PROTECTION AGENCY 

2 40 CFR Part 146 

3 [EPA-HQ-OW-2008-0390 FRL-_______-_______] 

4 RIN 2040-AE98 

5 TITLE: Minimum Federal Requirements Under the Underground Injection Control (UIC) 

6 Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells 

7 AGENCY: Environmental Protection Agency (EPA). 

8 ACTION: Proposed Rule. 

9 

10 SUMMARY: EPA is proposing minimum Federal requirements under the Safe Drinking Water 

11 Act (SDWA) for underground injection of carbon dioxide (CO2) for the purpose of geologic 

12 sequestration (GS). GS is one of a portfolio of options that could be deployed to reduce CO2

13 emissions to the atmosphere and help to mitigate climate change. Today’s proposal applies to 

14 owners or operators of wells that will be used to inject CO2 into the subsurface for the purpose of 

15 long-term storage. It proposes a new class of well and minimum technical criteria for the 

16 geological characterization, fluid movement, area of review (AoR) and corrective action, well 

17 construction, operation, mechanical integrity testing, monitoring, well plugging, post-injection 

18 site care, and site closure for the purposes of protecting underground sources of drinking water 

19 (USDWs). The elements of today’s proposal are based on the existing UIC regulatory 

20 framework, with additional new requirements to address the unique nature of CO2 injection for 

21 GS. If finalized, today’s proposal would help ensure consistency in permitting underground 

22 injection of CO2 at GS operations across the U.S. and provide requirements to prevent 

23 endangerment of USDWs in anticipation of the eventual use of GS to reduce CO2 emissions. 
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1 

2 DATES: Comments must be received on or before [INSERT DATE 120 DAYS AFTER DATE 

3 OF PUBLICATION IN THE FEDERAL REGISTER]. A public hearing will be held during the 

4 public comment period in September 2008. EPA will notify the public of the date, time and 

5 location of a public hearing in a separate Federal Register notice. 

6 

7 ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-OW-2008-0390, 

8 by one of the following methods: 

9 o www.regulations.gov: Follow the on-line instructions for submitting comments.

10 o Mail: Water Docket, Environmental Protection Agency, Mailcode: 2822T, 1200 

11 Pennsylvania Ave., NW, Washington, DC 20460. 

12 o Hand Delivery: Water Docket, EPA Docket Center (EPA/DC) EPA West, Room 

13 3334, 1301 Constitution Ave., NW, Washington, DC. Such deliveries are only 

14 accepted during the Docket’s normal hours of operation, and special arrangements 

15 should be made for deliveries of boxed information. 

16 

17 Instructions: Direct your comments to Docket ID No. EPA-HQ-OW-2008-0390. EPA's policy 

18 is that all comments received will be included in the public docket without change and may be 

19 made available online at www.regulations.gov, including any personal information provided, 

20 unless the comment includes information claimed to be Confidential Business Information (CBI) 

21 or other information whose disclosure is restricted by statute. Do not submit information that you 

22 consider to be CBI or otherwise protected, through www.regulations.gov or email. The 

23 www.regulations.gov website is an “anonymous access” system, which means EPA will not 
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1 know your identity or contact information unless you provide it in the body of your comment. If 

2 you send an e-mail comment directly to EPA without going through www.regulations.gov your 

3 e-mail address will be automatically captured and included as part of the comment that is placed 

4 in the public docket and made available on the Internet. If you submit an electronic comment, 

5 EPA recommends that you include your name and other contact information in the body of your 

6 comment and with any disk or CD-ROM you submit. If EPA cannot read your comment due to 

7 technical difficulties and cannot contact you for clarification, EPA may not be able to consider 

8 your comment. Electronic files should avoid the use of special characters, any form of 

9 encryption, and be free of any defects or viruses. 

10 

11 Docket: All documents in the docket are listed in the www.regulations.gov index. Although 

12 listed in the index, some information is not publicly available, e.g., CBI or other information 

13 whose disclosure is restricted by statute. Certain other material, such as copyrighted material, 

14 will be publicly available only in hard copy. Publicly available docket materials are available 

15 either electronically in www.regulations.gov or in hard copy at the Water Docket, EPA/DC, EPA 

16 West, Room 3334, 1301 Constitution Ave., NW, Washington, DC. The Public Reading Room is 

17 open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The 

18 telephone number for the Public Reading Room is (202) 566-1744, and the telephone number for 

19 the EPA Docket Center is (202) 566-2426. 

20 

21 FOR FURTHER INFORMATION CONTACT: Lee Whitehurst, Underground Injection 

22 Control Program, Drinking Water Protection Division, Office of Ground Water and Drinking 

23 Water (MC-4606M), Environmental Protection Agency, 1200 Pennsylvania Ave., NW, 
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1 Washington, DC 20460; telephone number: (202) 564-3896; fax number: (202) 564-3756; e2 mail address: whitehurst.lee@epa.gov. For general information, contact the Safe Drinking Water 

3 Hotline, telephone number: (800) 426-4791. The Safe Drinking Water Hotline is open Monday 

4 through Friday, excluding legal holidays, from 10:00 a.m. to 4:00 p.m. Eastern time. 

5 

6 SUPPLEMENTARY INFORMATION: 

7 I. General Information 

8 This is a proposed regulation. If finalized, these regulations would affect owners or operators of 

9 injection wells that will be used to inject CO2 into the subsurface for the purposes of GS. 

10 Regulated categories and entities would include, but are not limited to, the following: 

11 ------------------------------------------------------------------------ 

12 Examples of regulated 

13 Category entities 

14 ------------------------------------------------------------------------ 

15 Private................................... Operators of CO2 injection wells used for GS. 

16 ------------------------------------------------------------------------ 

17 

18 This table is not intended to be an exhaustive list, but rather provides a guide for readers 

19 regarding entities likely to be regulated by this action. This table lists the types of entities that 

20 EPA is now aware could potentially be regulated by this action. Other types of entities not listed 

21 in the table could also be regulated. To determine whether your facility is regulated by this 

22 action, you should carefully examine the applicability criteria found in 14x.xxx of this proposed 

23 rule. If you have questions regarding the applicability of this action to a particular entity, consult 
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1 the person listed in the preceding “FOR FURTHER INFORMATION CONTACT” section. 

2 

3 Abbreviations and Acronyms 

4 AASG American Association of State Geologists 

5 AoR Area of Review 

6 API American Petroleum Institute 

7 CaCO3 Calcium Carbonate 

8 CAA Clean Air Act 

9 CCS Carbon Capture and Storage 

10 CERCLA Comprehensive Environmental Response, Compensation, and Liability Act 

11 CO2 Carbon Dioxide 

12 CSLF Carbon Sequestration Leadership Forum 

13 DOE Department of Energy 

14 ECBM Enhanced Coalbed Methane 

15 EFAB Environmental Finance Advisory Board 

16 EGR Enhanced Gas Recovery 

17 EM Electromagnetic 

18 EOR Enhanced Oil Recovery 

19 EPA Environmental Protection Agency 

20 ERT Electrical Resistance Tomography 

21 FACA Federal Advisory Committee Act 

22 GHGs Greenhouse Gases 

23 GS Geologic Sequestration 
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1 GWPC Ground Water Protection Council 

2 H2S Hydrogen Sulfide 

3 ICR Information Collection Request 

4 IEA International Energy Agency 

5 IOGCC Interstate Oil and Gas Compact Commission 

6 IPCC Intergovernmental Panel on Climate Change 

7 LBNL Lawrence Berkeley National Laboratory 

8 LIDAR Light Detection and Ranging 

9 MI Mechanical Integrity 

10 MIT Mechanical Integrity Test 

11 MMT Million Metric Tons 

12 MMV Monitoring, Measurement, and Verification 

13 MPRSA Marine Protection, Research, and Sanctuaries Act 

14 NDWAC National Drinking Water Advisory Council 

15 NETL National Energy Technology Laboratory 

16 NGOs Non-Governmental Organizations 

17 NODA Notice of Data Availability 

18 NPDWR National Primary Drinking Water Regulation 

19 NTTAA National Technology Transfer and Advancement Act 

20 OIRA Office of Information and Regulatory Affairs 

21 OMB Office of Management and Budget 

22 O&M Operation and Maintenance 

23 ORD Office of Research and Development 
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1 NOx Nitrogen Oxides 

2 PFC Perfluorocarbon 

3 PNNL Pacific Northwest National Laboratory 

4 PRA Paperwork Reduction Act 

5 PVT Pressure-Volume-Temperature 

6 PWS Public Water Supply 

7 RA Regulatory Alternative 

8 RCRA Resource Conservation and Recovery Act 

9 RCSP Regional Carbon Sequestration Partnerships 

10 RFA Regulatory Flexibility Act 

11 SACROC Scurry Area Canyon Reef Operators Committee 

12 SBREFA Small Business Regulatory Enforcement Fairness Act 

13 SDWA Safe Drinking Water Act 

14 SOx Sulfur Oxides 

15 TDS Total Dissolved Solids 

16 UIC Underground Injection Control 

17 UICPG#83 Underground Injection Control Program Guidance # 83 

18 UMRA Unfunded Mandates Reform Act 

19 USDW Underground Source of Drinking Water 

20 VEF Vulnerability Evaluation Framework 

21 

22 DEFINITIONS 

23 
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1 Annulus: the space between the well casing and the wall of the bore hole; the space between 

2 concentric strings of casing; space between casing and tubing. 

3 

4 Area of review (AoR): the region surrounding the geologic sequestration project that may be 

5 impacted by the injection activity. The area of review is based on computational modeling that 

6 accounts for the physical and chemical properties of all phases of the injected carbon dioxide 

7 stream. 

8 

9 Ball valve: a valve consisting of a hole drilled through a ball placed in between two seals. The 

10 valve is closed when the ball is rotated in the seals so the flow path no longer aligns with the well 

11 casing. 

12 

13 Buoyancy: upward force on one phase (e.g., a fluid) produced by the surrounding fluid (e.g., a 

14 liquid or a gas) in which it is fully or partially immersed, caused by differences in pressure or 

15 density. 

16 

17 Capillary force: adhesive force that holds a fluid in a capillary or a pore space. Capillary force is 

18 a function of the properties of the fluid, and surface and dimensions of the space. If the 

19 attraction between the fluid and surface is greater than the interaction of fluid molecules, the 

20 fluid will be held in place. 

21 

22 Caprock: see confining zone. 

23 
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1 Carbon dioxide plume: the extent underground, in three dimensions, of an injected carbon 

2 dioxide stream. 

3 

4 Carbon dioxide (CO2) stream: carbon dioxide that has been captured from an emission source 

5 (e.g., a power plant), plus incidental associated substances derived from the source materials and 

6 the capture process, and any substances added to the stream to enable or improve the injection 

7 process. This subpart does not apply to any carbon dioxide stream that meets the definition of a 

8 hazardous waste under 40 CFR Part 261. 

9 

10 Carbon Capture and Storage (CCS): the process of capturing CO2 from an emission source, 

11 (typically) converting it to a supercritical state, transporting it to an injection site, and injecting it 

12 into deep subsurface rock formations for long-term storage. 

13 

14 Casing: the pipe material placed inside a drilled hole to prevent the hole from collapsing. The 

15 two types of casing in most injection wells are 1) surface casing, the outer most casing that 

16 extends from the surface to the base of the lowermost USDW and 2) long-string casing, which 

17 extends from the surface to or through the injection zone. 

18 

19 Cement: material used to support and seal the well casing to the rock formations exposed in the 

20 borehole. Cement also protects the casing from corrosion and prevents movement of injectate up 

21 the borehole. The composition of the cement may vary based on the well type and purpose; 

22 cement may contain latex, mineral blends, or epoxy. 

23 
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1 Confining zone: a geologic formation, group of formations, or part of a formation 

2 stratigraphically overlying the injection zone that acts as a barrier to fluid movement. 

3 

4 Corrective action: the use of Director approved methods to assure that wells within the area of 

5 review do not serve as conduits for the movement of fluids into underground sources of drinking 

6 water (USDW). 

7 

8 Corrosive: having the ability to wear away a material by chemical action. Carbon dioxide mixed 

9 with water forms carbonic acid, which can corrode well materials. 

10 

11 Dip: the angle between a planar feature, such as a sedimentary bed or a fault, and the horizontal 

12 plane. The dip of subsurface rock layers can provide clues as to whether injected fluids may be 

13 contained. 

14 

15 Director: the person responsible for permitting, implementation and compliance of the UIC 

16 program. For UIC programs administered by EPA the Director is the EPA Regional 

17 Administrator; for UIC programs in Primacy States, the Director is the person responsible for 

18 permitting, implementation, and compliance of the State, Territorial, or Tribal UIC program. 

19 

20 Ductility: the ability of a material to sustain stress until it fractures. 

21 

22 Enhanced Coal Bed Methane (ECBM) recovery: the process of injecting a gas (e.g., CO2) into 

23 coal, where it is adsorbed to the coal surface and methane is released. The methane can be 
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1 captured and produced for economic purposes; when CO2 is injected, it adsorbs to the surface of 

2 the coal, where it remains sequestered. 

3 

4 Enhanced Oil or Gas Recovery (EOR/EGR): typically, the process of injecting a fluid (e.g., 

5 water, brine, or CO2) into an oil or gas bearing formation to recover residual oil or natural gas. 

6 The injected fluid thins (decreases the viscosity) or displaces small amounts of extractable oil 

7 and gas, which is then available for recovery. This is also known as secondary or tertiary 

8 recovery. 

9 

10 Flapper valve: a valve consisting of a hinged flapper that seals the valve orifice. In GS wells, 

11 flapper valves can engage to shut off the flow of the CO2 when acceptable operating parameters 

12 are exceeded. 

13 

14 Formation or geological formation: a layer of rock that is made up of a certain type of rock or a 

15 combination of types. 

16 

17 Geologic sequestration (GS): the long-term containment of a gaseous, liquid or supercritical 

18 carbon dioxide stream in subsurface geologic formations. This term does not apply to its capture 

19 or transport. 

20 

21 Geologic sequestration project: an injection well or wells used to emplace a CO2 stream beneath 

22 the lowermost formation containing a USDW. It includes the subsurface three-dimensional 
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1 extent of the carbon dioxide plume, associated pressure front, and displaced brine, as well as the 

2 surface area above that delineated region. 

3 

4 Geophysical surveys: the use of geophysical techniques (e.g., seismic, electrical, gravity, or 

5 electromagnetic surveys) to characterize subsurface rock formations. 

6 

7 Injectate: the fluids injected. For the purposes of this rule, this is also known as the CO2 stream. 

8 

9 Injection zone: a geologic formation, group of formations, or part of a formation that is of 

10 sufficient areal extent, thickness, porosity, and permeability to receive carbon dioxide through a 

11 well or wells associated with a geologic sequestration project. 

12 

13 Lithology: the description of rocks, based on color, mineral composition and grain size. 

14 

15 Mechanical integrity (MI): The absence of significant leakage within the injection tubing, casing, 

16 or packer (known as internal mechanical integrity), or outside of the casing (known as external 

17 mechanical integrity). 

18 

19 Mechanical Integrity Test (MIT): a test performed on a well to confirm that a well maintains 

20 internal and external mechanical integrity. MITs are a means of measuring the adequacy of the 

21 construction of an injection well and a way to detect problems within the well system before 

22 leaks can occur. 

23 
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1 Model: a representation or simulation of a phenomenon or process that is difficult to observe 

2 directly or that occurs over long time frames. Models that support GS can predict the flow of 

3 CO2 within the subsurface, accounting for the properties and fluid content of the subsurface 

4 formations and the effects of injection parameters. 

5 

6 Packer: a mechanical device set immediately above the injection zone that seals the outside of 

7 the tubing to the inside of the long string casing. 

8 

9 Pinch-out: the location where a porous, permeable formation that is located between overlying 

10 and underlying confining formations thins to a zero thickness, and the confining formations are 

11 in contact with each other. 

12 

13 Pore space: open spaces in rock or soil. These are filled with water or other fluids such as brine 

14 (i.e., salty fluid). CO2 injected into the subsurface can displace pre-existing fluids to occupy 

15 some of the pore spaces of the rocks in the injection zone. 

16 

17 Post-injection site care: appropriate monitoring and other actions (including corrective action) 

18 needed following cessation of injection to assure that USDWs are not endangered as required 

19 under §146.93. 

20 

21 Pressure front: the zone of elevated pressure that is created by the injection of carbon dioxide 

22 into the subsurface. For GS projects, the pressure front of a CO2 plume refers to zone where 
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1 there is a pressure differential sufficient to cause the movement of injected fluids or formation 

2 fluids into a USDW. 

3 

4 Saline formations: deep and geographically extensive sedimentary rock layers saturated with 

5 waters or brines that have a high total dissolved solids (TDS) content (i.e., over 10,000 mg/L 

6 TDS). Saline formations offer great potential CO2 storage capacity. 

7 

8 Shut-off device: a valve coupled with a control device which closes the valve when a set pressure 

9 or flow value is exceeded. Shut-off devices in injection wells can automatically shut down 

10 injection activities when operating parameters unacceptably diverge from permitted values. 

11 

12 Sorption (absorption, adsorption): Absorption refers to gases or liquids being incorporated into a 

13 material of a different state; adsorption is the adhering of a molecule or molecules to the surface 

14 of a different molecule. 

15 

Supercritical fluid: a fluid above its critical temperature (31.1o 16 C for CO2) and critical pressure 

17 (73.8 bar for CO2). Supercritical fluids have physical properties intermediate to those of gases 

18 and liquids. 

19 

20 Stratigraphic zone (unit): a layer of rock (or stratum) that is recognized as a unit based on 

21 lithology, fossil content, age or other properties. 

22 
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1 Total Dissolved Solids (TDS): the measurement, usually in mg/L for the amount of all inorganic 

2 and organic substances suspended in liquid as molecules, ions, or granules. For injection 

3 operations, TDS typically refers to the saline (i.e., salt) content of water-saturated underground 

4 formations. 

5 

6 Transmissive fault or fracture: a fault or fracture that has sufficient permeability and vertical 

7 extent to allow fluids to move between formations. 

8 

9 Trapping: the physical and geochemical processes by which injected CO2 is sequestered in the 

10 subsurface. Physical trapping occurs when buoyant CO2 rises in the formation until it reaches a 

11 layer that inhibits further upward migration or is immobilized in pore spaces due to capillary 

12 forces. Geochemical trapping occurs when chemical reactions between dissolved CO2 and 

13 minerals in the formation lead to the precipitation of solid carbonate minerals. 

14 

15 Underground Source of Drinking Water (USDW): an aquifer or portion of an aquifer that 

16 supplies any public water system or that contains a sufficient quantity of ground water to supply 

17 a public water system, and currently supplies drinking water for human consumption, or that 

18 contains fewer than 10,000 mg/l total dissolved solids and is not an exempted aquifer. 

19 

20 Viscosity: the property of a fluid or semi-fluid that offers resistance to flow. As a supercritical 

21 fluid, CO2 is less viscous than water and brine. 

22 

23 TABLE OF CONTENTS 
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1 I. General Information 

2 II. What is EPA Proposing Today? 

3 A. Why is EPA Proposing to Develop New Regulations to Address GS of CO2? 

4 B. What is EPA’s Authority Under the SDWA to Regulate Injection of CO2? 

5 C. Who Implements the UIC Program? 

6 D. What are the Risks Associated with CO2 GS? 

7 E. What Steps has EPA Taken to Inform Today’s Proposal? 

8 F. Why is EPA Proposing to Develop a New Class of Injection Well for GS of CO2? 

9 G. How would today’s proposal affect existing injection wells under the UIC Program? 

10 H. What are the Target Geologic Formations for GS of CO2? 

11 I. Is Injected CO2 Considered a Hazardous Waste under RCRA? 

12 J. Is Injected CO2 Considered a Hazardous Substance under CERCLA? 

13 III. Proposed Regulatory Alternative 

14 A. Proposed Alternative 

15 1. Proposed Geologic Siting Requirements 

16 2. Proposed Area of Review and Corrective Action Requirements 

17 Delineating the Area of Review 

18 Modeling CO2 Movement 

19 Corrective Action 

20 Area of Review Reevaluation 

21 Phased Corrective Action 

22 Proposed Area of Review and Corrective Action Plan 

23 3. Proposed Injection Well Construction Requirements 
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1 Well construction procedures 

2 Horizontal Well Construction 

3 Well component degradation 

4 4. Proposed Injection Well Operating Requirements 

5 Injection parameter limitations 

6 Continuous monitoring 

7 Corrosion Monitoring and Control 

8 Injection Depth in Relation to USDWs 

9 Tracers 

10 5. Proposed Mechanical Integrity Testing Requirements 

11 6. Proposed Plume and Pressure Front Monitoring Requirements 

12 Testing and Monitoring Plan 

13 Plume tracking, ambient groundwater and surface air monitoring 

14 Geophysical methods for plume tracking 

15 Geochemical and Pressure Monitoring 

16 Surface air and soil gas monitoring 

17 7. Proposed Recordkeeping and Reporting Requirements 

18 Submissions required for consideration of permit applications

19 Operational recordkeeping and reporting requirements 

20 Reporting associated with closure and post-injection site care 

21 Electronic Reporting

22 8. Proposed Well Plugging and Post-Injection Site Care Requirements 

23 9. Proposed Financial Responsibility and Long-term Care Requirements 
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1 B. Adaptive Approach 

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

3 Projects? 

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

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

6 VII. Cost Analysis 

7 A. National Benefits and Costs of the Proposed Rule 

8 B. Comparison of Benefits and Costs of Regulatory Alternatives of the Proposed Rule 

9 C. Conclusions 

10 VIII. Statutory and Executive Order Reviews 

11 A. Executive Order 12866: Regulatory Planning and Review 

12 B. Paperwork Reduction Act 

13 C. Regulatory Flexibility Act (RFA) 

14 D. Unfunded Mandates Reform Act (UMRA) 

15 E. Executive Order 13132: Federalism 

16 F. Executive Order 13175: Consultation and Coordination with Indian Tribal 

17 Governments 

18 G. Executive Order 13045: Protection of Children from Environmental Health Risks and 

19 Safety Risks 

20 H. Executive Order 13211: Actions that Significantly Affect Energy Supply, 

21 Distribution, or Use 

22 I. National Technology Transfer and Advancement Act 
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1 J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority 

2 Populations and Low-Income Populations 

3 IX. References 

4 

5 II. What is EPA Proposing Today? 

6 EPA is proposing to create a new category of injection well under its existing Underground 

7 Injection Control (UIC) Program with new minimum Federal requirements to allow for 

8 permitting of the injection of CO2 for the purpose of GS. Today’s proposal builds on existing 

9 UIC regulatory components for key areas including siting, construction, operation, monitoring 

10 and testing, and closure for injection wells that address the pathways through which underground 

11 sources of drinking water (USDWs) may be endangered. The Agency proposes to tailor existing 

12 UIC program components so that they are appropriate for the unique nature of injecting large 

13 volumes of CO2 into a variety of geological formations to ensure that USDWs are not 

14 endangered. 

15 

16 In addition to protecting USDWs, today’s proposed rule provides a regulatory framework to 

17 promote consistent approaches to permitting GS projects across the U.S and supports the 

18 development of a key climate change mitigation technology. 

19 

20 This proposal does not require any facilities to capture and/or sequester CO2; rather, this 

21 proposal focuses on underground injection of CO2 and outlines requirements that, if finalized, 

22 would protect USDWs under the SDWA. The SDWA provides EPA with the authority to 

23 develop regulations to protect USDWs. The SDWA does not provide authority to develop 
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1 regulations for all areas related to GS. These areas include, but are not limited to, capture and 

2 transport of CO2; determining property rights (i.e., to permit its use for GS and for possible 

3 storage credits); transfer of liability from one entity to another; and accounting or certification 

4 for greenhouse gas (GHG) reductions. EPA is not proposing regulations for CO2 under the Clean 

5 Air Act (CAA) in this proposed rulemaking. 

6 

7 A. Why is EPA Proposing to Develop New Regulations to Address GS of CO2? 

8 1. What is Geologic Sequestration (GS)? 

9 GS is the process of injecting CO2 captured from an emission source (e.g., a power plant or 

10 industrial facility) into deep subsurface rock formations for long-term storage. It is part of a 

11 process known as “carbon capture and storage” or CCS. 

12 

13 CO2 is first captured from fossil-fueled power plants or other emission sources. To transport 

14 captured CO2 for GS, operators typically compress CO2 to convert it from a gaseous state to a 

15 supercritical fluid (Christopher et al., 2008). CO2 exists as a supercritical fluid at high pressures 

16 and temperatures, and in this state it exhibits properties of both a liquid and a gas. After capture 

17 and compression, the CO2 is delivered to the sequestration site, typically by pipeline, or 

18 alternatively using tanker trucks or ships (WRI, 2007). 

19 

20 The CO2 is then injected into deep subsurface rock formations via one or more wells, using 

21 technologies that have been developed and refined by the oil and gas and chemical 

22 manufacturing industries over the past several decades. To store the CO2 as a supercritical fluid, 

23 it would likely be injected at depth (greater than approximately 800 meters, or 2,625 feet), such 
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1 that a sufficiently high pressure and temperature would be maintained to keep the CO2 in a 

2 supercritical state. 

3 

4 When injected in an appropriate receiving formation, CO2 is sequestered by a combination of 

5 trapping mechanisms, including physical and geochemical processes. Physical trapping occurs 

6 when the relatively buoyant CO2 rises in the formation until it reaches a stratigraphic zone with 

7 low fluid permeability (i.e., geologic confining system) that inhibits further upward migration. 

8 Physical trapping can also occur as residual CO2 is immobilized in formation pore spaces as 

9 disconnected droplets or bubbles at the trailing edge of the plume due to capillary forces. A 

10 portion of the CO2 will dissolve from the pure fluid phase into native ground water and 

11 hydrocarbons. Preferential sorption occurs when CO2 molecules attach onto the surfaces of coal 

12 and certain organic-rich shales, displacing other molecules such as methane. Geochemical 

13 trapping occurs when chemical reactions between the dissolved CO2 and minerals in the 

14 formation lead to the precipitation of solid carbonate minerals. (Wilson, 2004; IPCC 2005) 

15 

16 The effectiveness of physical CO2 trapping is demonstrated by natural analogs worldwide in a 

17 range of geologic settings, where CO2 has remained trapped for millions of years. For example, 

18 CO2 has been trapped for more than 65 million years under the Pisgah Anticline, northeast of the 

19 Jackson Dome in Mississippi and Louisiana, with no evidence of leakage. (IPCC, 2005) 

20 

21 2. Why is Geologic Sequestration Under Consideration as a Climate Change Mitigation 

22 Technology? 
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1 Greenhouse gases (GHGs) perform the necessary function of keeping the planet’s surface warm 

2 enough for human habitation. But, the concentrations of GHGs continue to increase in the 

3 atmosphere, and according to data from the National Oceanic and Atmospheric Administration 

4 (NOAA) and National Aeronautics and Space Administration (NASA), the Earth's average 

5 surface temperature has increased by about 1.2 to 1.4o F in the last 100 years. Eleven of the last 

6 twelve years rank among the twelve warmest years on record (since 1850), with the two warmest 

7 years being 1998 and 2005. Most of the warming in recent decades is very likely the result of 

8 human activities (IPCC, 2007). The burning of fossil fuels, e.g., from coal-fired electric plants 

9 and other sources in the electricity and industrial sectors, is a major contributor to human10 induced greenhouse gas emissions. 

11 

12 Fossil fuels are expected to remain the mainstay of energy production well into the 21st century, 

13 and increased concentrations of CO2 are expected unless energy producers reduce the CO2

14 emissions to the atmosphere. The capture and storage of CO2 would enable the continued use of 

15 coal in a manner that greatly reduces the associated CO2 emissions while other safe and 

16 affordable alternative energy sources are developed in the coming decades. Given the United 

17 States’ abundant coal resources and reliance on coal for power generation, CCS could be a key 

18 mitigation technology for achieving domestic emissions reductions. 

19 

20 Estimates based on DOE and IEA studies indicate that areas of the U.S. with appropriate geology 

21 could theoretically provide storage potential for over 3,000 gigatons (or 3,000,000 megatons) of 

22 geologically sequestered CO2. Theoretically, this capacity could be large enough to store a 

23 thousand years of CO2 emissions from nearly 1,000 coal-fired power plants. Worldwide, there 
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1 appears to be significant capacity in subsurface formations both on land and under the seafloor to 

2 sequester CO2 for hundreds, if not thousands of years. CCS technologies could potentially 

3 represent a significant percentage of the cumulative effort for reducing CO2 emissions worldwide 

4 until 2100. 

5 

6 While predictions about large-scale availability and the rate of CCS project deployment are 

7 subject to considerable uncertainty, EPA analyses of Congressional climate change legislative 

8 proposals (the McCain-Lieberman bill S. 280, the Bingaman-Specter bill S. 1766, and the 

9 Lieberman-Warner bill S. 2191) indicate that CCS has the potential to play a significant role in 

10 climate change mitigation scenarios. For example, analysis of S. 2191 indicates that CCS 

11 technology could account for 30 percent of CO2 emission reductions by 2050. 

12 (http://www.epa.gov/climatechange/economics/economicanalyses.html)

13 

14 It is important to note that GS is only one of a portfolio of options that could be deployed to 

15 reduce CO2 emissions. Other options could include efficiency improvements and the use of 

16 alternative fuels and renewable energy sources. Today’s proposal provides a regulatory 

17 framework to protect USDWs as this key climate mitigation technology is developed and 

18 deployed. This proposal provides certainty to industry and the public about requirements that 

19 would apply to injection, by providing consistency in requirements across the U.S., and 

20 transparency about what requirements apply to owners or operators. 

21 

22 Establishing a supporting regulatory framework for the future development and deployment of 

23 CCS technology can provide the regulatory certainty needed to foster industry adoption of CCS, 
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1 which is crucial to supporting the goals of any proposed climate change legislation. This 

2 proposed rule is consistent with and supports a strategy to address climate change through: (1) 

3 slowing the growth of emissions; (2) strengthening science, technology and institutions; and (3) 

4 enhancing international cooperation. EPA plays a significant role in implementing this strategy 

5 through encouraging voluntary GHG emission reductions, and working with other agencies 

6 including DOE to establish programs that promote climate technology and science. 

7 

8 B. What is EPA’s Authority Under the SDWA to Regulate Injection of CO2? 

9 Underground injection wells are regulated under the authority of Part C of the Safe Drinking 

10 Water Act (42 U.S.C. 300h et seq.). The SDWA is designed to protect the quality of drinking 

11 water sources in the U.S. and prescribes that EPA issue regulations for State programs that 

12 contain “minimum requirements for effective programs to prevent underground injection which 

13 endangers drinking water sources.” Congress further defined endangerment as follows: 

14 

15 Underground injection endangers drinking water sources if such injection may result in 

16 the presence in underground water which supplies or can reasonably be expected to 

17 supply any public water system of any contaminant, and if the presence of such 

18 contaminant may result in such system’s not complying with any national primary 

19 drinking water regulation or may otherwise adversely affect the health of persons. 

20 (Section 1421(d)(2) of the SDWA, 42 U.S.C. 300h(d)(2)). 

21 

22 Under this authority, the Agency has promulgated a series of UIC regulations at 40 CFR Parts 

23 144 through 148. The chief goal of any federally approved UIC Program (whether administered 
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1 by a State, Territory, Tribe or EPA) is the protection of USDWs. This includes not only those 

2 formations that are presently being used for drinking water, but also those that can reasonably be 

3 expected to be used in the future. EPA has established through its UIC regulations that USDWs 

4 are underground aquifers with less than 10,000 milligrams per liter (mg/L) total dissolved solids 

5 (TDS) and which contain a sufficient quantity of ground water to supply a public water system. 

6 (40 CFR 144.3) Section 1421(b) (3)(A) of the Act also provides that EPA’s UIC regulations 

7 shall “permit or provide for consideration of varying geologic, hydrological, or historical 

8 conditions in different States and in different areas within a State.” 

9 

10 EPA promulgated administrative and permitting regulations, now codified in 40 CFR Parts 144 

11 and 146, on May 19, 1980 (45 FR 33290), and technical requirements, in 40 CFR Part 146, on 

12 June 24, 1980 (45 FR 42472). The regulations were subsequently amended on August 27, 1981 

13 (46 FR 43156), February 3, 1982 (47 FR 4992), January 21, 1983 (48 FR 2938), April 1, 1983 

14 (48 FR 14146), May 11, 1984 (49 FR 20138), July 26, 1988 (53 FR 28118), December 3, 1993 

15 (58 FR 63890), June 10, 1994 (59 FR 29958), December 14, 1994 (59 FR 64339), June 29, 1995 

16 (60 FR 33926), December 7, 1999 (64 FR 68546), May 15, 2000 (65 FR 30886), June 7, 2002 

17 (67 FR 39583), and November 22, 2005 (70 FR 70513). 

18 

19 Under the SDWA, the injection of any “fluid” is subject to the requirements of the UIC program. 

20 “Fluid” is defined under 40 CFR 144.3 as any material or substance which flows or moves 

21 whether in a semisolid, liquid, sludge, gas or other form or state, and includes the injection of 

22 liquids, gases, and semisolids (i.e., slurries) into the subsurface. Examples of the fluids currently 

23 injected into wells include CO2 for the purposes of enhancing recovery of oil and natural gas, 
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1 water that is stored to meet water supply demands in dry seasons, and wastes generated by 

2 industrial users. CO2 injected for the purpose of GS is subject to the SDWA (42 U.S.C. 300f et 

3 seq.). EPA regulates both pollutants and commodities under the UIC provisions; however, 

4 today’s proposal does not address the status of CO2 as a pollutant or commodity. In addition, 

5 whether or not a fluid could be sold on the market as a commodity is outside the scope of EPA’s 

6 authority under the SDWA to protect USDWs. 

7 

8 There are limited injection activities that are exempt from UIC requirements including the 

9 storage of natural gas (Section 1421(b)(2)(B)). This exclusion applies to the storage of natural 

10 gas as it is commonly defined—a hydrocarbon—and not to injection of other matter in a gaseous 

11 state such as CO2. A more detailed summary of EPA’s authority to regulate the injection of CO2 

12 can be found in the docket 

13 

14 Other authorities: Today’s proposal applies to injection wells in the U.S. including those in 

15 State territorial waters. Wells up to three miles offshore may be subject to other authorities or 

16 may require approval under other authorities such as the Marine Protection, Research, and 

17 Sanctuaries Act (MPRSA). EPA recently submitted to Congress proposed changes to MPRSA to 

18 implement the 1996 Protocol to the London Convention on ocean dumping (the "London 

19 Protocol"). Among the proposed changes is a provision to allow for and regulate carbon 

20 sequestration in sub-seabed geological formations under the MPRSA. 

21 

22 C. Who Implements the UIC Program? 
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1 Section 1422 of the SDWA provides that States, Territories and federally recognized Tribes may 

2 apply to EPA for primary enforcement responsibility to administer the UIC program; those 

3 governments receiving such authority are referred to as “Primacy States.” Section 1422 requires 

4 Primacy States to meet EPA’s minimum Federal requirements for UIC programs, including 

5 minimum construction, operating, monitoring and testing, reporting, and closure requirements 

6 for well owners or operators. Where States, Territories, and Tribes do not seek this 

7 responsibility or fail to demonstrate that they meet EPA’s minimum requirements, EPA is 

8 required to implement a UIC program for them by regulation. 

9 

10 Additionally, Section 1425 allows States, Territories, and Tribes seeking primacy for Class II 

11 wells to demonstrate that their existing standards are effective in preventing endangerment of 

12 USDWs. These programs must include requirements for permitting, enforcement, inspection, 

13 monitoring, record-keeping, and reporting that demonstrate the effectiveness of their 

14 requirements. 

15 

16 Thirty-three States and three Territories currently have primacy to implement the UIC program. 

17 EPA shares implementation responsibility with seven States and directly implements the UIC 

18 Program for all well classes in 10 states, two Territories, the District of Columbia, and all Tribes. 

19 At the time of this proposal, no Tribes have been approved for primacy for the UIC Program. 

20 However, at the time of this published notice Fort Peck Assiniboine and Sioux Tribes in EPA 

21 Region 8 and the Navajo Nation in EPA Region 9 have pending primacy applications. 

22 
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1 EPA believes that the most effective approach for the comprehensive management of CO2 GS 

2 projects would be achieved at the State and Tribal level. EPA is aware that some States with 

3 primacy for the UIC program are actively engaged in the process of developing their own 

4 regulatory frameworks for the GS of CO2. In some cases, these frameworks include capture, 

5 transportation and injection requirements. While EPA encourages States to move forward with 

6 initiatives to protect USDWs and public health, it is important to note that States wishing to 

7 retain UIC primacy will need to promulgate regulations that are at least as stringent as those that 

8 will ultimately be finalized following this proposed rulemaking. In an attempt to reduce 

9 uncertainty in this proposed rulemaking, the Agency will keep States apprised of its efforts to 

10 establish new minimum Federal UIC GS requirements. 

11 

12 Additionally, EPA seeks comment on any aspects of the ongoing State efforts to regulate the GS 

13 of CO2 (see docket for details on State initiatives) and how these efforts might be used to better 

14 inform a final Federal rulemaking. 

15 

16 D. What are the Risks Associated with CO2 GS? 

17 An improperly managed GS project has the potential to endanger USDWs. The factors that 

18 increase the risk of USDW contamination are complex and can include improper siting, 

19 construction, operation and monitoring of GS projects. Today’s proposal addresses 

20 endangerment to USDWs by establishing new minimum Federal requirements for the proper 

21 management of CO2 injection and storage. Risks to USDWs from improperly managed GS 

22 projects can include CO2 migration into USDWs, causing the leaching and mobilization of 

23 contaminants (e.g., arsenic, lead, and organic compounds) and the movement of saltier formation 
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1 fluids into USDWs, causing degradation of water quality. 

2 

3 While the focus of today’s proposal is the protection of USDWs, EPA recognizes that injection 

4 activities could pose additional risks that are unrelated to the protection of USDWs including 

5 risks to air, human health, and ecosystems. The measures taken to prevent migration of CO2 to 

6 USDWs in today’s proposal will also prevent the migration of CO2 to the surface. A more 

7 detailed discussion follows. 

8 

9 Potential USDW Impacts: 

10 Injected CO2 is likely to come in contact with water in the formation fluids of the geologic 

11 formations into which it is injected. When CO2 mixes with water it forms a weak acid known as 

12 carbonic acid. Over time, carbonic acid could acidify formation waters potentially causing 

13 leaching and mobilization of naturally occurring metals or other contaminants (e.g., arsenic, lead, 

14 and organic compounds). CO2 may also release contaminants into solution by replacing 

15 molecules that are sorbed to the surface of the formation, for example, organic molecules such as 

16 polycyclic aromatic hydrocarbons (PAHs) in coal beds. The migration of formation fluids 

17 containing mobilized contaminants could cause endangerment of USDWs. 

18 

19 Another concern for USDWs is the presence of impurities in the CO2 stream. These impurities, 

20 although a relatively small percentage of the total fluid, could include hydrogen sulfide, 

21 sulfurous and nitrous oxides. Because of the volume of the CO2 that could be injected, there 

22 may be a risk that co-contaminants in the CO2 stream could endanger a USDW if the injectate 

23 migrates into a USDW. Additionally, when fluids are injected in large quantities, the potential 
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1 exists for injection to force native brines (naturally occurring salty water) into USDWs. 

2 

3 Improperly operated injection activities may cause geomechanical and/or geochemical effects 

4 which may deteriorate the integrity of the initially intact caprock overlying a storage reservoir. 

5 For example, injection of CO2 at high pressure could induce fracturing or could open existing 

6 fractures, thereby increasing movement through the caprock and enabling CO2 to migrate out of 

7 the storage reservoir, and potentially into USDWs. 

8 

9 Other Potential Impacts: 

10 Human Health: Improperly operated injection activities or ineffective long-term storage could 

11 result in the release of injected CO2 to the atmosphere, resulting in the potential to impact human 

12 health and surrounding ecosystems under certain circumstances. While CO2 is present normally 

13 in the atmosphere, depending on the concentration and duration of exposure, CO2 can be an 

14 asphyxiant. Direct exposure to elevated levels of CO2 can cause both chronic and acute health 

15 effects to humans and animals. Wind speed and direction, topography and geographic location 

16 can have a role in the severity of the human health impact of a CO2 release. 

17 

18 EPA considers that risk of asphyxiation from properly managed CO2 injection activities is 

19 minimal based on experience gained in the oil and gas industry, experience from international 

20 GS projects, and evaluations of large scale releases of naturally occurring CO2. 

21 

22 EPA collected information on the use of CO2 injection in the oil and gas industry which has 

23 decades of experience in drilling through highly pressurized formations and injecting CO2 for the 
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1 purpose of enhanced recovery. Internationally, CO2 has been injected on very large scales at 

2 three sites: at Sleipner in the North Sea, at In Salah in Algeria, and in the Weyburn Field in 

3 Alberta, Canada (see section E.3 of this document). There have been no documented cases of 

4 leakage from these projects, nor has there been release and surface accumulation of CO2 such 

5 that asphyxiation would have been possible. 

6 

7 However, some CO2 releases from injection activity have been documented. An example of a 

8 significant CO2 leak occurred at Crystal Geyser, Utah. CO2 and water erupted from an 

9 abandoned oil exploration well due to improper well plugging. This well continues to erupt 

10 periodically and discharges 12,000 kilotons of CO2 annually. Studies indicated that within a few 

11 meters of the well, CO2 concentrations were below levels that could adversely affect human 

12 health. (Lewicki et al., 2006) 

13 

14 EPA also evaluated the occurrence of natural discharges of CO2 to determine whether such 

15 releases could be caused by CO2 injection or whether injection could result in release of similar 

16 magnitudes. Although natural underground CO2 reservoirs exist throughout the world in 

17 volcanically active areas, there are very few instances of rapid discharge of large amounts of CO2

18 to the surface (Lewicki et al., 2006). Unusually large and rapid releases of CO2 from lake 

19 bottom storage reservoirs occurred at Lake Nyos and Lake Monoun in Cameroon in the 1980s, 

20 causing asphyxiation. These catastrophic events stemmed from a phenomenon known as “limnic 

21 eruption.” Prolonged high ambient temperatures led to prolonged stratification that allowed 

22 naturally occurring CO2 to slowly accumulate at the bottom of the lakes over many years. Large 

23 volumes of CO2 escaped during an abrupt lake turnover, possibly prompted by volcanic activity. 
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1 

2 While lake turnover can bring CO2 stored in the deepest layers of lake water to the surface 

3 almost instantaneously, geologic confining systems do not experience this type of rapid and 

4 complete turnover. GS would store CO2 beneath many layers of rock with a well-defined 

5 geologic confining system. Even if a geologic confining system were compromised, any 

6 migration of CO2 towards the surface would not be analogous to a limnic eruption. Pathways for 

7 CO2 leakage from geologic storage reservoirs are generally conductive faults or fractures. In 

8 some cases CO2 may spread diffusely through overlying rocks and soils (Lewicki et al., 2006). 

9 None of these conditions is a likely conduit for release of CO2 on the scale of the releases at 

10 Lakes Nyos and Monoun. 

11 

12 Ecosystem: Improperly operated CO2 injection activities resulting in a release of CO2 to the 

13 atmosphere may have a range of effects on exposed terrestrial and aquatic ecosystems. Due to 

14 organisms’ varied sensitivities to environmental and habitat changes, certain organisms may be 

15 adversely affected at different CO2 exposure levels. Surface-dwelling animals, including 

16 mammals and birds, could be affected similarly to humans when directly exposed to elevated 

17 levels of CO2. The exposure could cause both chronic and acute health effects depending on the 

18 concentration and duration of exposure (Benson et al., 2004). Plants, while dependent upon CO2

19 for photosynthesis, could also be adversely affected by elevated CO2 levels in the soil because 

20 the CO2 will inhibit respiration (Vodnik et al., 2006). Soil acidity changes resulting from 

21 increased CO2 concentrations may adversely impact both plant (McGee and Gerlach, 1998) and 

22 soil dwelling organisms (Benson et al., 2004). Elevated CO2 concentrations in aquatic 

23 ecosystems can impede fish respiration resulting in suffocation (Maina, 1998), increase pH 
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1 (acidity of the water) to lethal levels and reduce the calcification in shelled organisms, and may 

2 adversely affect photosynthesis of some aquatic organisms (Turley et al., 2006). The risk of 

3 adverse impacts to ecosystems from properly managed CO2 injection activities is minimal. 

4 

5 Seismic events: Improperly operated injection of CO2 could raise pressure in the formation, and 

6 if too high, injection pressure could “re-activate” otherwise dormant faults, potentially inducing 

7 seismic events (earthquakes). Rarely, small induced seismic events have been associated with 

8 past injection of large fluid volumes. Before a Federal UIC Program was formed, injection 

9 activities at the Rocky Mountain Arsenal in Colorado from 1963 to 1968 induced measurable 

10 seismic activity. This incident was the result of poor site characterization and well operation and 

11 was among the primary drivers that prompted Congress to pass legislation establishing the UIC 

12 Program. Recently, the IPCC (2005) concluded that, because there have been few seismic events 

13 associated with deep-well injection, the risks of induced seismicity are low. 

14 

15 Today’s proposal contains safeguards to ensure that potential endangerment to USDWs from 

16 CO2 injection is addressed before the commencement of full-scale GS projects. While 

17 preventing releases of CO2 to the atmosphere is not within the scope of this proposal, today’s 

18 proposed rulemaking also addresses the risks posed by releases to the atmosphere by ensuring 

19 that injected CO2 remains in the confining formations. The measures outlined in today’s 

20 proposed rulemaking to prevent endangerment of USDWs may also prevent migration of CO2 to 

21 the surface. A more complete discussion of the potential risks posed by GS is in the 

22 Vulnerability Evaluation Framework (VEF). (USEPA, 2008b). 
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1 

2 E. What Steps has EPA Taken to Inform Today’s Proposal? 

3 EPA has taken a number of steps to support today’s proposal including: 1) building on the 

4 experience of the UIC Program, 2) identifying the risks to USDWs from GS activities; 3) 

5 tracking the results on ongoing research; 4) identifying technical and regulatory issues associated 

6 with pilot and full-scale GS projects; 5) coordinating with stakeholders on the rulemaking 

7 process; and 6) providing guidance and reviewing permits for initial pilot-scale projects. 

8 

9 1. Building on the existing UIC program framework to specifically address CO2 injection 

10 EPA’s UIC regulations prohibit injection wells from causing “the movement of fluid containing 

11 any contaminant into an underground source of drinking water, if the presence of that 

12 contaminant may cause a violation of any primary drinking water regulation...or may otherwise 

13 adversely affect the health of persons” (40 CFR 144.12(a)). The federal UIC Program has been 

14 implemented since 1980 and has responsibility for managing over 800,000 injection wells. The 

15 programmatic components of the UIC Program are designed to prevent fluid movement into 

16 USDWs by addressing the potential pathways through which injected fluids can migrate into 

17 USDWs. These components are described below: 

18 

19 • Siting: EPA requires injection wells to be sited to inject into a zone capable of storing the 

20 fluid, and to inject below a confining system that is free of known open faults or fractures 

21 that could allow upward fluid movement that endangers USDWs. 

22 • Area of Review (AoR) and Corrective Action: The Agency requires examination of both the 

23 vertical and horizontal extent of the area that will potentially be influenced by injection and 
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1 storage activities and identification of all artificial penetrations in the area that may act as 

2 conduits for fluid movement into USDWs (e.g., active and abandoned wells) and, as needed, 

3 perform corrective action to these open wells. 

4 • Well Construction: EPA requires injection wells to be constructed using well materials and 

5 cements that can withstand injection of fluids over the anticipated life span of the project. 

6 • Operation: Injection pressures must be monitored so that fractures that could serve as fluid 

7 movement conduits are neither propagated into the layers in which fluids are injected or 

8 initiated in the confining systems above. 

9 • Mechanical Integrity Testing (MIT): The integrity of the injection well system must be 

10 monitored at an appropriate frequency to provide assurance that the injection well is 

11 operating as intended and is free of significant leaks and fluid movement in the well bore. 

12 • Monitoring: Owners or operators must monitor the injection activity using available 

13 technologies to verify the location of the injected fluid, the pressure front, and demonstrate 

14 that injected fluids are confined to intended storage zones (and, therefore, injection activities 

15 are protective of USDWs). 

16 • Well Plugging and Post-Injection Site Care: At the end of the injection project, EPA requires 

17 injection wells to be plugged in a manner that ensures that these wells will not serve as 

18 conduits for future fluid movement into USDWs. Additionally, owners or operators must 

19 monitor injection wells to ensure fluids in the storage zone do not pose an endangerment to 

20 USDWs. 

21 

22 Today's proposal builds upon these longstanding UIC programmatic components and tailors 

23 them based on the current state of knowledge about the injection of CO2 for GS purposes. 
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1 

2 2. Identifying the Risks to USDWs from Injection of CO2

3 The existing UIC program provides a foundation for designing a regulatory framework for GS 

4 projects that prevents endangerment to USDWs. The Agency has evaluated the risks of CO2

5 injection to USDWs to determine how best to tailor the existing UIC regulations to address the 

6 buoyant and viscous properties of CO2 and the large volumes that could be injected. 

7 

8 EPA developed the Vulnerability Evaluation Framework (VEF), an analytical framework that 

9 identifies and offers approaches to evaluate the potential for a GS project to experience CO2

10 leakage and associated adverse impacts. The VEF is a high-level screening approach that can be 

11 used to identify key GS system attributes that should be evaluated further to establish site 

12 suitability and targeted monitoring programs. The VEF is focused on the three main parts of GS 

13 systems: the injection zone, the confining system, and the CO2 stream. The VEF first identifies 

14 approaches to evaluate key geologic attributes of GS systems that could influence vulnerability 

15 to leakage or pressure changes. It then describes an approach to define the area that should be 

16 evaluated for adverse impacts associated with leakage or pressure changes. Finally, the VEF 

17 identifies receptors that could be adversely impacted if leakage or pressure changes were to 

18 occur. The assessment of vulnerabilities to leakage and pressure changes, and of the potential 

19 impacts to receptors, is described in a series of detailed decision-support flowcharts. (Some of 

20 the impacts addressed in the VEF, e.g., to the atmosphere or ecological receptors, are outside of 

21 the scope of today’s proposal.) The draft VEF report (USEPA, 2008b) is included in the docket 

22 for this proposed rulemaking and is available online at [www.epa.gov/]. 

23 
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1 EPA and the Department of Energy (DOE) are jointly funding the Lawrence Berkeley National 

2 Laboratory (LBNL) to study potential impacts of CO2 injection on ground water aquifers and 

3 drinking water sources. As part of the same study, LBNL is also assessing potential changes in 

4 regional ground water flow, including displacement of pre-existing saline water or hydrocarbons 

5 that could impact USDWs or other resources. EPA is receiving interim progress reports from 

6 LBNL activities and will post them on EPA’s website and in the docket as they become 

7 available. EPA and DOE are also jointly funding the Pacific Northwest National Laboratory 

8 (PNNL) to perform technical analyses on conducting site assessments, evaluating reservoir 

9 suitability, and modeling the flow of injected CO2 in geologic formations. 

10 

11 3. Tracking the results of CO2 GS research projects 

12 EPA is tracking the progress and results of national and international GS research projects. DOE 

13 leads experimental field research on GS in the U.S. in conjunction with the Regional Carbon 

14 Sequestration Partnerships (RCSP) program. Collectively, the seven RCSPs represent regions 

15 encompassing 97 percent of coal-fired CO2 emissions, 97 percent of industrial CO2 emissions, 96 

16 percent of the total U.S. land mass, and nearly all the GS sites in the U.S. potentially available 

17 for carbon storage. Approximately 400 organizations, including State geologists, industry and 

18 environmental organizations, and national laboratories are involved with the RCSPs. 

19 

20 DOE’s 2007 Roadmap (DOE, 2007b) describes DOE-sponsored research designed to gather data 

21 on the effectiveness and safety of CO2 GS in various geologic settings through the RSCPs. The 

22 Roadmap describes three phases of research, each of which builds upon the previous phase. 

23 During the Characterization Phase (2003 to 2005) the partnerships studied regionally-specific 
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1 sequestration approaches as well as potentially needed regulations and infrastructure 

2 requirements for GS deployment. During the Validation Phase (2005-2009), approximately 25 

3 pilot tests will be performed to validate the most promising GS technologies, evaluate regional 

4 CO2 repositories, and identify best management practices for future deployment. During the 

5 Deployment Phase (2008-2017), the partnerships will conduct large volume carbon storage tests 

6 to demonstrate that large-scale CO2 injection and storage can be achieved safely and 

7 economically. EPA will use the data collected from these projects to support decisions in the 

8 final GS rule. Additional information on DOE’s research and the partnerships is available at 

9 http://www.fossil.energy.gov/sequestration/partnerships/index.html.

10 

11 EPA is also communicating with other research organizations and academic institutions 

12 conducting GS research. These institutions include Princeton University, which has a research 

13 program for assessing potential problems with degradation of well material from the geologic 

14 sequestration of CO2 and the Massachusetts Institute of Technology, which has a CCS program 

15 emphasizing safe and effective future use of coal as a prime energy source. 

16 

17 EPA is also monitoring the progress of international GS efforts. Three projects of note are 

18 underway in the North Sea, Algeria, and Canada, whose results are being used to inform today’s 

19 proposal. 

20 

21 The Sleipner Project, located off the Norwegian coast in the North Sea, is the first commercial 

22 scale GS project into a saline formation. Approximately 1 Mt CO2 is removed annually from the 

23 natural gas produced in the Sleipner West Gas Field and injected 800 m (2400 ft) below the 
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1 seabed. Injection began in August 1996, and operators expect to store 20 Mt CO2 over the 

2 expected 25-year life of the project. Activities include baseline data gathering and evaluation, 

3 reservoir characterization and simulation, assessment of the need and cost for monitoring wells, 

4 and geophysical modeling. Seismic time-lapse surveys have been used to monitor movement of 

5 the CO2 plume and demonstrate effectiveness of the cap rock. (IPCC, 2005) 

6 

7 The In Salah Gas Project, in the central Saharan region of Algeria, is the world's first large-scale 

8 CO2 storage project in a gas reservoir. CO2 is stripped from natural gas produced from the 

9 Krechba Field and re-injected via three horizontal injection wells into a 1,800 meter-deep 

10 sandstone reservoir. Approximately 1.2 Mt CO2 have been injected annually since April 2004 

11 and it is estimated that 17 Mt CO2 will be stored over the life of the project. To characterize the 

12 site, 3-D seismic surveys and well data have been used to map the field, identify deep faults, 

13 establish as baseline, and conduct a risk assessment of storage integrity. Planned monitoring at 

14 the site includes use of noble gas tracers, pressure surveys, tomography, gravity baseline studies, 

15 microbiological studies, four-dimensional seismic, and geomechanical monitoring. (IPCC, 2005) 

16 

17 Weyburn is an EOR project where the CO2 produced at a coal gasification plant in Beulah, ND is 

18 piped to Weyburn in southeastern Saskatchewan for EOR. Approximately 1.5 Mt CO2 are to be 

19 injected annually via a combination of vertical and horizontal injection wells. It is expected that 

20 20 Mt CO2 will be stored in the field over the 20 to 25 year life of the CO2-EOR project. The 

21 monitoring regime at the site includes high-resolution seismic surveys and surface monitoring to 

22 determine any potential leakage. (IPCC, 2005) The conclusions of Phase I of the project are that 
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1 depleted oil and gas reservoirs from EOR operations are a promising CO2 storage option and that 

2 4-D seismic monitoring is a valuable tool for plume tracking. (IEA, 2005) 

3 

4 Other ongoing GS projects include the Gorgon Gas Development project, a deep saline 

5 formation project in Barrow Island, Western Australia; the Otway (Australia) Project, where GS 

6 is taking place in a saline formation within a depleted natural gas reservoir; the South Quinshu 

7 Basin, China Enhanced Coalbed Methane (ECBM)/CO2 sequestration project; the CO2SINK 

8 project in Ketzin, Germany (a sandstone saline formation); and testing of CO2 GS in the Deccan 

9 Trap basalts of India. 

10 

11 4. Identifying Technical and Regulatory Issues Associated with CO2 GS 

12 EPA has conducted a series of technical workshops with regulators, industry, utilities, and 

13 technical experts to identify and discuss questions relevant to the effective management of CO2

14 GS. 

15 

16 EPA held a technical workshop on measurement, monitoring, and verification that focused on 

17 the availability and utility of various subsurface and near-surface monitoring techniques that may 

18 be applicable to GS projects. This workshop, co-sponsored by the Ground Water Protection 

19 Council (GWPC), took place in New Orleans, LA on January 16, 2008. 

20 

21 The Agency held a technical workshop on geological considerations for siting and Area of 

22 Review studies to discuss subsurface geologic information needed to determine whether a site is 

23 appropriate for GS; the role of artificial conduits in the AoR on siting decisions; factors that 
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1 affect the size and shape of the AoR; and corrective actions to address wells in the AoR. 

2 Representatives of the RCSPs and the Interstate Oil and Gas Compact Commission (IOGCC) 

3 presented their experiences with pilot and experimental GS projects. This workshop took place 

4 in Washington, DC on July 10 and 11, 2007. 

5 

6 EPA also held a technical workshop on well construction and MIT that included experimental 

7 research in the U.S. and Canada on wellbore integrity and CO2-cement interactions, modeling, 

8 the impact of wellbore integrity on GS site selection, and industry research on well construction. 

9 This workshop was held in Albuquerque, New Mexico on March 14, 2007, with participation 

10 from the International Energy Association (IEA), an international organization evaluating 

11 technical issues associated with CCS. 

12 

13 EPA and DOE collaborated on the State Regulators’ Workshop on GS of CO2 to discuss and 

14 formulate the questions related to CO2 injection that should be addressed in the development of a 

15 GS management framework. At this workshop, held in conjunction with the GWPC’s UIC 

16 Technical meeting in San Antonio, Texas on January 24, 2007, participants identified a set of 

17 research questions on the following topics: site characterization, modeling, AoR, injection well 

18 construction, MIT, monitoring, closure and post-injection site care, and liability and financial 

19 responsibility. The questions they raised set the agenda for future technical workshops as well as 

20 established the foundation for today’s proposal. 

21 

22 Participants at the International Symposium on Site Characterization for CO2 Geological 

23 Storage, an EPA sponsored meeting with LBNL, held in Berkeley, California on March 20-22, 
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1 2006, discussed various aspects of site characterization and selection of potential CO2 storage 

2 sites. The symposium emphasized advances in the site characterization process, development of 

3 measurement methods, identification of key site features and parameters and case studies. 

4 

5 At a workshop on Risk Assessment for Geologic CO2 Storage, participants discussed the 

6 development of a risk assessment framework to identify potential risks related to GS of CO2 and 

7 to consider relevant field experience that could be applicable to injection and long-term storage 

8 of CO2. Some of the key topics addressed at the workshop were: abandoned wells, faults, and 

9 groundwater displacement. This workshop, co-sponsored by GWPC, took place in Portland, 

10 Oregon on September 28-29, 2005. 

11 

12 On April 6-7, 2005, EPA held a workshop on Modeling and Reservoir Simulation for Geologic 

13 Carbon Storage in Houston, Texas. The topics of this workshop included: an assessment of the 

14 potential applications of reservoir models and reservoir simulations to GS; use of models for risk 

15 assessments and risk communication throughout the life cycle of a CO2 storage reservoir; a 

16 discussion of areas of new research and data needs to improve the application of modeling and 

17 reservoir simulation for carbon storage. 

18 

19 Summaries of the workshops described above are available on EPA’s web site, at 

20 http://www.epa.gov/safewater/uic/wells_sequestration.html. 

21 

22 5. Stakeholder Coordination and Outreach 
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1 Stakeholder participation is an important component of today’s proposed rulemaking. EPA held 

2 public meetings to discuss EPA’s rulemaking approach, met with State and Tribal 

3 representatives, and consulted with other stakeholder groups including NGOs to gain an 

4 understanding of stakeholder concerns. 

5 

6 Public Meetings: EPA conducted two public stakeholder workshops with participants from 

7 industry, environmental groups, utilities, academia, States, and the general public. These 

8 workshops were held in December 2007 and February 2008. The December 2007 workshop 

9 provided EPA with an opportunity to hear stakeholders’ perspectives and concerns. EPA and 

10 stakeholders discussed issues including the rulemaking process, existing regulations and 

11 regulatory components, statutory authority, GS technology, and technical issues associated with 

12 GS. During the February 2008 workshop, EPA provided a comprehensive review of how current 

13 UIC program elements could be tailored for the purposes of CO2 injection for GS. Smaller 

14 technical sessions were dedicated to discussion of key questions and considerations related to 

15 Area of Review and Site Characterization, Monitoring, Long-term Financial Assurance, and 

16 Public Participation. Technical discussions and stakeholder feedback from these workshops 

17 were used to inform today’s proposal. Summaries of these workshops are available on EPA’s 

18 web site, at http://www.epa.gov/safewater/uic/wells_sequestration.html

19 

20 State and Tribal Meetings: EPA coordinated with the Ground Water Protection Council 

21 (GWPC), a State association that focuses on ensuring safe application of injection well 

22 technology and protecting ground water resources. In the past several years, GWPC meetings 

23 have included sessions on many of the key GS technical and policy issues described above. 
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1 EPA’s participation in these sessions has resulted in a clearer understanding of the regulatory 

2 issues associated with the implementation of GS of CO2. 

3 

4 EPA also coordinated with the Interstate Oil and Gas Compact Commission (IOGCC), a 

5 chartered State association representing oil and gas producing States. These State members have 

6 specific expertise regulating the injection of CO2 for the enhanced recovery of oil and gas. 

7 Additionally, EPA reviewed the IOGCC’s model State geologic sequestration regulatory 

8 framework to help inform today’s proposal. 

9 

10 During the development of the proposed rule, EPA contacted all federally recognized tribes to 

11 invite their engagement in the rulemaking process and held a dedicated conference call with the 

12 tribes. EPA will continue an ongoing dialogue with interested tribes on this rulemaking. 

13 

14 During the development of the proposed rule, EPA contacted state and local government 

15 associations to invite their engagement in the rulemaking process and held a dedicated 

16 conference call with their representatives. EPA will continue an ongoing dialogue with 

17 interested state and local associations on this rulemaking. 

18 

19 The Agency also held meetings and presented information about the proposed rulemaking to 

20 members of the water utility sector. These organizations included the American Water Works 

21 Association (AWWA), Association of Metropolitan Water Agencies (AMWA), and the America 

22 Public Power Association (APPA). 

23 
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1 In addition, EPA consults with the National Drinking Water Advisory Council (NDWAC) a 

2 group that operates under the SDWA to provide advice to EPA’s drinking water program and 

3 reports to EPA’s Administrator. NDWAC consists of members of the general public, drinking 

4 water experts, State and local agencies, and private groups concerned with safe drinking water. 

5 In support of the proposed rulemaking and in accordance with statutory requirements, EPA 

6 consulted with the Department of Health and Human Services. EPA will conduct further 

7 consultations prior to finalization of the GS regulation. 

8 

9 The Agency also meets annually with the American Association of State Geologists (AASG) to 

10 discuss key topics related to protecting and preserving ground water resources. AASG members 

11 are State geologists from around the country who over the past several years have met with EPA 

12 to discuss injection-related activities, including CO2 GS. 

13 

14 Other stakeholder discussions: EPA invited key Non-Governmental Organizations to discuss the 

15 potential application of GS as a safe and effective climate change mitigation tool. Attendees of 

16 these meetings included Environmental Defense, the National Resources Defense Council, the 

17 Clean Air Task Force, the World Resources Institute, and others. In addition, EPA attended and 

18 participated in numerous conferences and technical symposia on GS. These meetings, attended 

19 by various stakeholders, included sessions on technical issues related to GS and were organized 

20 or attended by DOE’s National Energy Technology Laboratory (NETL), the American 

21 Petroleum Institute (API), Society of Petroleum Engineers (SPE), and the International Energy 

22 Agency (IEA). EPA also attends meetings of the Intergovernmental Panel on Climate Change 
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1 (IPCC) and events hosted by the World Resource Institute (WRI), including recent meetings 

2 focused on long-term liability and frameworks and standards for GS programs. 

3 

4 6. Providing Technical Guidance and Reviewing Permits for Initial Pilot-Scale Projects 

5 EPA issued program technical guidance to assist State and EPA Regional UIC programs in 

6 processing permit applications for pilot and other small scale experimental GS projects. This 

7 guidance was developed in cooperation with DOE and with States, through GWPC and IOGCC 

8 and other stakeholders. UIC Program Guidance # 83: Using the Class V Experimental 

9 Technology Well Classification for Pilot Carbon Geologic Sequestration Projects (UICPG#83, 

10 March 2007) assists permit writers in evaluating permit applications for pilot-scale GS projects. 

11 It clarifies the use of the UIC Class V experimental well classification for GS demonstration 

12 projects and provides recommendations to permit writers on how they can issue permits that 

13 allow experimental data to be collected while ensuring that USDWs are protected during 

14 injection. This guidance will continue to apply to pilot-projects as long as the projects continue 

15 to qualify under the guidelines for experimental wells laid out in UICPG #83. It will also remain 

16 a permitting option for future projects, as long as new projects are experimental in nature and 

17 continue to collect data and conduct research. The program guidance is available at: 

18 http://www.epa.gov/safewater/uic/wells_sequestration.html. 

19 

20 Currently, EPA Regional and State UIC programs are using this guidance to authorize a number 

21 of Class V experimental technology wells. The guidance is being used to help create a nationally 

22 consistent permitting framework that draws on the key technical components that affect the 

23 endangerment potential of CO2 GS. These experimental projects will continue to provide EPA 
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1 and States with critical information that will improve EPA’s understanding of the risks posed by 

2 CO2 injection for GS and the operational, technical, and administrative considerations for the 

3 advancement and appropriate permitting of this technology. This information will support 

4 EPA’s final decision on how to regulate GS activities. 

5 

6 F. Why is EPA Proposing to Develop a New Class of Injection Well for GS of CO2? 

7 EPA is proposing to establish a new class of injection well for GS projects because CO2 injection 

8 for long-term storage presents several unique challenges that warrant designation of a new well 

9 type. When EPA initially promulgated its UIC regulations, the Agency defined five classes of 

10 injection wells at 40 CFR 144.6, based on similarities in the fluids injected, construction, 

11 injection depth, design, and operating techniques. These five well classes are still in use today 

12 and are described below. 

13 

14 Class I wells inject industrial non-hazardous liquids, municipal wastewaters or hazardous wastes 

15 beneath the lowermost USDW. These wells are most often the deepest of the UIC wells and are 

16 managed with technically sophisticated construction and operation requirements. 

17 

18 Class II wells inject fluids in connection with conventional oil or natural gas production, 

19 enhanced oil and gas production and the storage of hydrocarbons which are liquid at standard 

20 temperature and pressure. 

21 

22 Class III wells inject fluids associated with the extraction of minerals or energy, including the 

23 mining of sulfur and solution mining of minerals. 
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1 

2 Class IV wells inject hazardous or radioactive wastes into or above USDWs. Few Class IV wells 

3 are in use today; these wells are banned unless authorized under an approved Federal or State 

4 ground water remediation project. 

5 

6 Class V includes all injection wells that are not included in Classes I-IV. In general, Class V 

7 wells inject non-hazardous fluids into or above USDWs; however, there are some deep Class V 

8 wells that inject below USDWs. 

9 

10 Today’s proposed rulemaking would establish a new class of injection well – Class VI – for GS 

11 projects based on the unique challenges of preventing potential endangerment to USDWs from 

12 these operations. The Agency invites public comment on the appropriateness of this 

13 classification. 

14 

15 G. How would today’s proposal affect existing injection wells under the UIC Program? 

16 CO2 is currently injected in the U.S. under two well classifications: Class II and Class V 

17 experimental technology wells. The requirements in today’s proposal, if finalized, would not 

18 specifically apply to Class II injection wells or Class V experimental technology injection wells. 

19 Class VI requirements would only apply to injection wells specifically permitted for the purpose 

20 of GS. 

21 
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1 Existing wells currently permitted as Class I, Class II, or Class V experimental technology wells 

2 could potentially be re-classified for GS of CO2. However the owner or operator would need to 

3 follow the permitting process outlined in today’s proposal to receive a Class VI permit. 

4 

5 EPA is proposing to give the Director discretion to carry over or “grandfather” the construction 

6 requirements for existing Class I and Class II wells seeking a permit for GS of CO2, provided 

7 he/she is able to make a determination that these wells would not endanger USDWs. Although 

8 CO2 is not currently injected in Class I wells, Class I well construction requirements are similar 

9 to those for Class VI. Today’s proposal requires that the owner or operator make a 

10 demonstration that the well will maintain integrity and stability in a CO2 rich environment for the 

11 life of the GS project. Only the construction requirements would be grandfathered under today’s 

12 proposal, therefore, Class I or Class II owners or operators seeking to change the purpose of their 

13 injection well from Class I or Class II to Class VI would need to meet the other requirements of 

14 today’s proposed rule (e.g., operating, monitoring, MIT, plugging and post-injection site care and 

15 closure). 

16 

17 EPA’s program guidance on issuing Class V Experimental Technology Well permits (EPA, 

18 2007) encourages owners or operators and permitting authorities to consider the potential for 

19 changing the purpose of demonstration wells to full-scale GS when designing and approving 

20 experimental GS projects. EPA understands, based on reviews of several Class V pilot project 

21 permits that many of these wells are specifically designed for injection of CO2 and are being 

22 built to Class I non-hazardous well specifications. 

23 
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1 Accordingly, EPA is proposing that the Director have the discretion to “grandfather” the 

2 construction requirements for Class V experimental wells when they are converted to full-scale 

3 GS Class VI wells. As with converted Class I and Class II wells, these grandfathered wells 

4 would be required to meet the other requirements of today’s proposed rule (e.g., operating, 

5 monitoring, MIT, plugging and post-injection site care and closure). 

6 

7 EPA seeks comment on the approach to grandfather construction requirements at the Director’s 

8 discretion for existing Class I, Class II and Class V wells seeking to convert to Class VI wells 

9 and whether additional construction requirements would be necessary to prevent endangerment 

10 to USDWs from the GS of CO2. 

11 

12 H. What are the Target Geologic Formations for GS of CO2? 

13 A range of geologic formations is being assessed as potential target formations for receiving and 

14 sequestering CO2. Target formations with the greatest GS capacity include deep saline 

15 formations, depleted oil and gas reservoirs, unmineable coal seams, and other formations. 

16 

17 Deep saline formations: DOE estimates indicate that up to 80 percent of the capacity for CO2

18 injected for GS is in deep saline formations. These formations are deep and geographically 

19 extensive sedimentary rock layers saturated with waters or brines that have a high TDS content 

20 (i.e., over 10,000 mg/L TDS). Deep saline formations are found throughout the U.S. and many 

21 of these formations may be overlain by laterally extensive, impermeable formations that may 

22 restrict upward movement of injected CO2. All of these characteristics make deep saline 

23 formations the leading candidates for GS. Since most deep saline formations have not been 
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1 extensively investigated, a thorough site-specific characterization of saline formations proposed 

2 for GS will be necessary. Such characterizations will need to demonstrate the safety and 

3 efficacy of these sites for GS and rule out the presence of fractures, faults, or other characteristics 

4 that may endanger USDWs. 

5 

6 Depleted oil and gas reservoirs: DOE estimates that depleted oil and gas reservoirs represent 

7 approximately seven percent of the potential CO2 storage capacity in the U.S. and Canada. 

8 Because many of these reservoirs have trapped liquid and gaseous hydrocarbon resources for 

9 millions of years, EPA believes that they can also be used to sequester CO2. Hydrocarbons are 

10 commonly trapped structurally, by faulted, folded, or fractured formations, or stratigraphically, 

11 in porous formations bounded by impermeable rock formations. These same trapping 

12 mechanisms can effectively store CO2 for GS in depleted oil and gas reservoirs. 

13 

14 Oil and gas exploration activities have generated a great deal of geologic data on depleted oil and 

15 gas reservoir sites. This information would be directly transferable to the GS site 

16 characterization process. Furthermore, models can predict the movement and displacement of 

17 hydrocarbons in oil and gas reservoirs and can be used to further advance site specific 

18 knowledge about CO2 storage. 

19 

20 It should also be noted that there are technical challenges associated with GS in depleted oil and 

21 gas reservoirs. Injection volumes, operation conditions, and formation pressures for CO2

22 injection will differ from those of traditional EOR/EGR operations. The American Petroleum 

23 Institute (API) estimates that over 0.6 gigatons of CO2 have been injected for EOR/EGR 
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1 operations to date and a large percentage of this CO2 is recovered through production (causing a 

2 pressure decrease in the reservoir). (Meyer, undated) However, DOE estimates that over 90 

3 gigatons of CO2 could be geologically sequestered in U.S. oil and gas reservoirs resulting in the 

4 potential for reservoir-wide pressure increases. 

5 

6 Depleted oil and gas reservoirs will contain numerous artificial penetrations (e.g., active and 

7 abandoned injection and production wells, water wells, etc.) and other types of conduits that 

8 could be potential pathways for CO2 migration. Some of these wells may be decades old, 

9 constructed or plugged with materials that may not be able to withstand long-term exposure to 

10 CO2 or may be difficult to locate. Locating and assessing the integrity of these wells and 

11 performing appropriate corrective action are essential to assuring that they would not serve as 

12 conduits for movement of injected CO2 or displaced fluids to USDWs. 

13 

14 Unmineable coal seams: Unmineable coal seams represent approximately 13 percent of the 

15 remaining potential U.S. storage capacity. Currently, enhanced coalbed methane (ECBM) 

16 operations exploit the preferential chemical affinity of coal for CO2 relative to the methane that 

17 is naturally found on the surfaces of coal. When CO2 is injected, it is adsorbed to the coal 

18 surface and releases methane, which can then be captured and produced for economic purposes. 

19 DOE estimates that for every molecule of methane displaced in ECBM operations, three to 13 

20 CO2 molecules are adsorbed. This process effectively “locks” the CO2 to the coal, where it 

21 remains sequestered. 

22 
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1 There are a number of technical challenges related to use of coal seams for GS. While coal 

2 seams are well studied and understood, the process of CO2 adsorption to coal has not been 

3 proven and the chemical reactions of supercritical CO2 within coal formations are not well 

4 understood. In addition, coals swell as CO2 is adsorbed, which can reduce the permeability and 

5 injectivity of the coal seams, requiring higher injection pressures. (IPCC, 2005) There are 

6 currently no commercial scale CO2 ECBM projects, and ECBM with simultaneous CO2 storage 

7 is an emerging technology that is in the demonstration phase. (Dooley et al., 2006; IPCC, 2005) 

8 In addition, many ECBM recovery operations will likely be shallow. Shallow storage will result 

9 in the CO2 remaining in a gaseous state, which can limit the amount of CO2 that can be 

10 sequestered. Coal seams and water-bearing formations in close proximity to coal seams may 

11 contain less than 10,000 mg/L TDS and meet the definition of a USDW. 

12 

13 EPA is concerned that coal seams in close proximity to USDWs and CO2 injection for GS could 

14 endanger USDWs. In some cases, coal seams are considered USDWs and may serve as public 

15 drinking water supplies. As a result, EPA is proposing to preclude the injection of CO2 for long16 term storage into coal seams where they are above the lowermost USDW. Today’s proposal 

17 would not affect injection activities where the primary purpose of the activity is methane 

18 production (a Class II activity). 

19 

20 Other formations: Other formations under investigation for CO2 storage include basalts, salt 

21 domes, and shales. These formations are limited in geographic and geologic distribution 

22 throughout the U.S., and their technological or economic viability as GS sites have not been 

23 demonstrated. In basalts, the injected CO2 could react with embedded silicate minerals and form 
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1 carbonate minerals that would be trapped in the basalt. Mined salt domes or salt caverns could 

2 be used for CO2 storage using processes similar to those used by industry to store natural gas. 

3 (IPCC, 2005) Other abandoned mines (e.g., potash, lead, or zinc deposits or abandoned coal 

4 mines) are also CO2 storage options. (IPCC, 2005) CO2 storage in organic-rich shales, to which 

5 CO2 could adsorb to organic materials in a process similar to coal seam adsorption, is also a 

6 possible storage option. (DOE, 2007a) As with unmineable coal seams, the location and 

7 proximity of these other formations to USDWs may preclude their use for GS. 

8 

9 I. Is Injected CO2 Considered a Hazardous Waste under RCRA? 

10 In developing today’s proposal, EPA considered the potential for hazardous constituents to be 

11 present in the injectate, and, whether their presence could render the injected CO2 stream a 

12 hazardous waste. The composition of the captured CO2 stream will depend on the source, the 

13 flue gas scrubbing technology for removing pollutants, additives, and the CO2 capture 

14 technology. In most cases, the captured CO2 will contain some impurities, however, 

15 concentrations of impurities are expected to be very low. (Apps, 2006) 

16 

17 Because the types of impurities and their concentrations in the CO2 stream are likely to vary by 

18 facility, coal composition, plant operating conditions, and pollution removal technologies, EPA 

19 cannot make a categorical determination as to whether injected CO2 is hazardous under RCRA. 

20 Owners or operators will need to characterize their CO2 stream as part of their permit application 

21 to determine if the injectate is considered hazardous as defined in 40 CFR Part 261. If the 

22 injectate is considered hazardous under RCRA, then the UIC Class I requirements for injection 

23 of hazardous waste apply. The design changes EPA is proposing are meant to address the 
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1 mobility and corrosivity caused by long term GS of CO2, and not the long term storage of 

2 hazardous wastes. 

3 

4 By defining “carbon dioxide stream” to exclude hazardous wastes (146.81(d)), if finalized, 

5 today’s rule assures that it would apply only to CO2 streams that are not hazardous wastes as 

6 defined in 40 CFR Part 261. As a result, today’s proposed rule would preclude the injection of 

7 hazardous wastes in Class VI injection wells. 

8 

9 J. Is Injected CO2 considered a hazardous substance under CERCLA? 

10 The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), also 

11 more commonly known as Superfund, is the law that provides broad federal authority to clean up 

12 releases or threatened releases of hazardous substances that may endanger human health or the 

13 environment. CERCLA references four other environmental laws to designate more than 800 

14 substances as hazardous and to identify many more as potentially hazardous due to their 

15 characteristics and the circumstances of their release. It allows EPA to clean up sites 

16 contaminated with hazardous substances and seek compensation from responsible parties, or 

17 compel responsible parties to perform cleanups themselves. A responsible party may be able to 

18 avoid liability through several enumerated defenses, including that the release constituted a 

19 “federally permitted release” as defined in CERCLA, 42 U.S.C. 9601(10). 

20 

21 While CO2 itself is not listed as a hazardous substance under CERCLA, the CO2 stream may 

22 contain other substances such as mercury that are hazardous substances or the constituents of the 
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1 CO2 stream could react with groundwater to produce listed hazardous substances such as sulfuric 

2 acid. Thus, whether or not there is a “hazardous substance” that may result in CERCLA liability 

3 from a sequestration facility depends entirely on the make-up of the specific CO2 stream and of 

4 the environmental media (e.g., soil, groundwater) in which they are stored. Moreover, while 

5 CERCLA exempts from liability certain “federally permitted releases” including releases in 

6 compliance with a UIC permit under SDWA, there may be situations where releases occur that 

7 are beyond the scope of the GS project’s Class VI permit. Such releases may not be “federally 

8 permitted” and, as a result, such releases may be subject to future CERCLA liability. Therefore, 

9 EPA cannot make a definitive statement in this proposed rule regarding the CERCLA liability of 

10 owners and operators of sequestration facilities. 

11 

12 The determination of liability would be made on a case-by-case basis by Federal courts in 

13 response to claims for natural resource damages (NRD) or response costs. A NRD claim could 

14 be brought by the U.S. or a State or Tribe. Any person, including a private party, that took a 

15 response action, could bring a claim for response costs. 

16 

17 III. Proposed Regulatory Alternative

18 The regulatory alternatives for managing CO2 injection for GS have been informed by the 

19 existing UIC program regulations and supplementary contributions from parties with expertise 

20 related to the challenges associated with GS of CO2. In preparing today’s proposal, EPA 

21 consulted with regulators, industry, utilities, and other technical experts; considered input 

22 provided at the technical workshops and stakeholder meetings; and reviewed research, early pilot 

23 GS project permits, and IOGCC’s model rules and regulations (IOGCC, 2007). 
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1 

2 EPA considered four alternatives for developing GS regulations. The four alternatives vary in 

3 stringency and specificity as described below. 

4 

5 Alternative 1: Non-specific Requirements Approach. This alternative is the least specific and 

6 stringent of the alternatives EPA considered. It includes no specific requirements for site 

7 characterization, well construction, or monitoring; rather, it applies a performance standard 

8 approach, specifying that GS wells be sited, constructed, operated, maintained, monitored, and 

9 closed in a manner that protects USDWs from endangerment. 

10 

11 Alternative 2: General Requirements Approach. This alternative provides more specificity than 

12 the previous alternative and includes standards for siting, construction, operation, and monitoring 

13 associated with basic deep well design and operation. The general requirements approach also 

14 gives permitting authorities flexibility to interpret certain elements in setting permit 

15 requirements; however, this alternative does not contain specific program requirements for 

16 technical challenges not currently addressed in the program such as long-term CO2 storage and 

17 large volumes. 

18 

19 Alternative 3: Tailored Requirements Approach. This approach builds on the general 

20 requirements approach by incorporating technical standards for deep-well injection of non21 hazardous fluids where appropriate and tailoring them to address the challenges of long-term 

22 CO2 storage. This approach also gives permitting authorities discretion in how to permit certain 

23 elements and in requiring additional information. 
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1 

2 Alternative 4: Highly Specific Requirements Approach. The highly specific requirements 

3 approach describes specific technologies and information needed for site characterization, AoR 

4 modeling, well construction, monitoring, and testing. Many components of this alternative equal 

5 or exceed the requirements for Class I hazardous waste injection wells. 

6 These alternatives are described in more detail in the document, “Regulatory Alternatives for 

7 Managing Geologic Sequestration of CO2.” (EPA 2008d) 

8 

9 A. Proposed Alternative 

10 EPA is proposing Regulatory Alternative 3, the Tailored Requirements Approach. The technical 

11 requirements of this alternative build upon the existing UIC regulatory framework for deep wells 

12 and are appropriately tailored to address the unique nature of full-scale CO2 GS. The tailored 

13 requirements approach promotes USDW protection, incorporates flexibility or the discretion of 

14 the permitting authority when appropriate, seeks to limit unnecessary burden on owners or 

15 operators or permitting agencies and provides the foundation for national consistency in 

16 permitting of GS projects. Because of the volumes of CO2 being anticipated for long-term 

17 storage, the buoyant and viscous nature of the injectate, and its corrosivity when mixed with 

18 water, EPA is proposing changes to the existing UIC approach or requirements in several 

19 program areas, including site characterization, area of review, well construction, mechanical 

20 integrity testing, monitoring and post-injection site care. 

21 

22 EPA did not select alternative 1 (Non-Specific Requirements Approach) because it does not 

23 provide enough specificity to ensure that permitting authorities manage GS wells appropriately 
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1 to prevent endangerment of USDWs. In addition, this alternative may be burdensome for owners 

2 or operators because of the potential for inconsistency across States and burdensome for 

3 permitting authorities who will likely be faced with developing their own technical approaches to 

4 regulating GS. Alternative 1 could create an uncertain regulatory landscape for owners or 

5 operators seeking to operate facilities in multiple states or seeking to manage projects that cross 

6 state boundaries. 

7 

8 Although alternative 2 (General Requirements Approach) provides standards for siting, 

9 construction, operation, and monitoring associated with basic deep well design and operation, 

10 EPA did not select this alternative because it is not tailored to meet the unique challenges of 

11 long-term CO2 storage. While this option includes flexibility for permit authorities to add 

12 requirements, EPA cannot be certain that the necessary adjustments would be made. 

13 

14 Alternative 4 (Highly Specific Requirements Approach) lacks the flexibility for incorporating 

15 and adapting to evolving GS technologies and provides no clear additional benefits beyond 

16 alternative 3 for USDW protection, therefore, EPA did not select this alternative. 

17 

18 1. Proposed Geologic Siting Requirements 

19 Existing UIC requirements for siting injection wells include identification of geologic formations 

20 suitable to receive the injected fluids and confine them such that they are isolated below the 

21 lowermost USDWs, minimizing the potential for endangerment. While initial assessments 

22 indicate there are many geologic formations in the U.S. that can potentially receive injected CO2, 

23 not all can serve as adequate CO2 GS sites. 
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1 

2 A detailed geological assessment is essential to evaluating the presence and adequacy of the 

3 various geologic features necessary to receive and confine large volumes of injected CO2 so that 

4 the injection activities will not endanger USDWs. Thus, EPA is proposing that owners or 

5 operators submit maps and cross sections of the USDWs near the proposed injection well. 

6 

7 Injection wells are drilled to a receiving zone, also known as the injection zone. The injection 

8 zone is typically a layer or layers of porous rocks, such as sandstone, that can receive large 

9 volumes of fluids without fracturing. Today’s proposal would require that owners or operators 

10 submit data to demonstrate that the injection zone is sufficiently porous to receive the CO2

11 without fracturing and extensive enough to receive the anticipated total volumes of injected CO2. 

12 Owners or operators would submit geologic core data, outcrop data, seismic survey data, cross 

13 sections, well logs, and other data that demonstrate the lateral extent and thickness, strength, 

14 capacity, porosity, and permeability of subsurface formations. The injection zone should be of a 

15 sufficient lateral extent that the CO2 can move a sufficient distance away from the well and still 

16 remain in the same zone, without displacing fluids into USDWs. Structural features of a 

17 potential injection zone reservoir, such as the lateral extent, dip, or the presence of “pinch-outs” 

18 (i.e., thinning or tapering out) can affect storage potential, and therefore should be examined. 

19 

20 The injection zone should be overlain by a low permeability confining system consisting of a 

21 geological formation, part of a formation, or group of formations that limits the injected fluid 

22 from migrating upwards out of the injection zone. The buoyancy of CO2 necessitates good 

23 characterization of potential conduits for fluid migration upward through the confining system to 
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1 USDWs. The confining system should be of sufficient regional thickness and lateral extent to 

2 contain the entire CO2 plume and associated pressure front under the confining system following 

3 the plume’s maximum lateral expansion. 

4 

5 EPA proposes that owners or operators of proposed GS projects present to the permitting 

6 authority data on the local geologic structure, including information on the presence of any faults 

7 and fractures that transect the confining zone and a demonstration that they would not interfere 

8 with containment. These data will support determinations about whether these features, if 

9 present, could potentially become conduits for movement of CO2 or other fluids to shallower 

10 layers, including USDWs. Under today’s proposal, owners or operators must perform and 

11 submit the results of geomechanical studies of fault stability and rock stress, ductility, and 

12 strength. 

13 

14 Today’s proposal would require that owners or operators submit information on the seismic 

15 history of the area and the presence and depth of seismic sources to assess the potential for 

16 injection-induced earthquakes. These examinations, along with interpretation of geologic maps 

17 and cross sections and geomechanical data, are proposed to help rule out sites with unacceptably 

18 high potential for seismic activity. Information on in-situ fluid pressures is also required to 

19 assess the potential for the pressures associated with injection to reactivate faults or to determine 

20 appropriate operating requirements. 

21 

22 A variety of techniques are available to characterize the receiving zones and confining zones of 

23 proposed GS sites. For example, geologic core data, test wells, and well logs can help determine 
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1 rock formations’ strength and extent. Seismic and electrical methods can be used to reveal 

2 subsurface features. Gravity anomalies indicate density variations at depth, and gravity surveys 

3 can be used to locate voids, such as cavities and abandoned mines. Carbon/oxygen surveys can 

4 indicate how much hydrogen is in a formation and, therefore, its porosity. Large scale, regional 

5 pressure tests can also provide insight into the fluid flow field and the presence and properties of 

6 major faults and fractures that may affect flow and transport of CO2 and displaced brines. 

7 

8 Underground injection wells, if improperly sited and operated, have the potential to induce 

9 seismicity, which may cause damage to reservoir and fault seals, creating conduits for fluid 

10 movement into USDWs. Today’s proposal would require that owners or operators only allow 

11 injection without initiating or propagating fractures in the confining zone. To prevent this, only 

12 maximum sustainable injection pressures that will not allow unpermitted fluid movement should 

13 be determined prior to CO2 injection. Estimates of maximum sustainable fluid pressures in CO2

14 storage sites are primarily based on predicted changes of effective stresses in rocks during CO2

15 injection and associated pore-pressure increase. (Streit and Siggins, 2004) Geomechanical 

16 studies of fault stability and rock stresses and strength, based on examination and interpretation 

17 of geological maps and cross sections, seismic and well surveys, determination of local stress 

18 fields, and modeling, can also help rule out sites with unacceptably high potential for seismic 

19 activity. (IPCC, 2005) 

20 

21 The geochemistry of formation fluids can also affect whether a site is suitable for GS. CO2 may 

22 act as a solvent, and can mix with native fluids to form carbonic acid, which can react with 

23 minerals in the formation. Dissolution of minerals may liberate heavy metals into the formation 
Deliberative draft – do not cite or distribute Page 63 

1 fluids. Reactions may also break down the rock matrix or precipitate minerals and plug pore 

2 spaces, therefore reducing permeability. (IPCC, 2005) Studies of rock samples and review of 

3 geochemical data from monitoring wells are needed to evaluate the impact of these effects. 

4 Today’s proposal would require owners or operators to submit geochemical data on a) the 

5 injection zone, b) the confining zones, c) containment zones above the confining zones in which 

6 any potentially migrating CO2 could be trapped, d) all USDWs, and e) any other geologic zone or 

7 formation that is important to the proposed monitoring program. The geochemical data are 

8 important for identifying potential chemical or mineralogical reactions between the CO2 and 

9 formation fluids that can break down the rock matrix or precipitate minerals that could plug pore 

10 spaces and reduce permeability. Additionally, pre-injection geochemical data can serve as 

11 baseline data to which results of future monitoring would be compared throughout the injection 

12 phase. This information can also improve predictions about trapping mechanisms (which, in turn 

13 may improve predictions of pressure changes in the subsurface and the ultimate size of the CO2

14 plume). 

15 

16 Today’s proposal would provide the Director the discretion to require the owner or operator to 

17 identify and characterize additional confining and containment zones above the primary (i.e., 

18 lowermost) confining zone that could further impede vertical fluid movement and allow for 

19 pressure dissipation. These layers could provide additional sites for monitoring, mitigation, and 

20 remediation. Today’s proposal would not require that these additional zones be identified for all 

21 GS sites because their absence does not necessarily indicate inappropriateness of a GS site. 

22 However, if such zones are present, information about their characteristics can provide inputs for 

23 predictive models, identify appropriate monitoring locations, and improve public confidence in 
Deliberative draft – do not cite or distribute Page 64 

1 and acceptance of a proposed GS site. EPA specifically seeks comment on the merits of 

2 identifying these additional zones. 

3 

4 2. Proposed Area of Review and Corrective Action Requirements 

5 Delineating the Area of Review: Under the UIC program, EPA established an evaluative 

6 process to determine that there are no features near the well such as faults, fractures or artificial 

7 penetrations, where significant amounts of injected fluid could move into a USDW or displace 

8 native fluids into USDWs. Current UIC regulations require that the owner or operator define the 

9 Area of Review (AoR), within which the owner or operator must identify all penetrations in the 

10 confining zone and the injection zone and determine whether they have been properly completed 

11 or plugged. The AoR determination is integral to the determination of geologic site suitability 

12 because it requires the delineation of the storage operation and an identification and evaluation of 

13 any penetrations that could result in the endangerment of USDWs. (40 CFR 146.6) 

14 

15 For Class I, II, and III injection wells, Federal UIC regulations require that the AoR be defined as 

16 either a fixed radius of 1⁄4 mile surrounding the well (or wells, for an area permit) or an area 

17 above the injected fluid and pressure front determined by a computational model. For Class I 

18 hazardous waste injection wells, the AoR is defined as a radius of two (2) miles around the well 

19 or an area defined based on the calculated cone of pressure influence, whichever is larger. 

20 

21 It is generally agreed that over time, the CO2 plume and pressure front associated with a full22 scale GS project will be much larger than for other types of UIC injection operations, potentially 

23 encompassing many square miles. In addition, the complexity of CO2 behavior in the subsurface 
Deliberative draft – do not cite or distribute Page 65 

1 may produce a non-circular AoR. It is also possible that multiple owners or operators will be 

2 injecting CO2 into formations that are hydraulically connected, and thus the elevated pressure 

3 zones may intersect or interfere with each other. Traditional AoR delineation methods such as a 

4 fixed radius or simple mathematical computations would not be sufficient to predict the extent of 

5 this movement. 

6 

7 EPA believes that predicting the complex multi-phase buoyant flow of the CO2, co-injectates, 

8 and compounds that may be mobilized due to injection requires the sophistication of 

9 computational models. EPA proposes that the owners or operators of GS wells delineate the 

10 AoR for CO2 GS sites using computational fluid flow models designed for the specific site 

11 conditions and injection regime. 

12 

13 Multiphase models are the most comprehensive type of computational model available to predict 

14 fluid movement in the subsurface under varying conditions or scenarios, and EPA considers 

15 them to be appropriate for delineating the AoR for GS projects. This approach was also 

16 recommended by IOGCC, workshop participants, and regional and State permit writers for GS 

17 operations. EPA seeks comment on the use of modeling for AoR delineation. 

18 

19 Modeling CO2 Movement and Reservoir Pressure: Computational models used to delineate the 

20 AoR consider the buoyant nature and specific properties of separate phases of the injected CO2

21 and native fluids within the injection zone. The models should be based on site characterization 

22 data collected regarding the injection zone and confining system, taking into account any 
Deliberative draft – do not cite or distribute Page 66 

1 geologic heterogeneities, and potential migration through faults, fractures, and artificial 

2 penetrations. 

3 

4 Appropriate models may incorporate numerical, analytical, or semi-analytical approaches. These 

5 models solve a series of governing equations to predict the composition and volumetric fraction 

6 (i.e., the fraction of the formation pore-space taken up by that fluid) of each phase state (e.g., 

7 liquid, gas, supercritical fluid), as well as fluid pressures, as a function of location and time for a 

8 particular set of conditions. 

9 

10 EPA has found that multiphase, computational models are the most appropriate type of 

11 computational model to predict the fate and transport of CO2, co-injectates, and compounds 

12 mobilized due to injection. In order to provide guidance related to computational modeling of 

13 CO2 injection for GS, EPA invited expert advice and reviewed relevant technical documents. On 

14 April 6-7, 2005, EPA held a workshop on “Modeling and Reservoir Simulation for Geologic 

15 Carbon Storage” for 60 EPA headquarters and regional staff in Houston, Texas. Computational 

16 modeling for AoR determination was also discussed at several additional technical workshops 

17 (Section II E). Additionally, the Agency evaluated peer-reviewed journal articles and critical 

18 reviews pertaining to computational modeling of CO2 injection (UESEPA, 2008a). 

19 

20 Model results provide predictions of CO2 fate and transport, as wells as changes in formation 

21 pressure, in three dimensions as a function of time that can be used to delineate the subsurface 

22 storage site and the AoR. Models can also be used to develop monitoring plans, help to evaluate 

23 long-term containment, select and characterize suitable storage formations, assess the risk 
Deliberative draft – do not cite or distribute Page 67 

1 associated with CO2 leakage and other impacts to USDWs, and to design remediation strategies. 

2 Importantly, models can be used to predict CO2 movement in response to varying conditions or 

3 scenarios, such as changing injection rates, or the presence or absence of fractures or faults in 

4 confining layers. 

5 

6 Multiphase models have been used by States and industry for predicting the movement of water 

7 and solutes in soil, the behavior of non-aqueous phase liquid contaminants (e.g., trichloroethene) 

8 at hazardous waste sites, the recovery of oil and gas from petroleum-bearing formations and, 

9 more recently, CO2 in the subsurface. The existing computational codes used to create 

10 multiphase models vary substantially in complexity. For example, available codes differ in what 

11 processes (e.g., changes of state, chemical reactions) may be included in simulations. As model 

12 complexity increases, so does the computational power necessary to use the model, as well as the 

13 amount and type of data needed to properly instruct model development. However, more 

14 complex models, when properly used, have the potential to provide a more accurate 

15 representation of the storage project. 

16 

17 Multiphase models are developed based on a specified set of conditions, such as the formation’s 

18 geological structure and injection scenario, and inputs describing these conditions are included in 

19 an appropriate computational code. Properties of the formation (e.g., permeability, porosity, 

20 reservoir entry pressure) and fluids present (e.g., solubility, mass-transfer coefficients), are 

21 described by model parameters, the independent variables in the model governing equations that 

22 may be constant throughout the domain or vary in space and time. Model predictions depend 
Deliberative draft – do not cite or distribute Page 68 

1 largely on the values of key parameters. Often these parameter values are estimated or averaged 

2 from several data sources. 

3 

4 Models used for GS sites should be based on accepted science and should be validated. In some 

5 cases, owners or operators may choose to use proprietary models (i.e., not available for free to 

6 the general public). EPA is aware that the use of proprietary codes may prevent full evaluation 

7 of model results (e.g., NRC, 2007). Several popular codes in the petroleum-reservoir 

8 engineering discipline are proprietary and owners or operators of particular sites may prefer to 

9 use these codes as they have previous experience with them, and they have been used in peer10 reviewed studies to model CO2 sequestration. When using a proprietary model, owners or 

11 operators should clearly disclose the code assumptions, relevant equations, and scientific basis. 

12 EPA seeks comment on allowing the use of proprietary models for GS sites. 

13 

14 Today’s proposal does not specify a period of time over which the AoR delineation models 

15 should be run. Rather, available models can predict, based on proposed injection rates and 

16 volumes and information about the geologic formations, the ultimate plume movement up to the 

17 point the plume movement ceases or pressures in the injection zone sufficiently decline to the 

18 point that the plume and pressure front would no longer impact USDWs. 

19 

20 EPA recognizes that a range of models could be used to delineate the AoR and that some of these 

21 models may have been in use for some time. Models currently used to delineate AoR, regardless 

22 of age, are considered computational and may be appropriate for use in determining the AoR for 

23 GS of CO2. However, EPA anticipates that modeling technology will improve substantially, and 
Deliberative draft – do not cite or distribute Page 69 

1 encourages and expects owners or operators to use the best multiphase computational models 

2 available to determine the AoR. Reliance on improved models will likely increase the accuracy 

3 and quality of the AoR characterization, resulting in better protection of USDWs. 

4 

5 Model simulations and site monitoring are interdependent, and comprise an iterative, cyclical 

6 system. Model simulations can be used for an initial prediction of injected fluid movement to 

7 identify the type, number and location of monitoring points. As data are collected at an injection 

8 site, model parameters can be adjusted to match real-world observations (i.e., model calibration 

9 or history-matching), which in turn improves the predictive capability of the model. 

10 Additionally, model simulations are adjusted over time to reflect operational changes. Project 

11 performance is thus evaluated through a combination of site monitoring and modeling. 

12 

13 EPA seeks comment on the applicability of computational fluid flow models for delineating the 

14 AoR of GS sites. 

15 

16 Corrective Action: Today’s proposal would require that owners or operators of GS wells 

17 identify all artificial penetrations in the AoR (including active and abandoned wells and 

18 underground mines) based on publicly available information. This inventory and review process 

19 is similar to what is required of Class I and Class II injection well operators. 

20 

21 The owner or operator would compile, tabulate, and review all publicly available information on 

22 each well in the AoR that penetrates into the confining system, including casing and cementing 

23 information as well as records of plugging. If additional confining zones are identified, wells 
Deliberative draft – do not cite or distribute Page 70 

1 penetrating those additional zones would be included in this review. Based on this review, the 

2 owner or operator would identify the wells that need corrective action to prevent the movement 

3 of CO2 or other fluids into or between USDWs. Owners or operators would perform corrective 

4 action to address deficiencies in any wells that are identified as potential conduits for fluid 

5 movement into USDWs. Corrective action could be performed prior to injection or on a phased 

6 basis over the course of the project (as outlined in the next section.) Available corrective action 

7 techniques include plugging of offset wells or monitoring in the injection zone. Another 

8 example of corrective action is remedial cementing, in which owners or operators would squeeze 

9 cement to prevent upward migration along uncemented casing. 

10 

11 Today’s proposal does not prescribe the specific cements to be used to plug abandoned wells in 

12 the AOR because industry standards, such as those developed by API or ASTM International, 

13 reflect the current state of the science and the expertise of industrial users on corrosion-resistant 

14 materials. 

15 

16 Though today’s proposal does not dictate specific corrective action methods, it requires that the 

17 corrective action methods be appropriate to the CO2 injection. At the Technical Workshop on 

18 Geological Considerations and AoR Studies, participants generally concluded that the reaction of 

19 the CO2 injectate stream with typical well materials and cements that are likely to be encountered 

20 in abandoned wells in the AoR is an important consideration. Today’s proposal would require 

21 that corrective action for wells in the AoR of GS projects be performed with appropriate 

22 corrective action methods such as use of corrosion-resistant cements. 

23 
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1 Area of Review Reevaluation: Predicting the behavior of injected CO2 in the subsurface, 

2 particularly the ultimate extent of a CO2 plume and associated area of elevated pressure in a 

3 laterally expansive reservoir, poses uncertainties. Today’s proposal would require that the owner 

4 or operator periodically reevaluate the AoR during the injection operation. Reevaluations would 

5 occur at a minimum fixed frequency, not to exceed 10 years, as agreed upon by the Director. 

6 

7 When monitoring data differ significantly from modeled predictions, or when there are 

8 appreciable operational changes (e.g., injection rates) reevaluation may be mandated prior to the 

9 minimum fixed frequency. At no time would area of review reevaluations occur less frequently 

10 than every 10 years. 

11 

12 Reevaluations of the AoR would be based on revision and calibration of the original 

13 computational model used to delineate the AoR. If site monitoring data agrees with the existing 

14 AoR delineation, a model recalibration may not be necessary. In these cases, an AoR 

15 reevaluation may consist simply of a demonstration that the current AoR delineation is adequate 

16 based on site monitoring data. 

17 

18 There are many potential benefits to periodically reevaluating the AoR. Each revised model 

19 prediction would estimate the full extent of the CO2 plume and area of elevated pressure; 

20 however, the near-term predictions (e.g., over the subsequent 10 years) would have the highest 

21 degree of certainty and could be the basis of corrective action. Re-running the models would 

22 allow refinement to the AoR delineation based on real-world conditions and monitoring results, 

23 and thus increase confidence in the modeled predictions. The revised model predictions would 
Deliberative draft – do not cite or distribute Page 72 

1 also be used to identify monitoring sites so that monitoring would occur in any areas subject to 

2 the greatest potential risk. 

3 

4 EPA seeks comment on requiring the reevaluation of the site AoR on a periodic basis, under 

5 what conditions the AoR should be reevaluated, and the appropriateness of a 10 year minimum 

6 fixed frequency for AoR reevaluation. 

7 

8 Phased Corrective Action: In the UIC program, corrective action is typically performed on all 

9 wells in the AoR in advance of the injection project. Today’s proposal recognizes that this may 

10 not always be appropriate for GS projects. The AoR for a GS site may be quite large, requiring 

11 considerable time and resources to perform corrective action on all wells that may eventually be 

12 affected by the GS project over the course of decades of injection. In addition, if the periodic 

13 reevaluations of the AoR indicate that the AoR has grown or shifted to areas not originally 

14 included, additional wells may need to be identified for potential corrective action. 

15 

16 Today’s proposal would give the Director the discretion to allow owners or operators to perform 

17 corrective action on an iterative, phased basis over the operational life of a GS project. Prior to 

18 injection, the owner or operator would identify all wells penetrating the confining or injection 

19 zone within the site AoR. However, the owner or operator may limit pre-injection corrective 

20 action to those wells in the portion of the AoR that would be intersected by the CO2 plume or 

21 pressure front during the first years of injection. As the project continues and the plume 

22 expands, the owner or operator would continue to perform corrective action on wells further 

23 from the well to assure that all wells in the AoR that need corrective action eventually receive it. 
Deliberative draft – do not cite or distribute Page 73 

1 This approach would ensure that any necessary corrective action is taken in advance of the CO2

2 plume and associated area of elevated pressure approaching USDWs. 

3 

4 There are potential benefits to implementing phased corrective action. Phasing in the corrective 

5 action would benefit the owner or operator by spreading out the burden and costs of corrective 

6 action and not delaying initiation of the GS project while corrective action is performed at wells 

7 that may not be affected by the injection for several decades. Initial corrective action would 

8 focus on those penetrations that pose a potential endangerment to USDWs from injection of CO2

9 in the near term. Deferring corrective action on some of the wells at the outer reaches of the 

10 predicted plume can improve USDW protection by giving these later corrective action efforts the 

11 benefit of newer corrective action techniques. Additionally, this approach can prevent the 

12 unnecessary burden of performing corrective action in areas far from the injection zone that may 

13 never be impacted. This approach would still assure that all wells in the AoR that need 

14 corrective action eventually receive it, as is the case in current UIC requirements. 

15 

16 Participants at the technical workshops on “Geological Considerations and AoR Studies” and 

17 “Modeling and Reservoir Simulation for Geologic Carbon Storage” agreed that the AoR should 

18 be reevaluated over time based on incoming monitoring and site characterization data. In 

19 addition, participants at the February 2008 Stakeholder Workshop generally supported 

20 reevaluation of the AoR and a phased corrective action approach. 

21 

22 EPA recognizes that a phased approach to corrective action may not be appropriate in all 

23 situations; therefore EPA is proposing that the Director have the discretion to decide to allow this 
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1 approach, based on the understanding of relevant geologic and site conditions. EPA invites 

2 public comment on the merits and frequency of reevaluation of the AoR as well as the phased 

3 corrective action approach for GS wells. 

4 

5 Proposed Area of Review and Corrective Action Plan: For typical UIC wells, AoR is delineated 

6 only once, and corrective action on all wells in the AoR is performed prior to commencing 

7 injection. However, AoR and corrective action for GS wells will involve multiple steps over 

8 many years, so EPA proposes that the owner or operator of a GS well submit an AoR and 

9 corrective action plan as part of their permit application. After approved by the Director, the 

10 owner or operator would implement the plan. 

11 

12 In the AoR and corrective action plan, the owner or operator would describe plans to delineate 

13 the AoR, including the model to be used, assumptions made, and the site characterization data on 

14 which the modeling would be based. It would include a strategy for the owner or operator to 

15 periodically reevaluate the AoR in response to operational changes (e.g., injection rates), when 

16 monitoring data varies from modeled predictions, or at a minimum fixed frequency, not to 

17 exceed 10 years, as agreed upon by the Director. It should describe what monitoring data would 

18 be used to determine whether the AoR needs to be adjusted and how that data would be 

19 incorporated into the model. A description of how the public would be informed of changes in 

20 the AoR would be included. 

21 

22 The AoR and corrective action plan would also specify where corrective action would be 

23 performed prior to injection, and what, if any areas would be addressed on a phased basis. In 
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1 addition, the plan would identify how site access would be guaranteed for areas requiring future 

2 corrective action, and how corrective action may change to address potential changes in the AoR. 

3 

4 EPA also proposes that, as owners or operators periodically reevaluate the AoR delineation, they 

5 must either amend the Director-approved AoR and corrective action plan (i.e., to perform 

6 additional corrective action) or report to the Director that no changes to the plan are necessary. 

7 This approach promotes continued communication between the Director and the owner or 

8 operator regarding expectations over the long duration of CO2 injection, and assures that the 

9 AoR delineation methodology reflects local conditions. The proposed requirement to 

10 periodically revisit the modeling effort, which was advocated by stakeholders, would help to 

11 verify that the CO2 plume is moving as predicted and provide an opportunity to adjust the 

12 injection operation and corrective action to address changes in the predicted AoR. 

13 

14 3. Proposed Injection Well Construction Requirements 

15 Well construction procedures: Properly constructing an injection well is a technologically 

16 complex yet well understood undertaking. An appropriately designed and constructed well 

17 would prevent endangerment to USDWs and would maintain integrity throughout the lifetime of 

18 the project, from the injection operation period through and beyond the post-injection site care 

19 period once the well is permanently plugged. Current drilling and well construction practices for 

20 CO2 injection wells are based on existing knowledge and practices from the oil and gas industry. 

21 

22 A typical well is constructed by placing multiple strings of high strength steel alloy or fiberglass 

23 concentric pipe and tubing into a drilled wellbore. Typically, the first step in well construction is 
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1 the drilling of a large borehole (e.g., 10” to 30”) through the base of the lowermost USDW. A 

2 large diameter pipe, termed surface casing, is then placed in the wellbore to protect shallow 

3 aquifers or underground sources of drinking water during the drilling and injection phases. This 

4 casing is usually cemented by circulating cement between the outside of the surface casing and 

5 the side of the borehole to ensure that the wellbore is stabilized, that the casing is completely 

6 sealed to the rock of the wellbore, and that the geologic formations are isolated from each other 

7 and the surface. 

8 

9 Next, a smaller diameter wellbore (e.g., 7” to 15”) is drilled further downwards, into the injection 

10 zone, and a smaller diameter pipe, usually designated as the long-string casing, is run into the 

11 hole. Similar to the surface casing, the long-string casing is cemented in place to the borehole by 

12 circulating cement from the bottom back up to the surface casing, filling the gap between the 

13 outside of the long-string casing and the wellbore. This cementing process again ensures that 

14 rock formations are isolated and no fluid movement occurs between formations. 

15 

16 Depending on the depth to the injection formation, additional strings of casing may be necessary, 

17 but in each case, these casings are engineered and designed to withstand internal and external 

18 pressures at depth. The final result is multiple barriers of cement and casing between formations 

19 above the injection zone and the fluids being injected. Typically a portion of the wellbore in the 

20 injection zone is left open or the casing is perforated to allow injected fluid to enter into the 

21 injection zone. 

22 
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1 Inside the long string casing, injection tubing is run from the surface to a depth within the 

2 injection zone. This tubing may be engineered of steel, an alloy, fiberglass, or a composite 

3 material most suitable for the injectate’s composition. The tubing extends from the wellhead 

4 down to the storage zone where it is sealed by a mechanical device known as a packer. The area 

5 between the tubing and long string casing is isolated and the fluid injected into the well can only 

6 enter the geologic formation for which it is targeted. With this type of well construction, the 

7 fluid within the well tubing has minimal contact with the components of the well that protect 

8 USDWs. 

9 

10 The space between the injection tubing and the long string casing and above the packer is called 

11 the annulus. The annulus between the wellhead and the packer is a water-tight space filled with a 

12 non-corrosive fluid that helps to protect the inside of the casing and outside of the tubing from 

13 damage due to chemical reactions. In addition, monitoring the pressure of the annulus using 

14 standard pressure devices can easily detect any leaks in the tubing, long string casing, or packer. 

15 

16 Due to the buoyancy of CO2, today’s proposal includes enhancements to typical deep well 

17 construction procedures to provide additional barriers to CO2 leakage outside of the injection 

18 zone. The proposal would require that surface casing for GS wells be set through the base of the 

19 lowermost USDW and cemented to the surface. The long-string casing would be cemented in 

20 place along its entire length. GS wells would also be constructed with a packer that is set 

21 opposite a cemented interval, at a location approved by the Director. EPA seeks comment on the 

22 proposed GS well requirements for depth of surface casing, the cementing of long-string casing, 

23 and construction with a packer set opposite a cemented interval. 
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1 

2 More information on well drilling may be found by consulting various sources including the 

3 Department of Energy, the American Petroleum Institute (API), and the Society of Petroleum 

4 Engineers (SPE). Please consult information or links on EPA’s website: 

5 www.epa.gov/safewater/uic.html, or similar sources. 

6 

7 Horizontal Well Construction: While horizontal well construction is not typical in deep injection 

8 wells in the UIC program, there are examples of horizontal well completions being used with 

9 success to improve the production of EOR and ECBM operations (e.g., Westermark et al., 2004; 

10 Sams et al., 2005). EPA understands that the In Salah project in Algeria is using horizontal well 

11 construction for GS purposes (BP, personal communication). Horizontal wells are constructed 

12 by use of a directional drilling system, which generally consists of both a curve and lateral 

13 drilling assembly. After the vertical portion of the well is constructed, the curve drilling 

14 assembly is used to drill a curve of prescribed radius to change the path from vertical to 

15 horizontal. The lateral drilling assembly is then used to construct the horizontal section, which 

16 can be lined or remain as an open hole. Importantly, several horizontal sections can be 

17 completed stemming from a single vertical completion. 

18 

19 The use of horizontal wells for a GS project could provide several benefits over vertical wells. 

20 Horizontal wells provide enhanced connectivity with permeable sections of the formation, 

21 increasing injectivity. The use of horizontal wells increases the sweep, or formation contact 

22 area, of the injected CO2 plume, as vertical channeling through high permeability regions is 

23 reduced. Increasing the sweep results in enhanced residual-phase CO2 trapping and dissolution 
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1 favorable for the purposes of permanent storage. Horizontal wells also reduce the pressures 

2 needed to inject any given volume of fluid. In addition, fewer vertical completions are required 

3 with the use of horizontal wells, which reduces the number of artificial penetrations in the 

4 formation through which fluid could migrate, as well as reducing overall costs. 

5 

6 EPA seeks comment on the merits of horizontal well drilling techniques for GS wells and the 

7 applicability of well construction requirements discussed in this proposal. 

8 

9 Well component degradation: The potentially corrosive nature of the injectate must be taken into 

10 consideration in the design and construction of CO2 GS wells. The quality of the well materials, 

11 proper well construction, composition and placement of appropriate cement along the wellbore, 

12 and appropriate maintenance are crucial, because a leaking annulus would be a significant route 

13 of escape for CO2 (IPCC, 2005). 

14 

15 CO2 mixed with water or impurities (NOx, SOx and H2S) can be corrosive to well materials and 

16 cements. Conventional cement formulations (e.g., Portland cement) are potentially vulnerable to 

17 acid attack. Acid attack on the calcium carbonate in cement can lead to altered permeability and 

18 mechanical instability. Defects in the well cement, such as channels, cracks, and microannuli 

19 (i.e., small spaces between the casing and cement) can provide pathways for acid to migrate and 

20 accelerate degradation. 

21 

22 Experience with CO2 injection for EOR includes the use of acid-resistant cements. Cements 

23 with a reduced Portland content are more resistant to acid because they contain less calcium 
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1 carbonate (CaCO3). Acid resistant cements can be formulated by adding fly ash, silica fume 

2 (microsilica), latex, epoxy, or other substances. Calcium phosphate cement is a blend of high3 alumina cement, phosphate, and fly ash that can retain integrity under conditions where other 

4 cements lose a substantial portion of their weight, according to one manufacturer 

5 (www.eandpnet.com/area/exp/153.htm). 

6 

7 EPA examined available information to determine the rate at which cement degrades in acidic 

8 environments. Laboratory studies provide evidence of deterioration of cement and other well 

9 components due to exposure to acid. For example, Duguid et al. (2004) performed a laboratory 

10 study in which Portland cement experienced significant damage within seven days. Limited 

11 results of field studies, however, do not show such severe corrosion. Cement samples from a 

12 well at the Scurry Area Canyon Reef Operators Committee (SACROC) site that were exposed to 

13 CO2 for 30 years did not show serious degradation (Meyer, undated). In the CO2 Wellbore 

14 Integrity Study (Christopher and Crow, 2007) an autopsy is in progress on a CO2 injection well 

15 completed in 1976. After 22 years of injection, the tubing and packer were removed, and the 

16 tubing was found to be in good condition. Laboratory analysis of the cement is in progress. 

17 Although the field corrosion looks surprisingly low, these are only limited examples. Laboratory 

18 studies are conducted under aggressive chemical conditions in an attempt to mimic the 

19 cumulative effects of long-term exposure to CO2 – rich formation fluids. Given the high 

20 injection rates, long lifespan, and potential impurities in GS, careful selection of acid-resistant 

21 materials and practices may be necessary. 

22 
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1 Metal components of the injection well, such as carbon steel, are subject to corrosion. To 

2 minimize problems, Meyer (undated) recommends the use of Grade 316 stainless steel. One 

3 company working on GS projects indicates that they use stainless steel well casing to avoid 

4 corrosion problems. (Buller et al., 2004) Stainless steels consist of iron, small amounts of 

5 carbon, and at least 10 percent chromium. Grade 316 stainless steel also contains molybdenum, 

6 which endows it with corrosion resistance in a variety of corrosive media, although it is subject 

7 to corrosion in warm chloride environments and to stress corrosion cracking at warmer 

8 temperatures (above 60 degrees C). According to the report, recovered CO2 injection well 

9 components at the SACROC site in Texas were made of Grade 316 stainless steel and did not 

10 exhibit signs of corrosion. Industry representatives at the Technical Workshop on Well 

11 Construction and MIT noted that many casing options (e.g., titanium and fiberglass casing) are 

12 available. Useful packer products include swell-resistant elastomer materials such as Buna-N 

13 and Nitrile rubbers. (Meyer, undated) Teflon and nylon are options for anti-corrosion seals. 

14 

15 The use of corrosion-resistant materials is crucial to the success of long-term GS operations. 

16 UIC program experience, industry experience, and stakeholder input suggest that appropriate 

17 materials are available. Today’s proposal does not specify materials that may be used, rather, 

18 proposes providing the owner or operator with the flexibility to choose, as long as the materials 

19 used in GS wells are corrosion-resistant and meet or exceed standards developed for such 

20 materials by API or ASTM International, or comparable standards approved by the Director. 

21 Well materials must be compatible with injected fluids, including any co-injected impurities or 

22 additives, throughout the life of the project, and be appropriate for the well’s depth, the size of 

23 the well bore, and the lithology of injection and confining zones. 
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1 

2 GS projects are anticipated to have long lifespans in comparison to other types of deep injection 

3 wells. Not only must GS wells be able to function safely and properly over the lifespan of the 

4 GS project, but they must be constructed such that USDWs remain protected after well plugging. 

5 Today’s proposal would require that the cements and cement additives used in GS wells be 

6 appropriate to address long-term injection of CO2 and assure that the well can maintain integrity 

7 throughout the proposed life span of the project, including the post-injection site care period and 

8 beyond once the well is permanently plugged. Owners or operators must use corrosion-resistant 

9 cement approved by the Director and be able to verify the integrity of the cement using logs or 

10 other acceptable methods. 

11 

12 EPA seeks comment regarding requirements for degradation-resistant well construction 

13 materials, such as acid-resistant cements and corrosion resistant casing. 

14 

15 4. Proposed Injection Well Operating Requirements 

16 EPA’s operating requirements for deep injection wells provide multiple safeguards to ensure that 

17 injected fluids do not escape and are confined within the injection zone and that the integrity of 

18 the confining zone is not compromised by non sealing artificial penetrations or geologic features. 

19 In today’s proposal, some well operating requirements are consistent with existing UIC well 

20 types and some requirements are tailored specifically for CO2 injection. 

21 

22 Injection parameter limitations: Limitations on injection parameters are intended to prevent the 

23 movement of injected or other fluids to USDWs via fractures in confining layers or vertical 
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1 migration. In order to drive the injected fluids away from the well and into the formation, fluids 

2 must be injected at a higher pressure than the pressure of fluids in the injection zone. However, 

3 the sustained pressure should not be as high as fracture pressure, that is, high enough to initiate 

4 or propagate fractures in the injection or confining zone. If the pressure within the reservoir 

5 becomes high enough, induced stresses may reactivate existing faults (Rutqvist et al, 2007), 

6 though injection pressure limitations may be employed to prevent this. (Li et al, 2006) Several 

7 geomechanical methods are available to assess the stability of faults and estimate maximum 

8 sustainable pore fluid pressures for CO2 storage. For example, one way of deriving these is to 

9 calculate the effective stresses on faults and reservoir rocks based on fault orientations, pore fluid 

10 pressures, and in-situ stresses (Streit and Hillis, 2004). 

11 

12 Today’s proposal would require an injection pressure limitation similar to existing UIC Class I 

13 deep well requirements. Owners or operators of GS wells must limit CO2 injection pressures, 

14 except during well stimulation, so that injection does not initiate new fractures, propagate 

15 existing fractures in the injection zone, or cause movement of injection or formation fluids that 

16 endanger USDWs. Under this proposal, during injection, the pressure in the injection zone must 

17 not exceed 90 percent of the fracture pressure of the injection zone. Calculation of fracture 

18 pressure is fundamental to evaluating the appropriateness of the site. The 90 percent 

19 requirement, suggested by permit writers and IOGCC, provides an added margin of safety in the 

20 well operation. 

21 

22 There are some circumstances, however, where fracturing of the injection zone would be 

23 acceptable provided the integrity of the confining system remains unaffected. For example, 
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1 hydraulic fracturing is a process where a fluid is injected under high pressure that exceeds the 

2 rock strength, and the fluid opens or enlarges fractures in the rock. EPA recognizes that there 

3 may be well completions which require intermittent treatments, including hydraulic fracturing of 

4 the injection zone, to improve wellbore injectivity. Such stimulation of the injection zone during 

5 a well workover (as defined in 144.86(d)) approved by the Director would be permissible. 

6 

7 Fracturing of the confining zone would be prohibited at all times, during injection and/or 

8 stimulation. 

9 

10 It is also possible that CO2 GS may be associated with ECBM, where more extensive hydraulic 

11 fracturing would be necessary to open pre-existing fractures in the coal and provide additional 

12 surfaces onto which CO2 may adsorb and to extract methane. These hydraulic fracturing 

13 operations are used to enhance oil and gas recovery and for ECBM recovery, and in general are 

14 exceptions to the definition of underground injection under the SDWA. 

15 

16 EPA is requesting comment on the extent and scope to which hydraulic fracturing should be 

17 allowed during GS injection, and whether the use of fracturing for the purposes of well 

18 stimulation is appropriate. EPA is also requesting information to better qualify the use of 

19 fracturing for GS injection in specific geologic settings and rock formation lithologies. 

20 

21 Continuous monitoring: Monitoring within the injection well system is important to assure that 

22 the injection project is operating within permitted limits. It can also protect the owner or 

23 operator’s investment, as significant divergences in any of these parameters could damage well 
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1 components. Deep injection well owners or operators typically monitor injection pressure, flow 

2 rate, temperature, and volumes. Owners or operators usually choose to maintain pressure on the 

3 annulus between the tubing and the long string casing and monitor this pressure to ensure 

4 protection of USDWs from well leakage. Monitoring is generally performed on a continuous 

5 basis, through the use of automated equipment that typically takes readings several times per 

6 minute and records them in a computer system. 

7 

8 Alarms and automatic shut-off devices connected to the monitoring equipment can engage if 

9 operational limits are exceeded. Available computer-driven monitoring systems have the ability 

10 to continuously monitor injection parameters and engage the shut-off devices. Though these 

11 systems are not required for all UIC well classes, the complexity of GS operations and the 

12 potential for movement of the CO2 in the event of a mechanical integrity loss makes a shut-off 

13 system an important safety consideration for GS projects. 

14 

15 Traditionally, owners or operators have installed monitoring and shut-off equipment at the 

16 wellhead (i.e., at the surface), however, down-hole devices have been used in offshore 

17 applications for several years. Today’s proposal requires that automatic shut-off valves be 

18 installed down-hole in addition to at the surface. This requirement is supported by many 

19 participants at the technical workshops and the IOGCC’s recommendations. 

20 

21 The down-hole valves provide a safety backstop in case damage to the wellhead prevents the 

22 proper operation of wellhead shut-off valves. Direct pressure measurements used to trigger shut23 off devices are more accurate than wellhead calculations of down-hole pressure. The down-hole 
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1 valves are an integral part of the tubing string and can be positioned anywhere along the tubing 

2 string. Gauges can be either inside or outside of the casing; installation on the outside of the 

3 casing may cause less interference with well maintenance. The down-hole valves are kept in an 

4 open position by hydraulic pressure from a connection to the surface. Damage to the wellhead or 

5 an upset in operations causes the positive hydraulic pressure to fall, forcing the valve into a 

6 ‘failsafe’ closed position. In case of well failure, a down-hole shut-off device would isolate the 

7 injectate below USDWs, rather than just below the surface. By engaging near the injection zone, 

8 they can prevent pressure-induced damage to the well casing. This would also require less 

9 expensive repairs if pressure exceedances were to occur. 

10 

11 While there would be some cost and downtime associated with replacing failed down-hole 

12 valves, such costs are considered small in comparison to the costs if large amounts of CO2

13 should escape into USDWs or to the surface. It is possible to place a new valve down-hole 

14 without removing the existing valve, so downtime can be minimized if an appropriate parts 

15 inventory is kept on hand. A Norwegian study found that the failure rate of down-hole safety 

16 valves was 2 failures per million operating hours. (Norwegian Oil Industry Association, 2001) 

17 This is a relatively low failure rate as the valves are designed to withstand harsh conditions and 

18 operate well after years of inactivity. Overall, it is likely that costs for replacing failed valves 

19 would be insignificant in comparison with costs of a CO2 leak. 

20 

21 Several types of valves are available and in use, including flappers and ball valves. The flapper 

22 types seem to be more reliable, at least for oilfield applications. (Garner et al., 2002) EPA seeks 

23 comment on the merits of requiring down-hole shut-off valves in GS wells. 
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1 

2 Corrosion Monitoring and Control: Existing UIC Class I deep well operating requirements 

3 allow Director’s discretion to require corrosion monitoring and control in the case of corrosive 

4 fluids. Corrosion monitoring can help avoid or provide early warning of corrosion of well 

5 materials that could compromise the well’s integrity. This is accomplished by exposing 

6 “coupons,” or small samples of the well material to the injection stream. The samples are 

7 periodically removed from the flow line, cleaned and weighed; the weight is compared to 

8 previous values to calculate a corrosion rate. Other methods of corrosion monitoring/control 

9 include: the use of wireline enhanced caliper or imaging logs to inspect the casing, the use of 

10 ultrasonic and electromagnetic techniques in well pipes (Brondel et al., 1994), the use of 

11 cathodic protection (where the casing would become the cathode of an electrochemical cell) or 

12 the use of fluid with biocide/corrosion inhibitor fluid in the annular space between the casing and 

13 tubing. 

14 

15 CO2 reacts with water to become acidic, potentially accelerating corrosion of well materials. The 

16 CO2 stream for a GS project may also contain small volumes of impurities that could be 

17 corrosive. Thus, EPA is proposing to require corrosion monitoring for GS wells. Corrosion 

18 monitoring is further discussed in the monitoring and testing section of this preamble. 

19 

20 Injection Depth in Relation to USDWs: Today’s proposal specifies a requirement that such 

21 injection should be allowed only beneath the lowermost formation containing a USDW. This is 

22 consistent with the siting and operational requirements for all Class I hazardous injection wells, 

23 and a very important protective component of the UIC program. Placing distance between the 
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1 point of injection and USDWs allows for the necessary confining and buffer formations, and 

2 further provides for opportunity for additional monitoring to detect any excursions from the 

3 intended injection zone. 

4 

5 However, EPA is not prescribing a minimum injection depth to keep the CO2 in a supercritical, 

6 liquid state after it is injected, as some well operators may choose to inject the CO2 as a gas. If 

7 the trapping mechanism is sufficiently protective, the injected CO2 should be contained 

8 regardless of its phase. 

9 

10 Some stakeholders and co-regulators have proposed other approaches for specifying an injection 

11 depth and these merit consideration by EPA. For example, one approach would be to require a 

12 minimum injection depth of approximately 800 m (2625 feet) for GS of CO2. The geothermal 

13 gradient and weight of the fluid and rock layers above this target depth would maintain CO2 at a 

14 sufficiently high pressure to keep it in a supercritical, liquid state. Storing CO2 at supercritical 

15 pressure would allow storage of greater volumes and thereby increase available underground 

16 storage capacity. Additionally, storing CO2 in a supercritical, liquid state may prevent the 

17 frequency of well mechanical integrity failure. When supercritical CO2 is injected into shallow 

18 formations where pressures are not high enough to maintain its supercritical state, it will revert to 

19 a gas. The expansion of gaseous CO2 will cause a drop in temperature (the Joule-Thomson 

20 effect), and if this temperature drop is large enough, freezing and thermal shock may take place 

21 in the vicinity of the well. Thermal shock is a common cause of cracking in many types of 

22 pressure equipment, and repeated exposure to such stresses could compromise the integrity of the 

23 injection well’s tubular components. Participants at the Technical Workshop on Well 
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1 Construction and MIT suggested that these phase changes (i.e., supercritical liquid to gas) are 

2 potentially a greater mechanical integrity concern than corrosivity. Modeling by Oldenburg 

3 (2007) shows that if the pressure drop is not large (less than 10 bars), this effect will not be great 

4 enough to cause significant problems. However, technical workshop participants concluded that 

5 more research is needed on the effects of phase changes on well mechanical integrity. 

6 

7 EPA is aware that the proposed requirement of injecting CO2 below the lowermost USDW may 

8 preclude injection into certain targeted geologic formations, which may be storage sites currently 

9 under consideration for GS. These formations may include unmineable coal seams (those not 

10 being used for Class II enhanced coal bed methane production), zones in between or above 

11 USDWs, and other formations also under consideration. In areas of the country with very deep 

12 USDWs, the need to construct GS wells beneath them may render GS technically impractical. 

13 As a result, the Agency is considering and requesting comment on alternative approaches that 

14 would allow injection between and/or above the lowermost USDW, and thus potentially allow 

15 for more areas to be available for GS while preventing USDW endangerment. 

16 

17 One alternative under consideration is a provision for Director’s discretion to allow injection 

18 above or between USDWs in specific geologic settings where the depth of the USDWs may 

19 preclude GS, make GS technically challenging, or significantly limit CO2 storage capacity. Such 

20 approval by the Director would allow injection between USDWs (and thereby allowing injection 

21 above the lowermost USDW) in circumstances in which it may be demonstrated that USDWs 

22 would not be endangered. An example where such injection may be appropriate, presents itself 

23 in areas such as the Williston and Powder River Basins in Wyoming, North Dakota, and South 
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1 Dakota, where receiving formations (formations with large CO2 storage capacity) for GS have 

2 been identified above the lowermost USDW and where there may be thousands of feet of rock 

3 strata between the injection zone and the overlying and underlying USDWs. In these cases, 

4 injection above or between USDWs may be appropriate, however, the Agency currently lacks 

5 data to demonstrate that such practices are or are not protective of USDWs. 

6 

7 Also, EPA is considering allowing Directors to exempt all USDWs below the injection zone. 

8 Currently, Directors may issue “aquifer exemptions” which when approved, essentially 

9 determines that an aquifer is no longer afforded protection as a USDW, in accordance with the 

10 requirements of 40 CFR 144.7(b)(1). Aquifer exemptions are permitted for mineral or 

11 hydrocarbon exploitation by Class III solution mining wells, or by Class II oil and gas-related 

12 wells, respectively, and when there is no reasonable expectation that the exempted aquifer will 

13 be used as a drinking water supply (please see specific aquifer exemption criteria at 40 CFR 

14 146.4). When EPA exempts an aquifer, it is no longer considered a USDW now or in the future. 

15 EPA limits aquifer exemptions for injection operations in the circumstances where the necessary 

16 criteria at 40 CFR 146.4 are met and not, in general, for the purpose of creating additional 

17 capacity for the emplacement of fluids. 

18 

19 EPA carefully considers all aspects of ensuring the protection of USDWs before approving an 

20 aquifer exemption request for any injection purpose in UIC programs which it implements. The 

21 Agency’s interpretation of the SDWA, and its own UIC regulations, currently allows for aquifer 

22 exemptions sought for specific reasons (as outlined above) and not solely for the purpose to relax 

23 well owner/operator requirements, such as operating, monitoring, or testing. Therefore, in 
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1 general, the Agency does not consider aquifer exemption requests for non-injection formations. 

2 It has also been EPA’s long-standing policy not to grant aquifer exemptions for the purpose of 

3 hazardous waste disposal because of the infeasibility of meeting Class I hazardous waste siting 

4 requirements (i.e., injection must be below the lowermost USDW). 

5 

6 However, aquifer exemptions could be issued for GS wells where receiving formations are 

7 situated above the lowermost USDW and where there are thousands of feet between the injection 

8 zone and the overlying and underlying USDWs. In these circumstances, the permit applicant 

9 would be required to meet all Class VI permit requirements. 

10 

11 It is also anticipated that some aquifers previously exempted for Class II injection operations 

12 may be appropriate formations for GS and permit applicants may seek to use these formations. 

13 In such circumstances, the permit applicant for a GS Class VI well would be required to seek a 

14 new aquifer exemption for the purpose of GS, and provide a non-endangerment demonstration 

15 that reflects the predicted extent of the CO2 plume, the associated pressure front, and the scope of 

16 the injection activities. 

17 

18 Furthermore, there may be other geologic settings with formations that could receive and store 

19 CO2 that are not below the lowermost USDW. Such formations include deep, marginal USDWs 

20 directly overlying crystalline basement rock and/or unmineable coal seams. Under today’s 

21 proposal, these formations would not qualify for GS without aquifer exemptions. In these areas 

22 where USDWs directly overlie crystalline basement rock, permit applicants may seek aquifer 

23 exemptions and permits to inject CO2 for GS into these exempted aquifers. In unmineable coal 
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1 seams that are USDWs or contain or are bounded by formations that are USDWs, permit 

2 applicants may also seek aquifer exemptions and permits for GS. 

3 

4 In summary, EPA is soliciting comment on whether CO2 injection should be allowed into an 

5 injection zone above the lowermost USDW, when the Director determines that geologic 

6 conditions (e.g., thousands of feet of intervening formations between the injection zone and the 

7 overlying and/or underlying USDWs) exist that will prevent fluid movement into adjacent 

8 USDWs. EPA is also requesting comments on whether aquifer exemptions should be allowed 

9 for the purpose of Class VI injection, and under what conditions should such aquifer exemptions 

10 be approved. Finally, EPA seeks comment on whether the Agency should set a minimum 

11 injection depth requirement for CO2 GS, rather than require that such injection take place below 

12 the lowermost USDW. 

13 

14 Tracers: While the UIC Program’s protective elements greatly reduce the potential for leakage, 

15 leakage is a possibility in any underground injection project. Tracers may help facilitate leak 

16 detection. Though use of tracers is not required under existing deep well requirements, the 

17 buoyancy of CO2 and the large volumes that are expected to be injected may warrant improved 

18 leak detection for GS wells. Detection of leakage of injected CO2 at the surface would indicate 

19 potential endangerment to USDWs. Additionally, if tracers are used for CO2 GS projects, they 

20 may also help owners or operators to infer geochemical processes caused by CO2 (e.g., 

21 dissolution or precipitation of calcium carbonate) that may pose risks. 

22 
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1 Gaseous CO2 is odorless and invisible. Tracers can be odorants, such as those added to domestic 

2 natural gas, in order to serve as a warning of a natural gas leak. Mercaptans are the most 

3 effective odorants, however, they are not generally suitable for GS because they are degraded by 

4 oxygen, even at very low concentrations. The experience from the natural gas storage industry is 

5 that they are scrubbed from the gas by adsorption to the formation in the subsurface. 

6 Disulphides, thioethers and ring compounds containing sulfur are options for CO2 GS odorants. 

7 (IPCC, 2005 p. 190) However, there has been no testing of these substances for GS, and it is 

8 unknown whether using them for GS would be effective. 

9 

10 Participants at the technical workshop on monitoring, measurement, and verification (MMV) 

11 discussed the use of tracers in monitoring. Measurement of stable isotopes of carbon (i.e., 

12 C12/C13 ratio) can serve as tracers and may be useful for identifying the source of CO2 (e.g., 

13 anthropogenic or biological). Panelists also addressed the potential utility of perfluorocarbon 

14 (PFC) and other inert tracers in detecting CO2 leakage. According to some researchers, PFCs are 

15 conservative and will remain with the CO2. Unique suites (or batches) of PFCs can be created 

16 using different combinations of PFCs. Different PFC suites can be used to establish unique 

17 signatures for different time periods of prolonged injection or for multiple CO2 injections, 

18 making it feasible to detect if a leak is transient versus long-term in nature. 

19 

20 There may be potential benefits of tracers for CO2 GS operations, though tracers’ effectiveness 

21 and cost-effectiveness are debated. There are also technical challenges, such as false positives, 

22 associated with their use that will vary on a case-by-case basis. In addition, in the case of PFCs, 

23 which have a global warming potential many orders of magnitude higher than CO2, there may be 
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1 concerns about the consequences of potential releases to the atmosphere. Today’s proposal 

2 allows Directors’ discretion on whether to require the use of tracers, and if so, what types of 

3 tracers. EPA seeks comment on the use of tracers in CO2 GS operations. 

4 

5 5. Proposed Mechanical Integrity Testing Requirements

6 Injection well mechanical integrity testing (MIT) is a critical component of the UIC Program’s 

7 goal to protect USDWs. Testing and monitoring the integrity of an injection well, at the 

8 appropriate frequency, can verify that the injection activity is operating as intended and does not 

9 endanger USDWs. MIT requirements for GS wells should be tailored to address the unique 

10 properties of CO2, specifically its buoyancy and potential corrosivity, so that owners or operators 

11 of GS projects will be able to detect defects within the well, and between the well and the 

12 borehole, before these defects could allow GS-related fluids to move into unintended formations 

13 or toward USDWs. 

14 

15 Currently, all UIC injection well owners or operators must demonstrate that their wells have both 

16 internal and external mechanical integrity (MI). (40 CFR 146.8) An injection well has internal 

17 MI if there is an absence of leakage in the injection tubing, casing, or packer. Typically, internal 

18 mechanical testing is accomplished with a periodic pressure test of the annular space between the 

19 injection tubing and long string casing of this annual space. Usually, loss of internal MI is due to 

20 corrosion or mechanical failure of the injection well’s components. Rarely, because of the 

21 multiple-barrier nature of injection well construction, do internal MI losses result in leakage 

22 outside of the well and present an endangerment to a USDW. 

23 
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1 Injection well external integrity is demonstrated by establishing the absence of fluid flow along 

2 the outside of the casing, generally between the cement and the well structure, although such 

3 flow may also occur between the cement and the well bore itself. This is typically accomplished 

4 through the use of down-hole geophysical logs or surveys designed to detect such leaks once 

5 every five years. Failure of an external MIT can indicate improper cementing or degradation of 

6 the cement that was emplaced to fill and seal the annular space between the outside of the casing 

7 and the well borehole. This type of failure can lead to movement of injected fluids out of 

8 intended injection zones and toward USDWs. As with internal MI failure, temporary loss of 

9 external MI rarely results in endangerment to USDWs. 

10 

11 Failure of either external or internal mechanical integrity may mean that one of the multiple 

12 protective layers in an injection well is not operating as intended. Proper testing can serve as an 

13 early warning to owners or operators that the well is not performing optimally and that 

14 maintenance or repair of a component of the well is needed before the injectate moves to 

15 unintended zones or a USDW is impacted. 

16 

17 The decades of State and EPA experience with Class I and Class II mechanical integrity testing 

18 requirements provides the best knowledge base for identifying appropriate MIT requirements for 

19 GS projects. This is supported by findings from technical workshops, conferences, and research. 

20 However, because of the buoyant and corrosive properties of a GS stream, current deep well 

21 internal and external MIT requirements will need to be tailored in order to ensure the protection 

22 of USDW. 

23 
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1 As previously discussed, internal MI testing is designed to evaluate the condition of internal well 

2 component. The evaluation is typically accomplished with an annual pressure test. However, 

3 due to the nature of GS injection stream, corrosivity must be considered when planning for MITs 

4 in GS projects. Studies conducted by EPA of previous MIT results suggest that wells injecting 

5 corrosive fluids fail MIT at rates 2 to 3 times higher than those that inject non-corrosive fluids. 

6 Thus a more corrosive injectate is a potential risk factor for MIT failure. 

7 

8 Therefore, today’s proposal would require owners or operators of Class VI GS projects to 

9 monitor internal mechanical integrity of their injection wells by continuously monitoring 

10 injection pressure, flow rate, and injected volumes, as well as the annular pressure and fluid 

11 volume to assure that no anomalies occur that may indicate an internal leak. 

12 

13 Continuous internal mechanical integrity monitoring of GS project injection wells, instead of 

14 periodic testing (which is required for most other types of deep injection wells) is important 

15 because the corrosive nature of GS waste streams makes immediate identification of corrosion16 related well integrity loss critical. Today’s proposal would also require automatic down-hole 

17 shut-off mechanisms (see well construction and operation) in the event of an MI loss. 

18 Continuous computer-driven monitoring of internal MI would need to be performed in order for 

19 automatic shut-off systems to be activated. This combination of computer-driven continuous 

20 internal monitoring linked to an automatic down-hole injection shut-off provides the maximum 

21 protection to USDWs and the earliest warning to owners or operators that repairs need to be 

22 performed. 

23 
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1 This proposed requirement would eliminate the necessity of conducting other periodic internal 

2 MITs. However, today’s proposal would provide the Director with the discretion to request any 

3 other additional tests necessary to ensure the protection of USDWs. 

4 

5 As mentioned above, external mechanical integrity testing is used to determine the absence of 

6 fluid leaks behind the long string casing. Instead of requiring external MI to be demonstrated 

7 every five years (which is typical for other types of deep injection wells), today’s proposal would 

8 require owners or operators of CO2 wells to demonstrate injection well external mechanical 

9 integrity at least once annually. This increase in testing frequency (from once ever five years to 

10 once a year) is justifiable for the protection of USDWs given the potential corrosive effects on 

11 injection well components (steel casing and cement) that are exposed to the GS stream and the 

12 buoyant nature of the injected fluid that tends to force it upward toward USDWs. 

13 

14 Today’s proposal does not change the existing allowable methods for demonstrating external MI 

15 in deep injection wells. They would include the use of a tracer survey, a temperature or noise 

16 log, a casing inspection log if required by the Director, or an alternative approved by the 

17 Administrator and, subsequently, the Director. Today’s proposal would also provide the 

18 Director with the discretion to request additional tests. 

19 

20 EPA proposes that owners or operators report semi-annually on the injection pressure, flow rate, 

21 temperature, volume and annular pressure, and on the results of MITs. This reporting frequency, 

22 which is the same as for other deep injection well classes, has proven to be timely for notification 

23 to permitting authorities on the status of the operation. 
Deliberative draft – do not cite or distribute Page 98 

1 

2 Additionally, EPA seeks comment on the appropriate frequency of internal and external MITs 

3 for GS injection wells, the appropriate types of MITs and how to optimize MIT methods for GS. 

4 

5 6. Proposed Plume and Pressure Front Monitoring Requirements 

6 Monitoring associated with UIC injection wells is required to ensure that the injectate is safely 

7 confined in the intended subsurface geologic formations and USDWs are not endangered. 

8 Certain existing UIC program monitoring requirements apply to all wells, while others are based 

9 on site-specific information and Director’s discretion. Information obtained through monitoring 

10 may be used to maintain the efficiency of the storage operation, minimize costs, and confirm that 

11 injection zone pressure decline follows predictions. Monitoring results of GS wells would also 

12 be used as data inputs for reevaluation of the site computational model and AoR and corrective 

13 action. 

14 

15 EPA considers CO2 plume and associated pressure front monitoring to be necessary for 

16 verification of model predictions. An integrated monitoring and modeling strategy should be 

17 used to track the evolution of the CO2 plume and associated pressure front. Monitoring may be 

18 conducted with a combination of direct and indirect techniques appropriate for the conditions of 

19 specific GS projects. Monitoring is necessary to verify initial model predictions given the 

20 uncertainty of CO2 fate and transport; because large volumes of CO2 will be injected during GS 

21 operations; and because of the challenges of comprehensive site characterization in large 

22 formations that may be used for GS projects. Monitoring results should be used to assess CO2

23 movement through high-permeability regions (i.e., faults, fractures) not detected in site 
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1 characterization and included in initial site modeling. Early pilot-projects have indicated that the 

2 most complete understanding of the site-specific behavior of CO2 will result from monitoring the 

3 movement of CO2 itself (e.g., Doughty et al., 2007). 

4 

5 EPA seeks comment on the requirement for monitoring of GS sites for the purpose of tracking 

6 the location of the CO2 plume and associated pressure front over time. 

7 

8 

9 Testing and Monitoring Plan: A monitoring program for a GS project should be designed to 

10 detect changes in ground water quality and track the extent of the CO2 plume and area of 

11 elevated pressure. Today, EPA is proposing that owners or operators of Class VI wells would 

12 submit, with their permit application, a testing and monitoring plan to verify that the GS project 

13 is operating as intended and is not endangering USDWs. This plan would be implemented upon 

14 Director approval and would include, at a minimum, analysis of the chemical physical 

15 characteristics of the CO2 stream; monitoring of injection pressure, rate, and volume; annular 

16 pressure and fluid volume; corrosion monitoring; a demonstration of external mechanical 

17 integrity (see mechanical integrity section of the preamble); the position of the CO2 plume and 

18 area of elevated pressure; monitoring of geochemical changes in the subsurface; and, at the 

19 discretion of the Director, monitoring for CO2 fluxes in surface air and soil gas, and any 

20 additional tests requested by the Director. 

21 

22 Monitoring within multiple layers (i.e., in the primary confining system; in USDWs and other 

23 shallow layers; and, at the surface) supports a multi-barrier approach to protecting USDWs. 

24 Surface air and/or soil gas monitoring may be used as the last line of monitoring to ensure that 
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1 there has not been vertical CO2 leakage, which could endanger USDWs. The program should 

2 also be site-specific, based on the identification and assessment of potential CO2 leakage routes 

3 complemented by computational modeling of the site. 

4 

5 Under today’s proposal, owners or operators would be required to analyze the CO2 stream at a 

6 frequency sufficient to yield data representative of its chemical and physical characteristics. This 

7 analysis will provide information on the content and corrosivity of the injected stream, which in 

8 turn will support improvements in well construction and optimization of well operating 

9 parameters. EPA also proposes that owners or operators would monitor well materials for signs 

10 of corrosion, such as loss of mass, thickness, cracking, or pitting. The proposed requirements are 

11 critical to address the potential well integrity concerns associated with the corrosive nature of the 

12 CO2 stream, to avoid (or provide early warning of) corrosion of well materials, and to protect the 

13 integrity of GS wells. Today’s proposal would also require continuous monitoring of the 

14 injection pressure, rate and volume as well as annular pressure and fluid volume discussed in the 

15 well construction and operation section of the preamble. 

16 

17 Monitoring CO2 movement and reservoir pressure: Monitoring subsurface geochemistry and the 

18 position of the CO2 plume and pressure front are necessary to verify predictions of plume 

19 movement, provide inputs for modeling, identify needed corrective actions, and target 

20 geochemical and surface monitoring activities. 

21 

22 Under today’s proposal, owners or operators would be required to track the subsurface extent of 

23 the CO2 plume and pressure front using pressure gauges in the first formation overlying the 
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1 confining zone or using indirect geophysical techniques (e.g., seismic, electrical, gravity, or 

2 electromagnetic surveys) or other down-hole CO2 detection tools, monitor for geochemical 

3 changes in subsurface formations, and if directed, monitor at the surface. Today’s proposal 

4 would also require owners or operators to monitor ground water quality and geochemical 

5 changes above the confining system. The results of this monitoring would be compared to 

6 baseline geochemical data to identify changes that may indicate unacceptable movement of CO2

7 or formation fluids. 

8 

9 In order to provide guidance related to monitoring of GS sites, EPA invited expert advice and 

10 reviewed technical documentation. EPA held a technical workshop on measurement, 

11 monitoring, and verification focused on the availability and utility of various subsurface and 

12 near-surface monitoring techniques that may be applicable to GS projects. This workshop, co13 sponsored by the Ground Water Protection Council (GWPC), took place in New Orleans, LA on 

14 January 16, 2008. 

15 

16 Monitoring within the confining zone for pressure, pH, salinity, or the presence of dissolved 

17 minerals, heavy metals, or organic contaminants requires direct access to the subsurface via 

18 monitoring wells. Wells installed for this purpose would be strategically placed in areas 

19 predicted to overlie the eventual CO2 plume and area of elevated pressure. Well number and 

20 placement would be based on project specific information such as injection rate and volume, site 

21 specific geology, baseline geochemical data, and the presence of artificial penetrations. 

22 Predictive models of the extent and direction of plume movement can support decisions about 

23 monitoring well placement. This has the dual benefit of targeting resources associated with what 
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1 is an expensive monitoring activity and reducing the number of artificial penetrations near the 

2 injection well, which could potentially become conduits for fluid movement into USDWs. 

3 

4 Today’s proposal would require that owners or operators perform a pressure fall-off test at least 

5 once every five years. Pressure fall-off tests are designed to ensure that reservoir injection 

6 pressures are tracking to predicted pressures and modeling input. They may be used in project 

7 siting and AoR calculations. Results of pressure fall-off tests may indicate mischaracterization 

8 of the site specific geology and potentially unidentified leakage pathways. 

9 

10 Pressure monitoring, both at the surface and in the formation, is a routine part of CO2 injection 

11 projects that serves several purposes. For instance, monitoring pressure in injection wells allows 

12 for use of shut-off valves in the case that injection pressure exceeds the formation fracture 

13 pressure, or pressure drop-offs indicate a subsurface leak (IPCC, 2005). Pressure monitoring in 

14 monitoring wells provides an indication of whether there is potential for brine intrusion into 

15 USDWs and CO2 leakage. When combined with information on temperature, pressure data 

16 provide an indication of the phase (e.g., gas, supercritical) and amount of the injected CO2. 

17 

18 Various pressure sensors are available, and monitoring can be conducted continuously. 

19 Conventional sensor types include piezo-electric transducers, strain gauges, diaphragms, and 

20 capacitance gauges (Burton et al., 2007). Fiber optic pressure and temperature sensors are also 

21 now commercially available and can be installed down-hole and connected to the surface 

22 through fiber optic cables. According to the CEC (2007), current monitoring technologies are 

23 more than adequate for monitoring pressure in a geologic sequestration project. 
Deliberative draft – do not cite or distribute Page 103 

1 

2 Direct geochemical monitoring is an important part of a monitoring program. Temperature, 

3 salinity, and pH should be monitored, as these parameters provide basic information for 

4 understanding water and gas geochemistry. Additionally, obtaining ground water samples via 

5 monitoring wells allows direct measurement of aqueous and pure-phase CO2. By studying the 

6 interactions between brine and CO2, it can be determined whether precipitation and/or 

7 dissolution of minerals is occurring (Nicot and Hovorka, 2008). These analyses will also 

8 indicate the rate of CO2 trapping mechanisms, and whether mineral dissolution may be causing 

9 permeability changes in the formation or impacting USDWs. Geochemical monitoring may also 

10 be conducted for heavy metals and organic contaminants that may potentially be mobilized in the 

11 formation due to injection. 

12 

13 Information and discussions from EPA technical and public workshops indicate that the 

14 collection of adequate baseline (pre-injection) data is critical for planning monitoring and for 

15 detecting CO2 movement and leakage during and after injection. 

16 

17 While the use of tracers is not a specific monitoring requirement in today’s proposal (per 

18 III.A.5), some Director’s may require owners or operators to use them. EPA has considered the 

19 merits of tracers for CO2 monitoring and recognizes that they may also be voluntarily employed 

20 by owners or operators. Tracers can also be measured through direct geochemical sampling to 

21 indicate the speed and direction of movement of CO2 after injection. Naturally occurring tracers 

22 include stable isotopes (atoms of a particular element with different numbers of neutrons) of 

23 carbon and oxygen. Analyses of the amounts of carbon-13 and oxygen-18 isotopes in water are 
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1 commonly used to track movement through the environment and to elucidate geochemical 

2 processes. It is also possible to include tracers, such as perfluorocarbons or noble gases, with the 

3 injected CO2 (Nimz and Hudson, 2005). Loss of tracers between the injection well and 

4 monitoring well may indicate diffusion into low-permeability materials, sorption, partitioning 

5 into non-aqueous phase liquids, partitioning into trapped gas phases, or leakage of CO2 (Nicot 

6 and Hovorka, 2008). Tracers were more fully discussed in well construction and operation 

7 section of the preamble. 

8 

9 There are several technical challenges associated with in-situ monitoring of formation fluids via 

10 wells. In the course of sample retrieval, there will be pressure changes, causing changes in CO2

11 solubility and pH. To address this, LBNL developed a “U-tube” sampling apparatus to enable 

12 collection of fluid and gas samples at in-situ pressure conditions. Also, samples collected from 

13 monitoring wells are point measurements that may not fully represent the entire reservoir, 

14 especially if there are extensive physical heterogeneities. 

15 

16 Geophysical methods for plume tracking: Various non-invasive deep subsurface monitoring 

17 techniques are available to track the movement of the CO2 plume. Many of these methods have 

18 been developed for use in the oil and gas industry, and some may also support certain aspects of 

19 baseline geologic characterization. Seismic and electrical techniques have been used to gather 

20 data related to rock composition, porosity, fluid content, and in-situ stress state. 

21 

22 In seismic surveying, a controlled source of seismic energy is used to send vibrations through the 

23 ground. The time it takes for the seismic waves to reflect off of a subsurface feature and reach a 
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1 receiver at the surface provides information about the depth of the feature. By using an array of 

2 receivers, possible plume and leakage flowpaths may be discerned. Seismic surveys may also be 

3 useful for monitoring how rock properties change with time during injection and for mapping of 

4 the CO2 plume. This method has been used to study the subsurface in the area near the injection 

5 well for the CO2-SINK project in Germany (Juhlin et al., undated) and at the Sleipner and In 

6 Salah sites. Seismic studies can also be done in a crosswell arrangement by placing an array of 

7 receivers in one borehole and drawing a seismic source upwards in another borehole, firing at 

8 periodic intervals. Current crosswell experience relevant to CO2 sequestration includes 

9 successful imaging of CO2 saturation and pressure effects in a carbonate reservoir in West Texas 

10 (Harris and Langan, 2001). Vertical seismic profiling (VSP), in which typically geophones are 

11 placed in a vertical array inside a borehole and sound sources originate the surface, is another 

12 promising technology for plume detection and monitoring. 

13 

14 Electrical methods rely on the electrical properties of the medium being studied and offer 

15 promise for CO2 plume monitoring. Electromagnetic (EM) surveys induce a current in 

16 subsurface materials, and conductivity meters detect areas with increased conductivity. Near the 

17 surface, EM can detect buried metal objects and contaminated soils. In the deeper subsurface, 

18 EM surveys can be used to detect certain contaminant plumes. EM can also be done in crosswell 

19 fashion. At Lawrence Livermore National Laboratory, researchers are conducting a long-term 

20 study using time-lapse multiple frequency EM characterization to image CO2 injected as part of 

21 an EOR operation. (Kirkendall and Roberts, undated) 

22 
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1 Electrical resistance tomography (ERT) measures electrical resistance by means of electrodes 

2 that may be placed at the surface, but are more commonly arrayed down boreholes in a crosswell 

3 configuration. Because the electrical properties of a medium are sensitive to fluid chemistry, 

4 ERT can be used for monitoring fluid migration in the subsurface. The oil industry has used 

5 ERT, and it has been also used for environmental applications such as detection of contaminant 

6 plumes at waste sites. Newmark (2003) reported preliminary data on the use of crosswell ERT at 

7 an EOR site to monitor for CO2.

8 

9 Microgravity surveys detect density variations in the subsurface using sensitive gravity 

10 measurements made at the ground surface. Microgravity surveys have been used to characterize 

11 subsurface formations, and given the density differences between CO2 and formation brines, may 

12 be useful for tracking a CO2 plume. Nooner et al. (2003) discuss use of microgravity surveys at 

13 the Sleipner CO2 GS project in Norway. 

14 

15 The GEO-SEQ Best Practices Manual (2004) discusses the capabilities of seismic and electrical 

16 crosswell methods for CO2 GS. The authors note the high spatial resolution of these methods 

17 and state that they can image leaks and fluid saturation within a reservoir. Simulations discussed 

18 in the manual confirm that seismic and electrical conductivity crosswell methods could provide 

19 information on the saturation of CO2 within the reservoir between wells. The authors note that 

20 seismic crosswell methods could also be used to detect CO2 phase changes. Although these 

21 methods are costly and time consuming, they may prove useful at GS sites in the future. To fully 

22 implement these technologies, additional research is needed regarding the electrical and seismic 

23 properties of subsurface media containing CO2. 
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1 

2 Some stakeholders expressed concerns about the usefulness of seismic surveys as a CO2 tracking 

3 tool under certain geologic conditions, particularly given the cost of specific technologies. EPA 

4 believes that tracking the plume and pressure front is an important companion step to address 

5 any uncertainties associated with initial AoR modeling. 

6 

7 As such, allowing flexibility in choosing the plume tracking methods and other monitoring 

8 technologies provides an appropriate balance between the protective nature of indirect 

9 monitoring and cost considerations, as well as allowing for the adoption of continuously 

10 advancing technology. 

11 

12 Surface air and soil gas monitoring: Surface air measurements can be used to monitor the flux 

13 of CO2 out of the deep subsurface, with deviations from background levels representing potential 

14 leakage. If deviation in the flux of CO2 is detected, it may indicate potential endangerment of 

15 USDWs. While subsurface monitoring forms the primary basis for protecting USDWs, near16 surface and surface techniques could be the last line of monitoring. Under today’s proposal, 

17 owners or operators would, at the Director’s discretion, be required to conduct surface air 

18 monitoring and/or soil gas monitoring in the AoR. Knowledge of leaks to shallow USDWs is of 

19 critical importance since these USDWs are more likely to serve public water supplies than 

20 deeper formations. If leakage to a USDW should occur, near-surface and surface monitoring can 

21 identify the general location of the leak. 

22 
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1 A range of techniques employed at varied monitoring frequencies are available for 

2 implementation. Optimal spacing of monitoring wells, eddy covariance towers, or soil gas 

3 chambers would need to be selected, and may be based on the outcome of other monitoring 

4 techniques such as seismic or ERT. 

5 

6 For surface air monitoring, chambers can be placed directly on the soil and trapped gases are 

7 passed through an infrared gas analyzer to determine CO2 content (GEO-SEQ Best Practices 

8 Manual). Changes in CO2 concentration and air flow rates are used to calculate a flux. 

9 Measurements using chambers are typically conducted along a grid, which has the benefit of 

10 defining spatial and temporal variations in CO2 flux that could be used for pinpointing and 

11 quantifying any leaks. Chamber measurements, however, are labor-intensive and are not 

12 efficient for sampling over large areas. For each of these methods, baseline (pre-injection) 

13 monitoring is very important in order to establish conditions for future comparison. There are 

14 natural sources of CO2 that can have wide variability and thus could mask leakage from a GS 

15 operation. 

16 

17 Eddy covariance techniques have been used for ecological applications to measure carbon fluxes 

18 from vegetated areas, and show promise for CO2 monitoring for GS operations (Miles, et al., 

19 2005). The equipment is installed on a tower and CO2 is measured with an infrared gas analyzer 

20 (GEO-SEQ Best Practices Manual). Wind velocity, relative humidity, and temperature are also 

21 measured and the information is integrated to calculate a CO2 flux. The height of the tower 

22 controls the aerial coverage, with higher towers averaging over larger areas. Because of the 

23 large coverage, the exact location of a leak would be difficult to pinpoint, and this method may 
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1 be better for detecting slow, diffuse leaks. Eddy covariance also assumes a horizontal and 

2 homogeneous land surface, which may not hold true for all GS locations. It does have the 

3 advantage of being automated, greatly reducing the labor involved. 

4 

5 Hyperspectral image analysis is a form of remote sensing that has been used, among other 

6 applications, for mapping vegetation habitat boundaries and for differentiating species types. 

7 Scanners collect images of a given feature using a number of relatively small wavelength bands, 

8 including in the visible and infrared portions of the spectrum. Because different elements have 

9 different spectral signatures, a hyperspectral image can convey information about composition. 

10 The potential utility for CO2 monitoring would be the ability to map the response of vegetation to 

11 elevated soil CO2 concentrations (Pickles and Cover, 2005). 

12 

13 LIDAR (light detection and ranging) is a remote sensing method that is used extensively in 

14 atmospheric science, and is currently under investigation as an option for CO2 detection to 

15 monitor GS sites (Benson and Myer, 2002). Similar in principle to RADAR, LIDAR uses light 

16 instead of radio waves, permitting resolution of very small features, such as aerosols. Light is 

17 pulsed from a laser and various constituents in the atmosphere reflect back some of the light. A 

18 number of properties of the backscattered light allow one to infer the atmospheric composition, 

19 including concentrations of CO2. Currently, differential absorption LIDAR (DIAL) is being 

20 studied by researchers at Montana State University for detecting CO2 leaks in pipelines. 

21 
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1 EPA proposes that owners and operators report semi-annually on the characteristics of injection 

2 fluids, injection pressure, flow rate, temperature, volume and annular pressure, and on the results 

3 of MITs, ground water monitoring, and any required atmospheric/soil gas monitoring. 

4 

5 EPA seeks comment on the appropriate amount and types of monitoring that should be 

6 conducted at a GS site. Specifically, EPA seeks comment regarding the usefulness of indirect 

7 geophysical monitoring and surface air and soil gas monitoring. In addition, EPA seeks 

8 comment regarding the use of a Director-approved monitoring plan for GS sites. 

9 

10 7. Proposed Recordkeeping and Reporting Requirements 

11 Submissions required for consideration of permit applications: Today’s proposal would require 

12 that owners and operators submit relevant site information to the permitting authority for 

13 consideration of permit applications. This information includes maps of the injection wells, the 

14 AoR as determined through computational modeling, all artificial penetrations within the AoR, 

15 maps of the general vertical and lateral limits of USDWs, maps of the geologic cross sections of 

16 the local area, the proposed operating data and injection procedures, proposed formation testing 

17 program, and stimulation program, well schematics and construction procedures, and 

18 contingency plans for shut-ins or well failures. EPA is also proposing that permit applicants 

19 submit a demonstration of financial responsibility to close, plug or abandon the well and to 

20 provide for post-injection site care. 

21 

22 EPA is proposing today that permit applications for GS sites include several plans not currently 

23 required under existing UIC regulations. These plans include a monitoring and testing plan, an 
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1 AoR and corrective action plan, and a post-injection site care plan. The requirement for 

2 additional plans is intended to provide the Director the opportunity to assess proposed project 

3 operating procedures, and addresses GS requirements that are seen to be site-specific (e.g., what 

4 monitoring techniques will be used). In addition, these plans are intended to establish an 

5 ongoing dialogue between the operator and the permitting authority which is more substantial 

6 than that required for other classes of injection wells. EPA seeks comment on the merits of 

7 requiring plans for monitoring, AoR, and post-injection site care as part of a permit application. 

8 

9 Operational recordkeeping and reporting requirements: Under current UIC requirements, 

10 operators must report on a regular basis to the permitting authority, the physical and chemical 

11 characteristics of the injected fluids, as well as other operational data. For Class I industrial and 

12 hazardous wells and Class III wells, operators must submit this information on a quarterly basis. 

13 For Class II wells, operators must submit this information on an annual basis. Today’s proposal 

14 would require that owners or operators of Class VI wells report semi-annually to the permitting 

15 authority, on the physical and chemical characteristics of injection fluids, injection pressure, flow 

16 rate, temperature, volume and annular pressure, annulus fluid volume added, and the results of 

17 MITs, plume tracking, and atmospheric/soil gas monitoring. Additionally, owners and operators 

18 will be required to submit the results of AoR modeling revisions; any updates to the information 

19 on the type, number, and location of all wells within the site AoR; and information on additional 

20 corrective action performed or planned based on AoR reevaluations. EPA considers a less 

21 frequent reporting requirement for Class VI wells compared to Class I wells appropriate 

22 considering the ongoing dialogue for Class VI wells established by multiple plans as discussed 

23 above. 
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1 

2 Under today’s proposal, owners and operators would also be required to maintain recordkeeping 

3 and reporting information for the duration of the project, as well as three years after site closure 

4 (following the post-injection period); and to keep their most recent plugging and abandonment 

5 report for one year following site closure. 

6 

7 Reporting associated with closure and post-injection site care: EPA proposes that owners or 

8 operators notify the Director at least 60 days prior or at a Director-determined time of their intent 

9 to plug the well and of any updates to the post-injection site care plan. After the well is closed, 

10 owners and operators would submit a well plugging report stating that the well was closed in 

11 accordance with the approved post-injection site care plan or specify the differences between the 

12 plan and the actual closure. During the post-injection monitoring period, owners or operators 

13 would report periodically on the results of monitoring. At the end of the post-injection 

14 monitoring period, owners or operators would submit a final post closure and site care report, 

15 along with a non-endangerment demonstration showing that conditions within the subsurface 

16 indicate that no additional monitoring is necessary to assure that there is no endangerment to 

17 USDWs associated with the injection. 

18 

19 Electronic Reporting and Recordkeeping: Under today’s proposal, EPA would require owners 

20 or operators to report data specified in section 146.91 in an electronic format acceptable to the 

21 Director for site, facility and monitoring information. At the discretion of the Director, formats 

22 other than electronic may be accepted after a determination has been made that the entity does 

23 not have the capability to use the required format. Long-term retention of records in an 
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1 electronic format may also be required at the Director's discretion. If records are stored in an 

2 electronic format, information should be maintained digitally in multiple locations (i.e., backed3 up) in accordance with best practices for electronic data. 

4 

5 EPA has previously required electronic reporting of monitoring data in the program implemented 

6 under the Unregulated Contaminant Monitoring Rule (64 FR 50611, September 17, 1999, 40 

7 CFR 141.35(e)). EPA believes that the permit applicants will have the resources to provide 

8 electronic data to the permit authority and that electronic reporting will reduce future burden 

9 related to recordkeeping. In addition, electronic data submissions will facilitate the application 

10 review process and make it easier to track progress of GS projects. EPA is committed to 

11 providing resources to States to develop the capability to exchange data electronically. Several 

12 States have received grants to develop electronic data exchange capability for their current UIC 

13 programs. EPA encourages State primacy agencies to work with EPA regional offices as much 

14 as possible in order to use the new database system for reporting of information regarding Class 

15 VI wells. [web link?] 

16 

17 EPA seeks comment on the requirement for electronic reporting in today’s proposed rule. 

18 In addition to the above recordkeeping and reporting requirements, EPA considered a 

19 requirement for owners or operators of GS sites to provide an annual report during the lifetime of 

20 the project, including the post-injection period, regarding the GS operation. This report would 

21 describe the status of the operation, any new data about the site including operational and 

22 monitoring data and new GS operations or other activities that may affect the plume movement, 

23 any non-compliance, and knowledge gained on GS technology that could contribute to the state 
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1 of the science on GS. This requirement would address the unique and large-scale nature of CO2

2 GS operations, provide the public with information regarding the operation, and facilitate 

3 information transfer about GS technology. Although EPA has not included a requirement for 

4 this report in today’s proposal, EPA seeks comment regarding the necessity for such an annual 

5 report. 

6 

7 8. Proposed Well Plugging and Post-Injection Site Care Requirements 

8 Today’s proposal outlines well plugging and post injection site care requirements for CO2

9 injection sites after injection activities end. If finalized, these new requirements at 40 CFR 

10 146.92-146.93 would ensure that owners or operators plug wells and manage sites in a manner so 

11 that wells do not serve as a conduit for escape of stored CO2 through unexpected migration from 

12 the injection site after injection ends, preventing endangerment of USDWs. EPA is proposing to 

13 give owners or operators flexibility in meeting the well plugging requirements by allowing the 

14 owner or operator to choose from available materials and tests to carry out the proposed 

15 requirements. EPA is not specifying the types of materials or tests that must be used during well 

16 plugging because there are a variety of methods that are appropriate and new materials and tests 

17 may become available in the future. EPA is also proposing that a combination of a fixed 

18 timeframe and performance standard be used to determine the duration of the post-injection site 

19 care period. 

20 

21 Steps in Injection Well Plugging: EPA is proposing that owners or operators develop a well 

22 plugging plan, and conduct several activities associated with the plugging of GS wells. Injection 

23 well plugging must comply with requirements of 40 CFR 144.12(a). The plan includes: 1) 
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1 providing notice of intent to plug a well at least 60 days prior to well plugging, 2) flushing each 

2 well to be plugged with a buffer fluid, 3) testing the mechanical integrity of each well, 4) 

3 plugging each well in a manner that will prevent the movement of fluid that may endanger 

4 USDWs, and 5) submitting a plugging report within 60 days after plugging the well or at the 

5 time of the next semi-annual report (whichever is less). 

6 

7 Notice of intent to plug: The notice of intent to plug provides a 60-day advance notice to the 

8 Director that the owner or operator intends to close the well. If circumstances warrant a shorter 

9 time period for giving notice of intent to plug, the Director may approve a shorter notice period. 

10 

11 Well Flushing: Flushing removes fluids remaining in the long string casing that could react with 

12 the well components over time. Fluids used for flushing may vary, but must provide sufficient 

13 buffering ability to avoid the possibility of reactions due to residual CO2 or other contaminants in 

14 the fluid. 

15 

16 Mechanical Integrity Testing: Mechanical integrity testing allows owners or operators to ensure 

17 that the long string casing and cement that are left in the ground after closure will maintain 

18 integrity over time. For GS wells, there are a number of methods that can be used to test 

19 mechanical integrity, including pressure tests with liquid or gas, radioactive tracer surveys, and 

20 noise, temperature, pipe evaluation, or cement bond logs. 

21 
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1 Well Plugging: The Agency is proposing that owners or operators plug wells in a manner that 

2 does not endanger USDWs. This may be accomplished in a number of ways using a number of 

3 different types of materials. In the case of GS wells, the plugging materials must be compatible 

4 with the fluids with which the materials may be expected to come into contact and plugged to 

5 prevent the movement of fluids either into or between USDWs. 

6 

7 Plugging Report: The owner or operator would be required to submit a report which includes 

8 information on the implementation of the plugging plan, including the date the well was plugged, 

9 the activities conducted to prepare well for plugging, the materials used for plugging, and the 

10 location of the well. The owner or operator may either submit the plugging report as a separate 

11 report within 60 days after the plugging activity, or update the semi-annual report required at 40 

12 CFR 146.92 of this proposed rule to include plugging information and submit the updated report 

13 within 60 days after the plugging activity. EPA is proposing that that the owner or operator must 

14 certify that the plugging report is accurate. If the well was plugged by an entity other than the 

15 owner or operator, that entity must also certify that the plugging report is accurate. 

16 

17 In addition, EPA is proposing the owners or operators prepare for eventual site closure in 

18 advance of the time when well plugging activities take place to ensure that a plan is in place in 

19 the event of an unexpected need to plug a well or close the site. Today’s proposal would require 

20 owners or operators to submit a Well Plugging Plan at the same time the permit application is 

21 submitted and to have this plan approved by the Director. As part of the Well Plugging Plan, the 

22 owner/operator would be required to conduct certain activities related to well plugging, and 

23 provide the information related to well plugging including the following: 1) testing methods used 
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1 to determine that the components of the well will maintain mechanical integrity over time; 2) 

2 type and number of plugs to be used; 3) placement of each plug, including the elevation of the 

3 top and bottom of each plug; 4) type, grade, and quantity of material to be used in plugging; and 

4 5) method used to put plugs in place. In addition, if for any reason the well plugging activities 

5 stated in the plan no longer reflect what is likely to occur upon closing the well, the owner or 

6 operator would be required to make changes to the plan and submit to the Director for approval 

7 before notifying the Director of intent to plug the well. 

8 

9 Post Injection Site Care: Today’s proposal would also require that owners or operators 1) 

10 develop a Post Injection Site Care and Closure plan, 2) monitor the site following cessation of 

11 the injection activity, and 3) plug all monitoring wells in a manner which prevents movement of 

12 injection or formation fluids that could endanger a USDW. 

13 

14 The Post Injection Site Care and Closure plan would be required to be submitted as part of the 

15 permit application and approved by the Director. It describes several activities associated with 

16 the post injection site care and closure of GS sites. Activities that would be required in the Post 

17 Injection Site Care and Closure plan include: 1) record of the pressure differential between pre18 injection and anticipated post injection pressures in the injection zone; 2) predicted position of 

19 the plume and associated pressure front at the time the site is closed; 3) description of post 

20 injection monitoring location(s), methods, and proposed frequency of monitoring; and 4) 

21 schedule for submitting post-injection site care and monitoring results to the Director. In 

22 addition, if for any reason the post injection site care and closure activities stated in the plan no 

23 longer reflect what is likely to occur upon closing the site, the owner or operator would be 
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1 required to make changes to the plan and submit the plan to the Director for approval within 30 

2 days of such change. Examples of factors which may require a modified post-injection site care 

3 and closure plan would include changes in injection procedures or volumes or plume movement 

4 in an unanticipated direction. 

5 

6 Upon permanent cessation of injection, the owner or operator would either submit an amended 

7 Post-Injection Site Care and Closure plan or demonstrate to the Director through monitoring and 

8 modeling results that no amendment to the plan is needed. Owners or operators would also be 

9 required to use any other information deemed necessary by the Director to make this 

10 demonstration. 

11 

12 The Post Injection Site Care and Closure plan would include a description of the monitoring that 

13 will occur after injection ceases. The owner or operator would monitor the site to show the 

14 position of the CO2 plume and pressure front and demonstrate that USDWs are not being 

15 endangered. A record of the pressures in the injection formation and surrounding areas as well 

16 and the pressure decay rate can help the owner or operator assess that the injected fluid does not 

17 pose endangerment to USDWs. 

18 

19 Post Injection Timeframe: Current UIC regulations do not limit the duration of the post closure 

20 period; however, many environmental programs use a 30-year period as a frame of reference. In 

21 many cases, a 30-year timeframe has been sufficient to determine that remaining pressure in 

22 plugged wells containing liquids will not lift fluid to overlying strata (53 FR 28143, July 26, 
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1 1988). However, characterizing post-closure timeframes for GS is more challenging. Given the 

2 buoyancy of CO2, viscosity, and large injection volumes associated with GS, the area over which 

3 CO2 will spread in the subsurface is likely to be larger than for existing well classes and 

4 therefore, the area over which there is potential for endangerment of USDWs is likely to be 

5 greater. The presence of physical and geochemical trapping mechanisms is likely to reduce the 

6 mobility of CO2 over time and research also suggests that pressure within the storage system will 

7 drop significantly when injection ceases, thus decreasing the risks of induced seismic activity, 

8 and faulting and fracturing (Birkholzer et al., 2005) and making storage more secure over longer 

9 timeframes. However, the timeframe over which this happens is difficult to define because it is 

10 based on site-specific considerations. 

11 

12 EPA considered three distinct alternatives for determining post injection site care and monitoring 

13 timeframes 1) establishing a fixed timeframe for post-injection site care; 2) allowing a 

14 performance-based approach to the post-injection site care time period; and 3) a combination of 

15 fixed timeframe and performance standard. 

16 

17 EPA considered the approach of specifying a fixed duration of time after which the post injection 

18 site care ends. As part of this approach, EPA evaluated four different timeframes: 10, 30, 50, 

19 and 100 years. 

20 

21 EPA reviewed studies, industry reports and environmental programs to determine appropriate 

22 post-injection site care time frames. Studies reviewed included those done by: Flett, M., Gurton 
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1 R., and G. Weir. 2007, Obi E.I., and M.J. Blunt. 2006, and Doughty, C. 2007. (see USEPA, 

2 2008a) A review of these studies suggests that the actual time for CO2 plume stabilization will 

3 be very site specific, being influenced by geologic factors such as formation permeability, 

4 geochemistry, and the degree of capillary trapping. In addition, predicted results will depend on 

5 several modeling considerations and assumptions, and thus will be to some degree model 

6 specific. Based on the three studies use for this preliminary analysis, modeling results indicate 

7 that the CO2 plume stabilized on the time frame of 10-100 years after the cessation of injection. 

8 

9 EPA also reviewed an IOGCC Task Force report which suggests a 10-year time frame from well 

10 closure (termed for the purposes of today’s proposal as “site closure”) to the release of the 

11 operator from liability. Alternatively, some environmental programs—including the UIC 

12 Program—use a 30-year period as a frame of reference. 

13 

14 While 10 years may be within the timeframe suggested in some studies, there are circumstances 

15 under which the potential risks of endangering USDWs will not decline within that timeframe 

16 given that stabilization may continue for several decades. (USEPA, 2008 a) Also, a 30-year 

17 timeframe can be appropriate for the types of fluids typically injected under the UIC Program 

18 (i.e., fluids that are liquids at standard pressure and temperature). However, longer timeframes 

19 may be more appropriate for GS wells, because the fluid is likely to be stored in supercritical 

20 form and the plume for a full-scale GS project will likely be large and substantial pressure 

21 increases will likely be observed during operation. 

22 
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1 Another option considered by the Agency is to apply a performance standard, i.e., that post2 injection site care will continue until the plume is stabilized and cannot endanger USDWs. 

3 Current UIC regulations at 40 CFR 146.71 utilize a performance type approach by requiring that 

4 the owner or operator of a Class I hazardous well observe and record pressure decay for a time 

5 specified by the Director. A similar performance standard could be considered for GS wells. 

6 Pressure decay data help to define the appropriate period of regulatory concern, because the 

7 likelihood that the injected fluid will migrate into USDWs above or adjacent to the injection 

8 zone decreases as injection-induced pressures in the formation decay. The post injection period 

9 ends when the models predicting CO2 movement are consistent with monitoring results 

10 demonstrating that there is no potential threat of endangerment to USDWs. 

11 

12 Combination of Fixed Timeframe and Performance Standard: EPA is proposing using a 

13 combination of fixed timeframe and a performance standard as described above. EPA is 

14 proposing a post-injection monitoring time period of 50 years with Director’s discretion to 

15 change that period to lengthen or shorten the 50-year period if appropriate. EPA expects that in 

16 most cases Directors would first apply a 50-year time period, and extend the timeframe if 

17 potential of endangerment to USDWs exists or if modeling and monitoring results are 

18 inconsistent with planned movement. A reduction in the 50-year time period should only be 

19 made when data on pressure, fluid movement, mineralization, and/or dissolution reactions 

20 support a compelling reason to shorten the timeframe. 

21 

22 To ensure that the post-closure monitoring timeframe is long enough to determine that there is no 

23 threat of endangerment to USDWs from injection activities, EPA is proposing a post-closure 
Deliberative draft – do not cite or distribute Page 122 

1 period of 50 years. During this 50-year post-closure period, the owner or operator would be 

2 required to submit periodic reports providing monitoring results and updated modeling results as 

3 appropriate until a demonstration of non-endangerment to USDWs can be made. Once the 50-

4 year post-injection monitoring period ends, owners or operators would be required to provide 

5 documentation that demonstrates that the models predicting CO2 movement are consistent with 

6 monitoring results and that there are no longer risks of endangerment to USDWs. 

7 

8 EPA is also proposing to allow the Director to shorten or lengthen the 50-year timeframe based 

9 on performance of the site. The Director may require that the post-injection site care period 

10 extend beyond the 50-year time frame if a demonstration of non-endangerment to USDWs 

11 cannot be made. Alternately, if the owner or operator can demonstrate that the remaining 

12 pressure front and plume will not endanger USDWs, then owners or operators may request a 

13 decreased post injection site monitoring and care period. 

14 

15 While EPA considered the 10-year, 30, and 100-year timeframes, the Agency considers that a 

16 50-year timeframe is appropriate because there are circumstances under which the potential risks 

17 of endangerment to USDWs will not decline within 10 years and that, while fluids that are liquid 

18 at standard pressure and temperature may show plume stabilization at about 30 years, or sooner, 

19 more time may be needed to accommodate the magnitude of CO2 injected as part of a full-scale 

20 GS project. The time needed to allow pressures to equalize within the subsurface because of the 

21 higher levels of mobility of injected CO2 may likely exceed 30 years. EPA is not proposing to 

22 require that owners or operators conduct post-injection site care activities for 100 years unless 

23 monitoring and modeling information suggests that plumes may still endanger after the 50-year 
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1 post injection site care time frame has ended. EPA considers that a 50-year timeframe represents 

2 a reasonable mid-point at which owners or operators must make a determination using 

3 monitoring and modeling that the injected CO2 will not endanger USDWs. 

4 

5 Site Closure: The Director would determine that the post-injection site care period has ended 

6 and authorizes site closure when the following have occurred: 

7 • the Director has certified that the well plugging report is accurate; 

8 • the Director receives all information required of the post-injection site care and 

9 closure plan; 

10 • the data demonstrate to the satifaction of the Director that there is no threat of 

11 endangerment to USDWs. 

12 Once the Director approves site closure, the owner or operator is required to submit a post13 injection site closure report within 90 days. The report would provide documentation of 

14 injection and monitoring well plugging; copies of notifications to State and local authorities that 

15 may have authority over future drilling activities in the region; and records reflecting the nature, 

16 composition, and volume of the injected carbon dioxide stream. The purpose of this report 

17 would be to provide information to potential users and authorities of the land surface and 

18 subsurface pore space regarding the operation. In addition, the owner or operator of the injection 

19 site must record a notation on the deed to the facility property or any other document that is 

20 normally examined during title search that will in perpetuity provide notification to any potential 

21 purchaser of the property information, that the land has been used to sequester CO2. 

22 
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1 EPA is requesting comments on the proposed requirements for well plugging and post injection 

2 site care, including the proposed requirements for the post injection time period. In addition, 

3 EPA seeks comment on whether the owner or operator should be allowed to shorten the 

4 timeframe based on performance information, and whether EPA should require a shorter or 

5 longer post injection period if data suggests the time frame should be adjusted. 

6 

7 9. Proposed Financial Responsibility and Long-term Care Requirements 

8 Today’s proposal would require that owners or operators demonstrate, maintain financial 

9 responsibility, and have the resources for activities related to closing and remediating GS sites. 

10 EPA is proposing that the rule only specify a general duty to obtain financial responsibility 

11 acceptable to the Director, and will provide guidance to be developed at a later date that 

12 describes recommended types of financial mechanisms that owners or operators can use to meet 

13 this requirement. 

14 

15 Although the SDWA does not have explicit provisions for financial responsibility, as included in 

16 RCRA, EPA believes that the general authorities provided under the SDWA authority to prevent 

17 endangerment of USDWs include the authority to set standards for financial responsibility to 

18 prevent endangerment of USDWs from improper plugging, remediation, and management of 

19 wells after closure. The SDWA authority does not currently extend to financial responsibility for 

20 activities unrelated to protection of USDWs (e.g., coverage of risks to air, ecosystems, or public 

21 health unrelated to USDW endangerment). It also does not cover transfer of owner or operator 

22 financial responsibility to other entities, or creation of a third party financial mechanism where 

23 EPA is the trustee. 
Deliberative draft – do not cite or distribute Page 125 

1 

2 Today’s proposal would require owners or operators to demonstrate financial responsibility for 

3 corrective action described in 40 CFR 146.84 of this notice, including well plugging, post4 injection site care and closure, and emergency and remedial response using a financial 

5 mechanism acceptable to the Director. The Director would determine whether the mechanism 

6 the owner or operator submits is adequate to pay for closure, post-injection care, and remediation 

7 that may be needed to prevent endangerment of underground sources of drinking water. 

8 

9 Owners or operators would no longer need to demonstrate that they have financial assurance 

10 after the post-injection site care period has ended. This generally occurs when the Director 

11 approves the completed Post-Injection Site Care and Closure plan and then determines that the 

12 injected fluid no longer poses a threat of endangerment to USDWs (e.g., the fluid no longer 

13 exhibits a propensity to move or migrate out of the injection zone to any point where it could 

14 endanger a USDW). 

15 

16 The Agency is proposing that the owner or operator periodically update the cost estimate for 

17 closure, post-injection care, and remediation to account for any amendments to the area of 

18 review and corrective action plan (40 CFR 146.84), the plugging and abandonment plan, and the 

19 post closure care plan (40 CFR 146.93). EPA is also proposing that the owner or operator 

20 submit an adjusted cost estimate to the Director if the original demonstration is no longer 

21 adequate to cover the cost of the plugging and post-injection site care and closure. As proposed, 

22 the Director would set the frequency for owners or operator redemonstration of financial 

23 responsibility and resources. It may be appropriate to redemonstrate financial responsibility on a 
Deliberative draft – do not cite or distribute Page 126 

1 periodic basis. Such redemonstration would take into account any amendments to the area of 

2 review and corrective action plan (40 CFR146.84) and adjustments for inflation. It may also be 

3 necessary to adjust cost estimates if the Director has reason to believe that the original 

4 demonstration is no longer adequate to cover the cost of the plugging and post-injection site care 

5 and closure. EPA is also proposing that the owner or operator notify the Director of adverse 

6 financial conditions, including but note limited to bankruptcy proceedings, which name the 

7 owner or operator as debtor, within 10 business days after the commencement of the proceeding. 

8 

9 EPA plans to develop guidance that is similar to current UIC financial responsibility guidance 

10 for Class II owners or operators. Currently, EPA guidance (EPA 570/9-90-003 May 1990) 

11 describes several options owners or operators can use to meet the requirements to demonstrate 

12 financial responsibility for well plugging. Financial assurance is typically demonstrated through 

13 two broad categories of financial instruments: 1) third party instruments, including surety bond, 

14 financial guarantee bond or performance bond, letters of credit (the above third party instruments 

15 must also establish a trust fund), and an irrevocable trust fund; 2) self-insurance instruments, 

16 including the corporate financial test and the corporate guarantee. A detailed description of these 

17 instruments is provided in the docket for this proposed rulemaking and at [include link to 

18 OSWER’s fact sheets here or refer to in docket—not yet finalized, inclusion pending 

19 finalization]. 

20 

21 Supplemental Information: In recent years, the EPA’s Office of Inspector General (OIG) and the 

22 U.S. Government Accountability Office (GAO) have raised issues regarding the use of financial 

23 responsibility instruments applicable to site closure for several EPA programs. Information 
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1 regarding these reviews and EPA’s responses are available on EPA’s website at [insert website 

2 address]. The OIG and GAO recommendations suggest that EPA may need to update or provide 

3 additional guidance in the following areas: cost estimation methodology; pay-in period for trust 

4 funds; the type of insurance provider that may be used; requirements for acceptable surety bonds 

5 and/or their providers; and the way by which corporations demonstrate financial strength/credit 

6 worthiness. 

7 

8 In response to evaluations of financial responsibility instruments, EPA’s RCRA program has 

9 issued a comprehensive financial responsibility strategy to improve the implementation of the 

10 financial responsibility requirements, as well as assess whether regulatory changes to certain 

11 mechanisms and financial responsibility requirements are warranted. EPA has begun 

12 implementing this strategy by providing additional guidance to support implementation and 

13 oversight of RCRA financial responsibility programs, providing training to EPA Regions and 

14 states, and developing tools (e.g., cost-estimating software) to assist staff in performing reviews 

15 of complex cost information. 

16 

17 In addition, EPA’s RCRA program has enlisted the experience and expertise of the 

18 Environmental Finance Advisory Board (EFAB) to evaluate specific issues related to financial 

19 responsibility. EFAB has completed assessments of the corporate financial test and captive 

20 insurance, and is currently in the process of undertaking analyses of third-party insurance and 

21 uncertainties associated with estimating costs that must be covered by the financial assurance 

22 requirements. In January 2006, the EFAB summarized its findings and recommendations on the 

23 corporate financial test, as a means of demonstrating financial assurance. EFAB's 
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1 recommendations in this area were not based on specific failures of the test, but on their 

2 "knowledge of prudent financial practices and the availability of existing expertise in the 

3 financial services sector." In March 2007, the EFAB summarized its preliminary findings and 

4 conclusions on its review of insurance, specifically captive insurance, as a means of 

5 demonstrating financial assurance. The Agency plans to continue to track these efforts by the 

6 EFAB, because they may provide key directions for future GS requirements with respect to 

7 financial responsibility. 

8 

9 EPA is considering updating mechanisms for demonstrating financial responsibility for GS 

10 projects. EPA is evaluating revising guidance to address the current financial responsibility 

11 requirements on the following topics: cost estimation for plugging, pay-in period for trust funds, 

12 insurance providers, surety bonds and/or their providers, and corporate demonstration of 

13 financial strength/credit worthiness. 

14 

15 Cost estimation for plugging: One of the most critical aspects to ensuring that owners or 

16 operators have the resources to pay for well plugging is cost estimation. Sound cost estimation 

17 requirements ensure that sufficient funds are set aside in the financial assurance instrument to 

18 properly undertake covered activities (e.g., plugging and post-injection site care) at any time 

19 during the operating life of the facility and during the post-injection care 

20 

21 EPA is assessing whether the cost estimate underpinning financial assurance should be based on 

22 the cost of retaining an independent, third party to conduct covered activities, such as well 

23 plugging. EPA also is considering provisions for annual inflationary adjustments and is 
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1 weighing the inclusion of a third-party certification requirement, or provisions for a third-party 

2 audit, in cases where the owner or operator self-prepares its cost estimate. Revision in this area 

3 will reduce the possibility of undervalued cost estimates. EPA will also consider EFAB’s 

4 findings on this issue when they become available. 

5 

6 Pay-in period for trust funds: Current UIC guidance describes trust funds as a form of financial 

7 assurance. The owner or operator may deposit funds into the trust fund in phases; that is, either 

8 over the term of the initial permit or over the remaining operating life of the injection well, as 

9 estimated in the well’s plugging and abandonment plan, whichever period is shorter. Because of 

10 the possibility that the owner or operator may face financial distress prior to the trust being fully 

11 funded, EPA is considering a guidance approach that would recommend adopting a pay in period 

12 of three years for GS projects, consistent with other similar programs in the Agency. 

13 

14 Insurance providers: Current UIC regulations for Class I hazardous waste injection allow for the 

15 use of insurance for purposes of demonstrating financial responsibility. However, insurance was 

16 not included as part of the guidance provided for Class II injection because this insurance 

17 mechanism was and still is, rarely used for the purpose of demonstrating financial assurance for 

18 injection wells. EPA is assessing whether to provide guidance on the use of insurance providers 

19 and, if so, whether to update eligibility requirements for insurers for GS wells consistent with 

20 other current Federal agency practices. 

21 

22 In addition, EPA is evaluating recommendations from Office of the Inspector General (OIG), the 

23 Government Accountability Office (GAO), and EFAB on the use of insurance as a financial 
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1 responsibility mechanism. EPA will also consider any additional recommendations EFAB may 

2 have on the use of third party insurance. 

3 

4 Surety bonds and/or their providers: Current UIC guidance describes several options for using 

5 surety bonds for purposes of demonstrating financial responsibility. The regulations at 40 CFR 

6 144 for Class I wells stipulate that eligible surety bond providers must be listed by the U.S. 

7 Department of Treasury on its Circular 570. Because surety bonds are a specialized line of 

8 insurance, EPA is assessing whether additional eligibility requirements for sureties, similar to 

9 those under consideration for insurers, are necessary for GS wells. 

10 

11 Corporate demonstration of financial strength/credit worthiness: UIC program guidance also 

12 describes options for owners or operators to self-assure their obligations to close, plug, and 

13 abandon the well. To be approved by the Director, the owner or operator would likely need to 

14 self-assure in the form of either a corporate financial test filed by the owner or operator of the 

15 injection well, or a corporate guarantee (including a corporate financial test) filed by the parent 

16 corporation of the owner or operator of the injection well. A corporate guarantee may also be 

17 provided by a “sibling” corporation (that is a company that shares the same higher-tier parent) or 

18 a company with whom they have a substantial business relationship. The guidance explains that 

19 demonstrating self-assurance typically includes either use of a bond rating or a series of financial 

20 ratios. Both the UIC financial responsibility provisions for Class I hazardous waste injection and 

21 the RCRA subtitle C provisions allow the use of self-assurance through a financial test or 

22 corporate guarantee. 

23 
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1 EPA is assessing whether a financial ratings threshold for all companies using a self-guarantee, 

2 similar to those used by other Federal agencies, is appropriate. The Agency also is considering 

3 what constitutes an appropriate financial rating threshold, and whether a financial rating greater 

4 than BBB or Baa (i.e., the current rating threshold established under the UIC regulations) is 

5 appropriate for GS wells. 

6 

7 In addition, EPA is considering whether adjustments should be made to the absolute net worth 

8 threshold of $10 million currently required under the UIC regulations. Specifically, EPA is 

9 assessing the net worth requirements of other Federal agencies and EPA programs to determine 

10 whether to make adjustments. For example, the Minerals Management Service within the 

11 Department of Interior, requires a net worth threshold at least 10 times the amount of the 

12 obligations being assured (see 30 CFR 253.25). Additionally, the Agency is in the process of 

13 evaluating potential changes to the RCRA subtitle C financial test requirements, including an 

14 option recommended by EFAB to require a financial ratings threshold for all companies using a 

15 financial test to self-assure their environmental obligations. EPA will consider the outcome of 

16 that process for possible application to GS wells guidance. 

17 

18 EPA is requesting comments on whether financial responsibility mechanisms to be 

19 recommended in EPA guidance should be adjusted in the manner described, whether additional 

20 instruments should be included, and whether other adjustments to the financial responsibility 

21 mechanisms should be considered, all subject to EPA’s authority under the SDWA. The Agency 

22 is also requesting comment on allowing separate financial demonstrations to be submitted for the 

23 plugging and abandonment of the injection well and for the post closure care requirements. 
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1 Since post closure care has the potential to extend many years into the future, subsequent to the 

2 time a permit is issued, the Agency believes that it may be advantageous to require the approval 

3 of the plugging and abandonment financial demonstration at permit issuance and the post closure 

4 care financial demonstration at a later time (e.g., within 180 days of notifying the Director that 

5 the well will be plugged and abandoned). Trying to determine the cost for post closure care, 

6 possibly 30 to 50 years in the future, could be difficult, as could the approval of a financial 

7 demonstration. 

8 

9 Considerations for Long-term Care: While EPA has authority to require closure and post10 injection care (e.g., monitoring, remediation) and financial responsibility for the protection of 

11 USDWs, the SDWA does not provide authority under financial responsibility or other provisions 

12 for coverage of risks to air, ecosystems, or public health. In addition, the SDWA does not 

13 provide EPA with the authority to transfer liability from one entity to another. Trust 

14 responsibility for potential impacts to USDWs remains with the owner or operator indefinitely 

15 under current SDWA provisions. 

16 

17 Responsibility for long-term care is often considered an important topic related to GS because of 

18 cost implications of indefinite responsibility for GS sites. Because of the focus of the SDWA on 

19 endangerment to USDWs and the absence of provisions to allow transfer of liability, 

20 stakeholders have expressed interest in alternative instruments for addressing financial 

21 responsibility after the post injection care period has ended. As a result of the interest in 

22 alternative instruments, including indemnity programs, EPA has compiled information on a 

23 variety of alternative instruments not currently available under the SDWA. This discussion is on 
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1 EPA’s website at [insert web address]. EPA has not determined whether any of the models above 

2 are appropriate for GS wells, however, EPA is aware that these models may contain important 

3 concepts that may become the model for future strategies for long-term care. 

4 

5 B. Adaptive Approach

6 To meet the potentially fast pace of implementation of GS, EPA is using an adaptive approach to 

7 regulating CO2 injection for GS. In 2007, EPA issued UIC Program Guidance # 83, which 

8 allows limited-scale experimental GS projects to proceed under the Class V experimental 

9 technology well classification. An adaptive approach allows regulatory development to move 

10 ahead in time to meet the future demand for permits, while recognizing the need to continue to 

11 gather data from pilot projects and other research as it becomes available. 

12 

13 EPA will continue to evaluate ongoing research and demonstration projects, review input 

14 received on this proposal and gather other relevant information, as needed, to make refinements 

15 to the rulemaking process. If appropriate, EPA will publish notices to collect new data before 

16 issuing a final rule on CO2 injection for GS. EPA plans to issue a final rule in advance of full17 scale deployment of GS. EPA will track implementation of the final GS rule to determine 

18 whether these requirements continue to meet SDWA objectives and, if not, revise them as 

19 needed. If new information gathered during implementation suggests the requirements need 

20 revisions, EPA will initiate the appropriate procedure, including public notice and comment. 

21 

22 IV. How Should UIC Program Directors involve the Public in Permitting Decisions for GS 

23 Projects? 
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1 Public participation has been an important part of the UIC Program since its inception. Public 

2 participation has a number of benefits, including 1) providing citizens with access to decision3 making processes that may affect them; 2) enabling the owner/operator and the permit writer to 

4 educate the community about the project; 3) ensuring that the public receives adequate 

5 information about the proposed injection; 4) allowing the permitting authority to become aware 

6 of public viewpoints, preferences and environmental justice concerns; and 5) ensuring that public 

7 viewpoints, preferences and concerns have been considered by the decision-making officials. 

8 

9 GS of CO2 is a new technology that is unfamiliar to most people, and maximizing the public’s 

10 understanding of the technology can result in more meaningful public input and constructive 

11 participation as new GS projects are proposed and developed. Critical to the success of GS is 

12 early and frequent involvement through education and information exchange. Such exchange 

13 can provide early insight into how the local community and surrounding communities perceive 

14 potential environmental, economic or health effects. 

15 

16 Owners or operators and permitting authorities can maximize the public participation process, 

17 thereby increasing the likelihood of success, by integrating social, economic, and cultural 

18 concerns of the community into the permit decision making process. 

19 

20 EPA examined existing requirements for public participation across the Agency’s environmental 

21 programs. EPA is proposing to adopt the requirements at 40 CFR Part 25 and the permit 

22 procedures at 40 CFR Part 124 for long-term storage of CO2. Under today’s proposal, the 

23 permitting authority would be required to provide public notice and opportunity for public input. 
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1 This includes providing public notice of pending actions via newspaper advertisements, postings, 

2 or mailings to interested parties and providing a fact sheet or statement of basis that describes the 

3 planned injection operation and the principal facts and issues considered in preparing the draft 

4 permit. Under today’s proposal, permitting authorities would provide a 30-day comment period 

5 during which public hearings may be held. At the conclusion of the comment period, the 

6 permitting authority would be required to prepare a responsiveness summary that becomes part 

7 of the public record. 

8 

9 EPA recognizes that advances in information technology and the available avenues for 

10 communication have changed the way that people receive news and information and that new 

11 means of engaging stakeholders are now available. Roundtables, constituency meetings, 

12 charrettes (workshops designed to involve the public in a planning or design process), 

13 information gathering sessions, cable TV, and the Internet are just a few tools the Agency has 

14 come to rely upon over the past decade to ensure more effective stakeholder involvement and 

15 public participation. These technologies provide a host of opportunities to educate and involve 

16 the public about GS technology and pending decisions. 

17 

18 In addition, electronic information technology has become widely available to inform and 

19 involve the public. Web pages, discussion boards, list serves, and broadcast text messages via 

20 cell phones are all available to keep the public informed. 

21 

22 EPA encourages permit applicants and permit writers to use the Internet and other available tools 

23 to explain potential GS projects; describe the technology; and post information on the latest 
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1 developments including schedules for hearings, briefings, and other opportunities for 

2 involvement. 

3 

4 EPA requests comment on adopting the existing requirements for public participation at 40 CFR 

5 Part 25 and 40 CFR Part 124 and whether additional requirements should be included to reflect 

6 the availability of new tools for disseminating and gathering information. Such tools include 

7 cable networks, the Internet, and other new technology. EPA also requests comment on ways to 

8 enhance the public participation process, including engaging communities in the site 

9 characterization process as soon as candidate locations are identified. 

10 

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

12 Wells? 

13 As described in section II.C above, EPA may approve primary enforcement authority for States, 

14 Territories, and Tribes that wish to implement the UIC Program. To gain authority for Class VI 

15 wells, States, Territories, and Tribes will be required to show that their regulations are at least as 

16 stringent as the proposed minimum Federal requirements (e.g., inspection, operation, monitoring, 

17 and recordkeeping requirements that well owners or operators must meet). In general, these 

18 regulations must be as stringent as the Federal requirements, but may be more stringent. Such 

19 Primacy States, Territories, and Tribes are authorized under Section 1422 of the SDWA. 

20 

21 Historically, EPA has approved State and Territorial UIC Program primacy in whole or in part as 

22 follows: 1) for all five classes of wells under Section 1422 of SDWA; 2) for Classes, I, III, IV, 

23 and V under Section 1422 of SDWA; or for 3) Class II wells only under Section 1425 of SDWA. 
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1 Several States with large Class II inventories may have primacy for a combination of wells, i.e., 

2 authority under Section 1425 for their Class II wells and 1422 authority for other well classes. 

3 

4 EPA is aware that some States may wish to obtain primacy for only Class VI wells. Historically, 

5 EPA has not authorized primacy for individual well classes for any state. The SDWA does not 

6 explicitly allow for approval of State UIC programs for individual well classes, however there 

7 appears to be no express prohibition. 

8 

9 There may be benefits to parsing out primacy for Class VI wells, however EPA has not made a 

10 decision on this. Allowing States, Territories, and Tribes to acquire primacy for only Class VI 

11 wells may encourage them to assume the responsibility of implementation and provide for a 

12 more comprehensive approach to managing CCS projects (e.g., capture, transportation, and 

13 geologic sequestration). EPA is seeking comment on the merits and possible disadvantages of 

14 allowing primacy approval for Class VI wells independent of other well classes. 

15 

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

17 Existing UIC regulations allow injection wells to be permitted individually or as part of an area 

18 permit. Because GS projects would likely used multiple injection wells per project, the Agency 

19 anticipates that most owners or operators would seek area permits for their injection wells. 

20 

21 Additionally, 40 CFR 144.36 sets forth the permit duration for the current classes of injection 

22 wells. Permits for Class I and Class V wells are effective for up to 10 years. Permits for Class II 
Deliberative draft – do not cite or distribute Page 138 

1 and III wells may be issued for the operating life of the facility; however they are subject to a 

2 review by the permitting authority at least once every 5 years. 

3 

4 Implementation of the AoR and corrective action plan as described in today’s proposal would 

5 involve periodic re-evaluation of site data, status of corrective action, monitoring results and 

6 modification of operating parameters, as needed. These periodic evaluations would provide the 

7 same effect and assurances obtained through the permit renewal process without the associated 

8 administrative burden. Additionally, the frequent level of ongoing interaction between the owner 

9 or operator and the Director as required by the AoR and corrective action plan is more 

10 substantial than that required for other classes of injection wells. The periodic evaluations and 

11 revisions driven by the various rule-required plans and the underlying computational model 

12 should provide abundant opportunities for technical reassessment by operators and regulators, 

13 and through permit amendments and modifications. 

14 

15 Therefore, EPA proposes that Class VI injection well permits would be issued for the operating 

16 life of the GS project including the post injection site care and closure period. EPA seeks 

17 comment on the merits of this approach. 

18 

19 VII. Cost Analysis 

20 

21 While today’s proposed rule making proposes regulations for the protection of USDWs, it does 

22 not require entities to sequester CO2. Thus, the costs and benefits associated with protection of 
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1 USDWs is the focus of this proposed rule and the costs associated with the mitigation of climate 

2 change are not directly attributable to this proposed rulemaking. 

3 

4 To calculate the costs and benefits of compliance for today’s proposal, EPA selected the existing 

5 UIC program Class I industrial waste disposal well category as the baseline for costs and 

6 benefits. EPA used this baseline to determine the incremental costs of today’s proposal. 

7 

8 The incremental costs of the proposed rule include elements such as geologic characterization, 

9 well construction and operation, monitoring equipment and procedures, well plugging, and post10 closure monitoring. The benefits of this proposed rulemaking could include the decreased risk of 

11 endangerment to USDWs and the decreased potential for health-related risks associated with 

12 contaminated USDWs. 

13 

14 The scope of the cost analysis includes the full range of an injection project, from the end of the 

15 CO2 pipeline at the GS site, to the underground injection and monitoring, as it occurs during the 

16 time frame of the analysis. The scope does not include capturing or purifying the CO2, nor does 

17 it include transporting the CO2 to the GS site. 

18 

19 The 25-year timeframe of the cost analysis is comparable to the time frames used in recent 

20 drinking water-related economic analyses. Costs attributed to the proposed rule are inclusive of 

21 geologic sequestration projects begun during the 25 years of the analysis and all cost elements 

22 that occur during the 25-year timeframe are discounted to present year values. EPA recognizes 

23 the need to revisit the cost analysis prior to the promulgation of a final rule as new data become 
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1 available. The number of GS projects projected over the timeframe of the cost analysis includes 

2 pilot projects and other projects driven by regulations that are in place today. Projections of GS 

3 projects may need to be revisited in light of any new climate change legislation prior to 

4 promulgation of a final rule. However, it is important to note that the proposed rule does not 

5 require anyone to inject CO2.

6 

A. National Benefits and Costs of the Proposed Rule1 7 

8 1. National Benefits Summary 

9 

10 This section summarizes the risk (and benefit) tradeoffs between compliance with existing 

11 requirements and the preferred regulatory alternative (RA) selected during the regulatory 

12 development process. Evaluations in the Cost Analysis include a non-quantitative analysis of the 

13 relative risks of contamination to USDWs for the regulatory alternatives under consideration. 

14 The expected change in risk based on promulgation of the preferred RA and the potential 

15 nonquantified benefits of compliance with this RA are also discussed. 

16 

17 a. Relative Risk Framework—Qualitative Analysis 

18 

19 Table VII-1 below presents the estimated relative risks of the preferred regulatory alternative 

20 selected for compliance with the proposed rule relative to the baseline. The term “baseline” in 

21 the exhibit refers to risks as they exist under current UIC Program regulations. The term 

22 “decrease” indicates the change in risk relative to this baseline. The Agency has used best 

 

1

 Although both estimated costs and benefits are discussed in detail, the final policy decisions regarding this 

rulemaking are not premised solely on a cost/benefit basis. 
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1 professional judgment to qualitatively estimate the relative risk of each regulatory alternative. 

2 This assessment was made with contributions from a wide range of injection well and 

3 hydrogeological experts, ranging from scientists and well owners or operators to administrators 

4 and regulatory experts. 

5 

6 Table VII-1. Relative Risk of Regulatory Components for Preferred Proposed Regulatory 

7 Alternative Versus the Current Regulations 

8 

Baseline 

Direction of Change 

in Risk 

(Relative to Baseline) 

1. Geologic Characterization

Geologic system consisting of a receiving zone; trapping mechanism; and confining 

system to allow injection at proposed rates and volumes. 

Operators provide maps and cross sections of local and regional geology, AoR, and 

USDWs; characterize the overburden and subsurface; and provide information on 

fractures, stress, rock strength, and in-situ fluid pressures within cap rock. 

Decrease 

2. Area Of Review (AoR) Study and Corrective Action

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 

the greatest risk to USDWs. 

Decrease 
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Baseline 

Direction of Change 

in Risk 

(Relative to Baseline) 

3. Injection Well Construction

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. 

Decrease

4. Well Operation

Limit injection pressure to avoid initiating new fractures or propagate existing fractures 

in the confining zone adjacent to the USDWs. 

Decrease 

5. Mechanical Integrity Testing (MIT)

Demonstrate internal and external mechanical integrity, conduct a radioactive tracer 

survey of the bottom-hole cement, and conduct a pressure fall-off test every 5 years. 

Decrease 

6. Monitoring

Monitor the nature of injected fluids at a frequency sufficient to yield data 

representative of their characteristics; Conduct ground water monitoring within the 

AoR. Report semi-annually on the characteristics of injection fluids, injection pressure, 

flow rate, volume and annular pressure, and on the results of MITs, and ground water 

and atmospheric monitoring. 

Decrease 

7. Well Plugging

Ensure that the well is in a state of static equilibrium and plugged using approved 

methods. Plugs shall be tagged and tested. Conduct post-closure monitoring to 

confirm that CO2 movement is limited to intended zones. 

Decrease 

8. Financial Responsibility 

Demonstrate and maintain financial responsibility and resources to close, plug, and 

abandon the well. 

Decrease 

Overall Decrease 

1 Note: See Chapter 2 of the GS Rule Cost Analysis for a detailed description of the components for each 

2 regulatory alternative. 

3 
Deliberative draft – do not cite or distribute Page 143 

1 

2 In the consideration of benefits of the proposed GS Rule, the direction of change in risk 

3 mitigation compared to the baseline regulatory scenario was assessed for each component of the 

4 four regulatory alternatives considered. An overall assessment for each alternative as a whole 

5 requires consideration of the relative importance of risk being mitigated by each component of 

6 the proposed rule. 

7 

8 As shown in Table VII-1, EPA estimates that under the Preferred Alternative, RA3, risk will 

9 decrease relative to the baseline for each of the eight components assessed. 

10 

11 b. Other Nonquantified Benefits 

12 

13 Promulgation of the proposed Rule will result in direct benefits, that is, protection of the USDWs 

14 which EPA is required by statute to protect; and indirect benefits, which are those protections 

15 afforded to entities as a by-product of protecting USDWs. Indirect benefits are described in the 

16 CO2 GS Risk Assessment Document (USEPA, 2008x) and summarized in Chapter 4 of the GS 

17 Rule Cost Analysis. They include mitigation of potential risk to surface ecology and to human 

18 health through exposure to elevated concentrations of CO2. Potential benefits from potential 

19 climate change mitigation are not included in the assessment. 

20 
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1 2. National Cost Summary

2 

3 a. Cost of Preferred Regulatory Alternative 

4 

5 EPA estimated the incremental one-time, capital, and operation and maintenance (O&M) costs 

6 associated with today’s proposed rulemaking. As Table VII-2 shows, the total incremental cost 

7 associated with the Preferred Alternative is $14.9 million and $15.5 million using a 3 percent and 

8 7 percent discount rate, respectively. The costs of the other regulatory alternatives considered are 

9 detailed in the cost analysis, along with a discussion of how EPA derived these estimates. 

10 

11 Table VII-2. Incremental Costs of Preferred Regulatory Alternative 

12 (2007$, $million) 

3% 7%

One-Time $ 1.5 $ 1.5 

Captial $ 4.9 $ 5.9 

O&M $ 8.6 $ 8.1 

Total $ 14.9 $ 15.5 

Cost Type Discount Rate 

13 

14 

15 

16 b. Nonquantified Costs and Uncertainties in Cost Estimates 

17 

18 The purpose of the GS Rule is to mitigate any risk introduced by CO2 GS activity to the quality, 

19 and indirectly quantity, of current and potential future USDWs; furthermore, the proposed rule 

20 requirements are intended to provide redundant safeguards. In the rare case where the proposed 

21 rule is non-implementable or not readily comprehensible, contamination could occur to a 
Deliberative draft – do not cite or distribute Page 145 

1 USDW. In that case, the cost of cleaning up the USDW or finding an alternative source of 

2 drinking water could be attributable to the proposed rule. Based on data from States regarding 

3 implementation of the UIC program and current research, EPA considers the likelihood of this 

4 occurring very small, and has not quantified this risk. 

5 

6 Should the proposed rule somehow impede CO2 GS from happening, then the opportunity costs 

7 of not capturing the benefits associated with CO2 GS could be attributed to the proposed rule; 

8 however, the Agency has tried to develop a rule that balances risk with practicability and 

9 economic considerations, and believes the probability of such impedance is very low. The GS 

10 Rule should serve to bolster public confidence in GS by establishing requirements that manage 

11 risks to USDWs, and should provide to industry regulatory certainty. Thus, EPA believes the 

12 proposed rule will not in any way impede CO2 GS from happening and has not quantified such 

13 risk. 

14 

15 Uncertainties in the analysis are included in some of the basic assumptions as well as some 

16 detailed cost items. If Congress should enact climate change legislation during the 25-year 

17 period of this Cost Analysis, it may affect three basic assumptions on which the analysis is 

18 based: 1) the estimated number of projects that will be affected by the GS Rule; 2) the labor 

19 rates applied; and 3) the estimated number of monitoring wells to be constructed per injection 

20 well to adequately monitor in a given geologic setting. 

21 

22 First, the number of projects that will deploy from 2012 through 2036 may be significantly 

23 underestimated in this analysis should legislation limiting greenhouse gas emissions be enacted. 
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1 The current baseline assumption is that 22 projects will deploy in the 25-year period, as 

2 described in Chapter 3 of this Cost Analysis and explained in detail in the CO2 Sequestration 

3 Baseline Document (USEPA, 2008x). 

4 

5 Second, the labor rate adopted for each of the labor categories described in Section 5.2.1 of this 

6 Cost Analysis (Geoscientist, Geological Engineer, State Geologist, and Agency Geologist) may 

7 be underestimated. The practice of CO2 injection represents an activity that, although already 

8 practiced widely in some contexts (i.e., EOR), is expected to expand rapidly in the coming years. 

9 This expansion may be exponential under certain climate legislative scenarios, which may lead 

10 to shortages in labor and equipment in the short term, resulting in rapid cost escalation for many 

11 of the cost components discussed in this chapter (Anecdotal evidence based on discussions with 

12 industry representatives suggests that there may already be labor shortages developing in some 

13 critical disciplines.) Because the cost analyses presented in this chapter are based on current 

14 industry costs, the level and pace of price responses as the level of CO2 GS increases represent a 

15 highly uncertain component in the cost estimates presented in this chapter. 

16 

17 Third, the Agency assumes three monitoring wells per injection well for the purpose of 

18 estimating national costs; however, the Agency recognizes that operators and primacy agency 

19 Directors may choose more or fewer monitoring wells depending on project site characteristics. 

20 Because the monitoring wells and associated costs represent a significant component of the Cost 

21 Analysis, the Agency acknowledges that this factor may be significant in the overall uncertainty 

22 of the Cost Analysis. 

23 
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1 Additional uncertainties correspond more directly to specific assumptions made in constructing 

2 the cost model. If the assumptions for such items are incorrect, there may be significant cost 

3 implications outside of the general price level uncertainties discussed above. These cost items 

4 are described in Section 5.9.2 of the GS Rule Cost Analysis. 

5 

6 B. Comparison of Benefits and Costs of Regulatory Alternatives of the Proposed Rule

7 

8 a. Costs Relative to Benefits; Maximizing Net Social Benefits 

9 Because EPA lacks the data to perform a quantified analysis of benefits, a direct numerical 

10 comparison of costs to benefits cannot be done. Costs can only be compared to qualitative 

11 relative risks as discussed in section VII-1. 

12 

13 Compared to the baseline, RA3 provides greater protection to USDWs because it is specifically 

14 tailored to the injection of CO2. The current regulatory requirements do not specifically consider 

15 the injection of a buoyant corrosive fluid. In particular, RA3 includes increased monitoring 

16 requirements that provide the amount of protection the Agency estimates is necessary for 

17 USDWs. Monitoring requirements account for 60 percent of the incremental regulatory costs, 

18 half of which is incurred for the construction of monitoring wells, and the other half which 

19 includes tracking of the plume and pressure front through complex modeling at a minimum of 

20 every 10 years for all operators (the cost model assumes every 5 years) and monitoring for CO2

21 leakage. Public awareness of these protective measures would be expected to enhance public 

22 acceptance of CO2 GS. 

23 
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1 RA1 and RA2 do not provide the specific safeguards against CO2 migration that RA3 does 

2 because of a significantly greater amount of discretion allowed to Directors and operators for 

3 interpreting requirements, and less stringent requirements for some compliance activities. (Only 

4 RA3 and RA4 require the periodic complex modeling exercise for tracking the plume, for 

5 example.) RA4 provides greater safeguards against CO2 migration, but at a much higher cost. 

6 

7 b. Cost Effectiveness and Incremental Net Benefits 

8 

9 RA1 and RA2 provide lower costs than RA3 but at increased levels risk to USDWs. Although 

10 RA4 has more stringent requirements, EPA does not believe that the increased requirements and 

11 the increased costs are necessary to provide protection to USDWs. Therefore EPA believes that 

12 RA3 is the best alternative. 

13 

14 C. Conclusions 

15 

16 RA3 provides a high level of protection to USDWs overlying injection zones of CO2. It does so 

17 at lower costs than the more stringent RA4 while providing significantly more protection than 

18 RA1 or RA2. Therefore EPA believes RA3 is the preferred regulatory alternative. 

19 

20 VIII. Statutory and Executive Order Reviews 

21 A. Executive Order 12866: Regulatory Planning and Review 

22 Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993), this action is a "significant 

23 regulatory action.” This proposal is considered a “significant regulatory action” because it raises 

24 “novel legal or policy issues” (EO 12866, 3(f)(4)). Accordingly, EPA submitted this action to 
Deliberative draft – do not cite or distribute Page 149 

1 the Office of Management and Budget (OMB) for review under EO 12866 and any changes 

2 made in response to OMB recommendations have been documented in the docket for this action. 

3 

4 B. Paperwork Reduction Act 

5 

6 The information collection requirements in this proposed rule have been submitted for approval 

7 to the Office of Management and Budget (OMB) under the Paperwork Reduction Act, 44 U.S.C. 

8 3501 et seq. The Information Collection Request (ICR) document prepared by EPA has been 

9 assigned EPA ICR number 2309.01. 

10 The information collected as a result of this proposed rule will allow EPA and State permitting 

11 authorities to review geologic information about a proposed GS site to evaluate its suitability for 

12 safe and effective GS. It also allows the Agency to verify throughout the life of the injection 

13 project that UIC protective requirements are in place and that USDWs are protected. The 

14 Paperwork Reduction Act requires EPA to estimate the burden on owners or operators of CO2

15 GS wells, and States, Territories, and Tribes with primacy. Burden is defined at 5 CFR 

16 1320.3(b). 

17 For GS well operators applying for permits, this burden includes the time, effort, and financial 

18 resources needed to collect information to furnish EPA with the following information: 

19 − UIC permit applications and information to support the site characterization, such as 

20 maps and cross sections, information on the geologic structure, hydrogeologic properties, 

21 and baseline geochemical data on the proposed site. 

22 − AoR and corrective action plan. 

23 − Testing and monitoring plan. 
Deliberative draft – do not cite or distribute Page 150 

1 − Well plugging and post-injection site care plans. 

2 − Emergency and remedial response plans. 

3 − Reports of well logs and tests performed during well construction. 

4 − Periodic updates to the AoR models and corrective action status. 

5 − Demonstration of financial responsibility and periodic updates. 

6 − Periodic reports of monitoring and testing. 

7 − Reports of post-injection monitoring. 

8 − Non-endangerment demonstrations and the conclusion of all post-injection site care. 

9 For the first 3 years after publication of the final rule in the Federal Register, the major 

10 information requirements apply to operators of GS wells that are submitting an application for 

11 the construction of a CO2 GS well (or seeking a Class VI permit for an existing well) or 

12 monitoring and MIT data during the operation of the GS project. The collection requirements 

13 are mandatory under the SDWA (42 U.S.C. 300h et seq.). Calculation of the information 

14 collection burden and costs associated with today’s proposal can be found in the Information 

15 Collection Request for the National Underground Injection Control Regulations: Minimum 

16 Federal Requirements for Class VI Injection Wells for the Geologic Sequestration of Carbon 

17 Dioxide (USEPA 2008x), available through www.regulations.gov under Docket ID EPA-HQ18 OW-2008-0390. 

19 As shown in Table VIII-1, the total burden associated with the proposed rule over the 3 years 

20 following promulgation is 68,378 hours, or an average of 22,792 hours per year. The total cost 

21 over this period is $7.7 million, or an average of $2.6 million per year. The average burden per 

22 response for each activity that requires a collection of information is 172 hours; the average cost 

23 per response is $19,460. 
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1 An agency may not conduct or sponsor, and a person is not required to respond to, a collection of 

2 information request unless it displays a currently valid OMB control number. The OMB control 

3 numbers for EPA's regulations in 40 CFR are listed in 40 CFR Part 9. 

4 To comment on the Agency's need for this information, the accuracy of the provided burden 

5 estimates, and any suggested methods for minimizing respondent burden, EPA has established a 

6 public docket for this proposed rule under Docket ID number EPA-HQ-OW-2008-0390. Submit 

7 any comments related to the ICR to EPA and OMB. See ADDRESSES section at the beginning 

8 of this notice for where to submit comments to EPA. Send comments to OMB at the Office of 

9 Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street, NW, 

10 Washington, DC 20503, Attention: Desk Office for EPA. Since OMB is required to make a 

11 decision concerning the ICR between 30 and 60 days after [INSERT DATE OF PUBLICATION 

12 IN THE FEDERAL REGISTER], a comment to OMB is best assured of having its full effect if 

13 OMB receives it by [INSERT DATE 30 DAYS AFTER PUBLICATION IN THE FEDERAL 

14 REGISTER]. The final rule will respond to any OMB or public comments on the information 

15 collection requirements contained in this proposal. 
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1 Table VIII-1 Annual, Total, and Annual Average Burden Hours and Costs for the 

2 Proposed Rule Information Collection Request 3-Year Approval Period 

3 

Year 1 Year 2 Year 3 Total Annual Average

Burden (in hours) 24,215.9 20,743.4 20,908.9 68,378.2 22,792.7 

Respondents 26.5 30.4 32.08 53.4 29.6 

Responses 137.4 119.4 135.4 397.3 132.4

Costs ($) 3,430,215 $ 2,505,871 $ 2,780,984 $ 7,732,028 $ 2,577,343 $ 

Labor ($) 1,224,535 $ 979,728 $ 991,202 $ 3,376,495 $ 1,125,498 $ 

Non-Labor ($) 2,205,680 $ 1,526,143 $ 1,789,782 $ 4,321,956 $ 1,440,652 $ 

Burden per Response 176.2 173.7 154.4 172.1 172.1

Cost per Response 24,958 $ 20,980 $ 20,533 $ 19,460 $ 19,460 $ 

Burden per Respondent 914.5 683.2 651.8 1,279.5 769.0 

Cost per Respondent 129,540 $ 82,539 $ 86,689 $ 144,686 $ 86,955 $ 

Burden (in hours) 5,215.5 2,142.0 2,276.5 12,144.0 4,048.0 

Respondents 3.0 4.0 5.0 5.0 4.0 

Responses 63.0 54.0 65.0 187.0 62.3 

Costs ($) 2,592,013 $ 1,685,246 $ 1,958,994 $ 5,251,211 $ 1,750,404 $ 

Labor ($) 386,333 $ 159,103 $ 169,212 $ 895,678 $ 298,559 $ 

Non-Labor ($) 2,205,680 $ 1,526,143 $ 1,789,782 $ 4,321,956 $ 1,440,652 $ 

Avg. Burden per Response 82.8 39.7 35.0 64.9 64.9

Avg. Cost per Response 41,143 $ 31,208 $ 30,138 $ 28,081 $ 28,081 $ 

Avg. Burden per Respondent 1,738.5 535.5 455.3 2428.8 1012.0

Avg. Cost per Respondent 864,004 $ 421,312 $ 391,799 $ 1,050,242 $ 437,601 $ 

Burden (in hours) 13,510.6 13,223.3 13,245.6 39,979.4 13,326.5 

Respondents 12.48 15.36 16.08 37.4 14.6

Responses 38.4 31.9 35.5 105.8 35.3

Costs ($) 569,683 $ 557,570 $ 558,511 $ 1,685,763 $ 561,921 $ 

Labor ($) 569,683 $ 557,570 $ 558,511 $ 1,685,763 $ 561,921 $ 

Non Labor ($) - $ - $ - $ - $ - $ 

Burden per Response 351.8 414.3 372.9 1139.0 379.7

Cost per Response 14,835 $ 17,468 $ 15,724 $ 48,027 $ 16,009 $ 

Burden per Respondent 1,082.6 860.9 823.7 2,767.2 922.4 

Cost per Respondent 45,648 $ 36,300 $ 34,733 $ 116,681 $ 38,894 $ 

Burden (in hours) 5489.8 5378.1 5386.8 16254.8 5418.3

Respondents 11.0 11.0 11.0 11.0 11.0

Responses 36.0 33.5 34.9 104.5 34.8

Costs ($) 268,519 $ 263,055 $ 263,479 $ 795,053 $ 265,018 $ 

Labor ($) 268,519 $ 263,055 $ 263,479 $ 795,053 $ 265,018 $ 

Non-Labor Cost ($) - $ - $ - $ - $ - $ 

Burden per Response 152.3 160.4 154.3 155.6 155.6

Cost per Response 7,451 $ 7,848 $ 7,545 $ 7,610 $ 7,610 $ 

Burden per Respondent 499.1 488.9 489.7 1477.7 492.6

Cost per Respondent 24,411 $ 23,914 $ 23,953 $ 72,278 $ 24,093 $ 

Note: Numbers may not appear to add due to rounding.

DI Programs/EPA Headquarters

Operators/Owners

Primacy Agencies

Total (Owners/Operators, Primacy Agencies, and DI Programs/EPA Headquarters)

4 

5 

Comment [A1]: I would recommend 

removing this table since it is included in 

the full ICR, as cited above. However, 

this is at the program’s discretion 
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1 C. Regulatory Flexibility Act (RFA) 

2 

3 The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a regulatory 

4 flexibility analysis of any rule subject to notice and comment rulemaking requirements under the 

5 Administrative Procedure Act or any other statute unless the agency certifies that the rule will 

6 not have a significant economic impact on a substantial number of small entities. Small entities 

7 include small businesses, small organizations, and small governmental jurisdictions. For 

8 purposes of assessing the impacts of today's rule on small entities, small entity is defined as: (1) 

9 a small business as defined by the Small Business Administration’s (SBA) regulations at 13 CFR 

10 121.201; (2) a small governmental jurisdiction that is a government of a city, county, town, 

11 school district or special district with a population of less than 50,000; and (3) a small 

12 organization that is any not-for-profit enterprise which is independently owned and operated and 

13 is not dominant in its field. 

14 

15 After considering the economic impacts of today’s proposed rule on small entities, I certify that 

16 this action will not have a significant economic impact on a substantial number of small entities. 

17 This proposed rule will not impose any requirements on small entities. Sequestering CO2 via 

18 injection wells is a voluntary action that would only be undertaken by a small entity if it were in 

19 its interest compared to other alternatives it may have. GS of CO2 is still a scientifically complex 

20 activity, the cost of which is anticipated to be prohibitive to small entities. Therefore it is 

21 anticipated small entities would not elect to sequester CO2 via injection wells. We continue to be 

22 interested in the potential impacts of the proposed rule on small entities and welcome comments 

23 on issues related to such impacts. 
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1 D. Unfunded Mandates Reform Act (UMRA)

2 Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), P.L. 104-4, establishes 

3 requirements for Federal agencies to assess the effects of their regulatory actions on State, local, 

4 and tribal governments and the private sector. Under section 202 of UMRA, EPA generally must 

5 prepare a written statement, including a cost-benefit analysis, for proposed and final rules with 

6 "Federal mandates" that may result in expenditures to State, local, and tribal governments, in the 

7 aggregate, or to the private sector, of $100 million or more in any one year. Before promulgating 

8 an EPA regulation for which a written statement is needed, section 205 of UMRA generally 

9 requires EPA to identify and consider a reasonable number of regulatory alternatives and adopt 

10 the least costly, most cost-effective or least burdensome alternative that achieves the objectives 

11 of the rule. The provisions of section 205 do not apply when they are inconsistent with 

12 applicable law. Moreover, section 205 allows EPA to adopt an alternative other than the least 

13 costly, most cost-effective or least burdensome alternative if the Administrator publishes with 

14 the final rule an explanation why that alternative was not adopted. Before EPA establishes any 

15 regulatory requirements that may significantly or uniquely affect small governments, including 

16 tribal governments, it must have developed under section 203 of UMRA a small government 

17 agency plan. The plan must provide for notifying potentially affected small governments, 

18 enabling officials of affected small governments to have meaningful and timely input in the 

19 development of EPA regulatory proposals with significant Federal intergovernmental mandates, 

20 and informing, educating, and advising small governments on compliance with the regulatory 

21 requirements. 

22 
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1 EPA has determined that this proposed rule does not contain a Federal mandate that may result in 

2 expenditures of $100 million or more for State, local, and tribal governments, in the aggregate, 

3 or the private sector in any one year. Expenditures associated with compliance, defined as the 

4 incremental costs beyond the existing regulations under which a CO2 GS well could be permitted 

5 and deployed, will not surpass $100 million in the aggregate in any year. Thus, today's 

6 proposed rule is not subject to the requirements of sections 202 and 205 of UMRA. 

7 

8 EPA has determined that this proposed rule contains no regulatory requirements that might 

9 significantly or uniquely affect small governments. Regulated entities are anticipated to be 

10 private entities, not governments. 

11 

12 E. Executive Order 13132: Federalism 

13 

14 Executive Order 13132, entitled “Federalism” (64 FR 43255, August 10, 1999), requires EPA to 

15 develop an accountable process to ensure “meaningful and timely input by State and local 

16 officials in the development of regulatory policies that have Federalism implications.” “Policies 

17 that have Federalism implications” is defined in the Executive Order to include regulations that 

18 have “substantial direct effects on the States, on the relationship between the national 

19 government and the States, or on the distribution of power and responsibilities among the various 

20 levels of government.” 

21 

22 This proposed rule does not have federalism implications. It will not have substantial direct 

23 effects on the States, on the relationship between the national government and the States, or on 
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1 the distribution of power and responsibilities among the various levels of government, as 

2 specified in Executive Order 13132. Currently, States may gain the authority to regulate a full or 

3 partial UIC program in their State by applying for primacy. States with primacy must develop a 

4 program incorporating all new Federal requirements for Class VI wells if they wish to regulate 

5 CO2 GS, and all programs will be subject to EPA approval. Since application for primacy is a 

6 voluntary process, the addition of this proposed regulation to the UIC regulations should not 

7 significantly impact States or their right to primacy for other classes of wells. If States do not 

8 develop a program for Class VI wells, EPA will oversee CO2 GS in those States. Thus, 

9 Executive Order 13132 does not apply to this proposal. 

10 

11 Although section 6 of Executive Order 13132 does not apply to this rule, EPA did consult with 

12 State and local officials early in the process of in developing this proposed rule to permit them to 

13 have meaningful and timely input in its development. EPA sent letters with background about 

14 the rulemaking and an invitation for consultation to the National Governors’ Association, the 

15 National Conference of State Legislatures, the Council of State Governments, the National 

16 League of Cities, the U.S. Conference of Mayors, the National Association of Counties, the 

17 International City/County Management Association, the National Association of Towns and 

18 Townships, and the County Executives of America. EPA held a meeting with interested parties 

19 from these organizations in April 2008. 

20 

21 In the spirit of Executive Order 13132, and consistent with EPA policy to promote 

22 communications between EPA and State and local governments, EPA specifically solicits 

23 comment on this proposed rule from State and local officials. A summary of the concerns raised 
Deliberative draft – do not cite or distribute Page 157 

1 during that consultation and EPA’s response to those concerns will be provided in the preamble 

2 to the final rule. 

3 

4 F. Executive Order 13175: Consultation and Coordination with Indian Tribal 

5 Governments 

6 

7 Executive Order 13175, entitled “Consultation and Coordination with Indian Tribal 

8 Governments” (65 FR 67249, November 9, 2000), requires EPA to develop an accountable 

9 process to ensure “meaningful and timely input by tribal officials in the development of 

10 regulatory policies that have tribal implications.” This proposed rule does not have tribal 

11 implications as specified in Executive Order 13175. Currently, no Indian Tribes have primacy. 

12 However, Indian Tribes may acquire authority to regulate a partial or full UIC program in lands 

13 under their jurisdiction by applying for and gaining primacy from the Agency. Tribes seeking 

14 primacy must develop requirements at least as stringent as the new proposed Federal minimum 

15 requirements for Class VI wells if they wish to regulate CO2 GS, and all programs will be subject 

16 to EPA approval. If Tribes do not develop a program for Class VI wells, EPA will directly 

17 implement Class VI CO2 GS on tribal lands. The application for primacy is a voluntary process. 

18 Furthermore, this proposal clarifies regulatory ambiguity rather than placing new requirements 

19 on tribal or other governmental entities. Therefore, this proposed rule should not change the 

20 Tribal-Federal relationship and should not significantly impact Tribes. Thus, Executive Order 

21 13175 does not apply to this proposed rule. 

22 
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1 Although Executive Order 13175 does not apply to this proposed rule, EPA consulted with tribal 

2 officials in developing this proposed rule. EPA sent letters with background about the 

3 rulemaking and an invitation for consultation to all of the federally recognized Indian Tribes. 

4 EPA held a meeting with interested parties from Tribal governments in April 2008. 

5 

6 EPA specifically solicits additional comment on this proposed rule from tribal officials. 

7 

8 G. Executive Order 13045: Protection of Children from Environmental Health Risks and 

9 Safety Risks 

10 

11 This action is not subject to EO 13045 (62 F.R. 19885, April 23, 1997) because it is not 

12 economically significant as defined in EO 12866, and because the Agency does not 

13 believe the environmental health or safety risks addressed by this action present a 

14 disproportionate risk to children. Moreover, this proposed rule will not require that CO2

15 GS be undertaken; but does require that if it is undertaken, operators will conduct the 

16 activity in such a way as to protect USDWs from endangerment caused by CO2. This 

17 action’s health and risk assessments are contained in CO2 GS Risk Assessment Document 

18 (USEPA, 2008x).

19 

20 The public is invited to submit comments or identify peer-reviewed studies and data that assess 

21 the effects of early life exposure to changes in drinking water quality that may be caused by 

22 geologic sequestration of carbon dioxide. 

23 
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1 H. Executive Order 13211: Actions that Significantly Affect Energy Supply, Distribution, 

2 or Use 

3 This rule is not a “significant energy action” as defined in Executive Order 13211, “Actions 

4 Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” (66 FR 

5 28355 (May 22, 2001)) because it is not likely to have a significant adverse effect on the supply, 

6 distribution, or use of energy. 

7 

8 The higher degree of regulatory certainty and clarity in the permitting process, in fact, will likely 

9 have a positive effect on the energy sector. Specifically, if climate change legislation that 

10 imposes caps or taxes on CO2 emissions is passed in the future, energy generation firms and 

11 other CO2 producing industries will have an economic incentive to reduce emissions, and this 

12 rule will provide regulatory certainty in determining how to maximize operations (for example, 

13 by increasing production while staying within the emissions cap or avoiding some carbon taxes). 

14 The proposed rule may allow some firms to extend the life of their existing capital investment in 

15 plant machinery or plant processes. By providing an economically feasible way for firms to 

16 continue fossil fuel use, the proposed rule allows the energy firms in the United States to 

17 maintain or increase production levels in the most efficient manner.

18 

19 I. National Technology Transfer and Advancement Act 

20 

21 Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (“NTTAA”), 

22 Public Law No. 104-113, 12(d) (15 U.S.C. 272 note) directs EPA to use voluntary consensus 

23 standards in its regulatory activities unless to do so would be inconsistent with applicable law or 

24 otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials 
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1 specifications, test methods, sampling procedures, and business practices) that are developed or 

2 adopted by voluntary consensus standards bodies. NTTAA directs EPA to provide Congress, 

3 through OMB, explanations when the Agency decides not to use available and applicable 

4 voluntary consensus standards. 

5 

6 The proposed rulemaking involves technical standards. Therefore, the Agency conducted a 

7 search to identify potentially applicable voluntary consensus standards. However, we identified 

8 no such standards, and none were brought to our attention. Thus the Agency decided to convene 

9 numerous workshops (discussed further in Chapter 2 of the Cost Analysis for the GS Rule, 

10 included in the docket) to develop standards based on current information available from experts 

11 in industry, government, and non-governmental organizations. EPA proposes to use a 

12 combination of technologies and standard practices that it estimates will provide the necessary 

13 protection to USDWs with regard to site characterization, construction, operation, monitoring, 

14 closure, and post-closure requirements for CO2 GS wells, without placing undue burden on well 

15 operators. These methods are listed in Chapter 2 of the Cost Analysis for the GS Rule and 

16 described in further detail in the CO2 GS Technology & Cost Document (USEPA, 2008x) 

17 developed in support of this proposed rule. 

18 

19 EPA welcomes comments on this aspect of the proposed rulemaking and, specifically, invites the 

20 public to identify potentially-applicable voluntary consensus standards and to explain why such 

21 standards should be used in this regulation. 

22 
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1 J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority 

2 Populations and Low-Income Populations 

3 

4 Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes federal executive policy 

5 on environmental justice. Its main provision directs federal agencies, to the greatest extent 

6 practicable and permitted by law, to make environmental justice part of their mission by 

7 identifying and addressing as appropriate any disproportionately high and adverse human health 

8 or environmental effects of their programs, policies, and activities on minority populations and 

9 low-income populations in the United States. 

10 

11 EPA has determined that this proposed rule will not have disproportionately high and adverse 

12 human health or environmental effects on minority or low-income populations because it 

13 increases the level of environmental protection for all affected populations without having any 

14 disproportionately high and adverse human health or environmental effects on any population, 

15 including any minority or low-income population. 

16 

17 Existing electric power generation plants that burn fossil fuels may be more prevalent in areas 

18 with higher percentages of people who are minorities or have lower incomes on average, but it is 

19 hard to predict where new plants with CCS will be built. This proposed rule would not require 

20 that CO2 GS be undertaken; but does require that if it is undertaken, operators will conduct the 

21 activity in such a way as to protect USDWs from endangerment caused by CO2. Additionally, 

22 promulgation of this proposed rule will ensure that all areas of the United States are subject to 

23 the same minimum Federal requirements for protection of USDWs from endangerment from GS. 
Deliberative draft – do not cite or distribute Page 162 

1 Additional detail regarding the potential risk of the proposed rule is presented in the CO2 GS 

2 Risk Assessment Document (USEPA, 2008x). 

3 

4 EPA believes that UIC permit writers should consider the impact of GS on any communities in 

5 the geographic areas of GS sites. Permit writers can ask specific questions to specifically address 

6 any potentially different impacts on minority and/or low-income communities. Examples 

7 include: In reviewing the application or Notice of Intent (NOI) for a GS permit, is there any 

8 indication that a minority and/or low-income community would be adversely affected? Are there 

9 measures that should be undertaken to understand minority and/or low-income community 

10 concerns during the permit drafting and development phase, including the development of permit 

11 conditions? If an environmental justice issue is identified, does the program go beyond the 

12 requirement to advertise the notice of application and opportunity for a hearing in a newspaper of 

13 general circulation in each region in which the proposed project would be constructed to reach 

14 out to minority and/or low-income populations? 

15 

16 EPA seeks comment on environmental justice considerations for GS permit writers. 

17 

18 

19 

20 

21 

22 

23 
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1 IX. References 

2 

3 Apps, J.A. 2006. A Review of Hazardous Chemical Species Associated with CO2 Capture from 

4 Coal-Fired Power Plants and Their Potential Fate in CO2 Geologic Storage. February 23, 2006. 

5 Lawrence Berkeley National Laboratory. Paper LBNL-59731. 

6 http://repositories.cdlib.org/lbnl/LBNL-59731 

7 

8 Benson, S.M., R. Hepple, J. Apps, C.F. Tsang, and M. Lippmann. 2002. Lessons Learned from 

9 Natural and Industrial Analogues for Storage of Carbon Dioxide in Deep Geolgical Formations. 

10 Lawrence Berkeley National Laboratory. Paper LBNL-51170. 

11 

12 Benson, S.M. and L. Myer. 2002. Monitoring to Ensure Safe and Effective Geologic 

13 Sequestration of Carbon Dioxide. IPCC Workshop for Carbon Capture and Storage 2002. 

14 Regina, Canada: IPCC. http://arch.rivm.nl/env/int/ipcc/ccs2002.html 

15 

16 Birkholzer, J.T., Q. Zhou, J. Rutqvist, P. Jordan, K. Zhang, C.F. Tsang. 2007. Research project 

17 on CO2 Geological Storage and groundwater resources: large-scale hydrogeological evaluation 

18 and impact on groundwater systems, Lawrence Berkeley National Laboratory Report, LBNL19 63544. 

20 

21 Brondel, D., R. Edwards, A. Hayman, D. Hill, S. Mehta, and T. Semerad. 1994. Corrosion in 

22 the Oil Industry. Oilfield Review. 6 (2): 4-18. April 1994. 

23 
Deliberative draft – do not cite or distribute Page 164 

1 Buller, A., O. Karstad, and G. de Koeijer. 2004. Carbon Dioxide Capture, Storage and 

2 Utilization. Statoil R&D Memoir series, Research & Technology Memoir No. 5. 

3 

4 California Energy Commission. 2007. Burton, E., R. Myhre, L. Myer, and K. Birkinshaw. 

5 Geologic Carbon Sequestration Strategies for California. Report to the Legislature. November, 

6 2007. CEC-500-2007-100-SF. 

7 

8 Christopher, C. and W. Crow. 2007. CO2 Capture Project: Wellbore Integrity Study. BP 

9 Houston. EPA Construction & MIT Workshops. March 14, 2007. 

10 http://www.epa.gov/ogwdw000/uic/pdfs/page_uic_albuquerque_presentations.pdf

11 

12 Christopher, C., W. Crow, K. Dodds, I. Wright and B. Williams. 2008. Risk Profile of a CO2 

13 Geological Storage Project: Wells. BP Alternative Energy. February 19, 2008. 

14 

15 DOE. 2007a. U.S. Department of Energy, Office of Fossil Energy, National Energy Technology 

16 Laboratory. Carbon Sequestration Atlas of the U.S. and Canada. March 2007. 

17 

18 DOE. 2007b. U.S. Department of Energy, Office of Fossil Energy, National Energy 

19 Technology Laboratory. Carbon Sequestration Technology Roadmap and Program Plan. April, 

20 2007. 

21 

22 Dooley, J.J., R.T. Dahowski, C.L. Davidson, M.A. Wise, N. Gupta, S.H. Kim, and E.L. Malone. 

23 2006. Carbon Dioxide Capture and Geologic Storage: A Core Element of a Global Energy 
Deliberative draft – do not cite or distribute Page 165 

1 Technology Strategy to Address Climate Change. A Technology Report from the Second Phase 

2 of the Global Energy Technology Strategy Program. April, 2006. 

3 

4 Doughty, C. 2007. Modeling geologic storage of carbon dioxide: Comparison of Non5 Hysteretic and Hysteretic Characteristic Curves. Energy Conversion and Management. 48, 

6 1768-1781. 

7 

8 Duiguid, A., M. Radonjic, R. Bruant, T. Mandecki, G. Scherer, and M. Celia. 2004. The Effect 

9 of CO2 Sequestration on Oil Well Cements. Greenhouse Gas Technologies Conference (GHGT10 7). Vancouver, Canada. September 5-9, 2004. 

11 

12 Flett, M., R. Gurton, and G. Weir. 2007. Heterogeneous saline formations for carbon dioxide 

13 disposal: impact of varying heterogeneity on containment and trapping. 

14 

15 Garner J., K. Martin, D. McCalvin, and D. McDaniel. 2002. At the Ready: Subsurface Safety 

16 Valves. Oilfield Review. Winter 2002/2003. 

17 http://www.slb.com/media/services/resources/oilfieldreview/ors02/win02/p52_64.pdf

18 

19 GEO-SEQ. 2004. GEO-SEQ Best Practices Manual. Geologic Carbon Dioxide Sequestration: 

20 Site Evaluation to Implementation. Lawrence Berkeley National Laboratory. Paper LBNL21 56623. http://www.netl.doe.gov/technologies/carbon_seq/refshelf/GEO-SEQ_BestPract_Rev1-

22 1.pdf

23 
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1 Harris, J.M. and R.T. Langan. 2001. Crosswell Seismic Profiling: Principle to Applications. 

2 Search and Discovery Article #40030. 

3 http://www.searchanddiscovery.net/documents/geophysical/harris_langan/index.htm

4 

5 IEA. 2005. IEA GHG Weyburn CO2 Monitoring and Storage Project. IEA Greenhouse Gas 

6 R&D Programme. July 2005. http://www.ieagreen.org.uk/glossies/weyburn.pdf 

7 

8 IOGCC. 2007. Storage of Carbon Dioxide in Geologic Structures; A Legal and Regulatory 

9 Guide for States and Provinces. Prepared by the Interstate Oil and Gas Compact Commission. 

10 September 25, 2007. 

11 

12 IPCC. 2005. IPCC Special Report on Carbon Dioxide Capture and Storage. Prepared by 

13 Working Group III of the Intergovernmental Panel on Climate Change. Metz, B., O. Davidson, 

14 H. C. de Coninck, M. Loos, and L. A. Meyer (eds.). New York: Cambridge University Press. 

15 

16 IPCC. 2007. IPCC Fourth Assessment Report: Climate Change 2007. Intergovernmental Panel 

17 on Climate Change. 

18 

19 Juhlin, C., C. Cosma, A. Förster, R. Giese, N. Johojuntti, H. Kazemeini, B. Norden, and K. Zink20 Jørgensen. 2007. Baseline 3D Seismic Imaging for the CO2-SINK Project in the Ketzin Area, 

21 Germany. http://www.co2sink.org/publications/GHGT8_v2.pdf

22 
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1 Kirkendall, B. and J. Roberts. 2004. Electromagnetic Imaging of CO2 Sequestration at an 

2 Enhanced Oil Recovery Site. U.S. Department of Energy. University of California, Lawrence 

3 Livermore National Laboratory. February 2004. 

4 http://www.netl.doe.gov/publications/proceedings/01/carbon_seq/6a3.pdf

5 

6 Lewicki, J.L., J.T. Birkholzer, C.F. Tsang. 2006. Natural and Industrial Analogues for Leakage 

7 of CO2 from Storage Reservoirs – Identification of Features, Events, and Processes and Lessons 

8 Learned. Journal of Environmental Geology. 52(3)457-467. 

9 

10 Li, Q., Z. Wu, Y. Bai, X. Yin, and X. Li. 2006. Thermo-hydro-mechanical Modeling of CO2 

11 Sequestration System Around Fault Environment. Pure and Applied Geophysics. 163(11-

12 12)2585–2593. December 2006. 

13 

14 Maina, J. N. 1998. The Gas Exchangers: Structure, Function, and Evolution of the Respiratory 

15 Processes. Berlin, Germany: Springer. 

16 

17 McGee, Kenneth A. and Terrence M. Gerlach. 1998. “Annual cycle of magmatic CO2 in a tree18 kill soil at Mammoth Mountain, California: implications for soil acidification.” Geology 26.5 

19 (1998): 463-66. 

20 

21 Meyer, J.P. 2007. Summary of Carbon Dioxide Enhanced Oil Recovery (CO2EOR) Injection 

22 Well Technology. Prepared for the American Petroleum Institute. 

23 http://www.api.org/aboutoilgas/sectors/explore/upload/07APICO2EORReportFinal.pdf 
Deliberative draft – do not cite or distribute Page 168 

1 

2 Miles, N.L., K.J. Davis, and J.C. Wyngaard. 2005. Detecting Leaks from Belowground CO2 

3 Reservoirs Using Eddy Covariance. In Carbon Dioxide Capture for Storage in Deep Geologic 

4 Formations. Volume 2. D.C. Thomas and S.M. Benson (eds.). 

5 

6 Newmark, R., 2003. Electrical Resistance Tomography Field Trials to Image CO2 

7 Sequestration. American Geophysical Union Fall Meeting, abstract #H21A-08. 

8 

9 Nicot, J.P. and S.D. Hovorka. 2008. Role of Geochemical Monitoring in Geologic 

10 Sequestration. Presented at Joint GWPC/EPA CO2 MMV meeting, New Orleans, January 16, 

11 2008. 

12 

13 Nimz, G.J. and G.B. Hudson, 2005. The Use of Noble Gas Isotopes for Monitoring Leakage of 

14 Geologically Stored CO2. In Carbon Dioxide Capture for Storage in Deep Geologic Formations. 

15 Volume 2. D.C. Thomas and S.M. Benson (eds.). 

16 

17 Nooner, S.L., M.A. Zumberge, O. Eiken, T. Stenvold, and G.S. Sasagawa. 2003. Seafloor 

18 Micro-gravity Survey of the Sleipner CO2 Sequestration Site. American Geophysical Union, 

19 Fall Meeting, abstract # GC31A-01. 

20 

21 Norwegian Oil Industry Association. 2001. Recommended Guidelines for the Application of 

22 IEC 61508 and IEC 61511 in the Petroleum Activities on the Norwegian Continental Shelf. 
Deliberative draft – do not cite or distribute Page 169 

1 NRC, 2007. National Research Council Of The National Academies. Models in Environmental 

2 Regulatory Decision Making. Washington, D.C.: The National Academies Press. 

3 

4 Obi, E.I., and M.J. Blunt. 2006. Streamline-based Simulation of Carbon Dioxide Storage in a 

5 North Sea Aquifer. Water Resources Research, 42 W03414. 

6 

7 Oldenburg, C.M. 2007. Joule-Thomson Cooling Due to CO2 Injection into Natural Gas 

8 Reservoirs. Energy Conversion and Management, 48 (6):1808-1815. pg. 45. 

9 OMB, 2003. Office of Management and Budget. Economic Analysis of Federal Regulations. 

10 OMB Circular A-4, September 17. 

11 

12 Pickles, W.L. and W.A. Cover. 2005. Hyperspectral Geobotanical Remote Sensing for CO2 

13 Storage Monitoring. In Carbon Dioxide Capture for Storage in Deep Geologic Formations. 

14 Volume 2. D.C. Thomas and S.M. Benson (eds.). 

15 

16 Rutqvist, J., J. Birkholzer, F. Cappa, and C.F. Tsang. 2007. Estimating Maximum Sustainable 

17 Injection Pressure During Geological Sequestration of CO2 Using Coupled Fluid Flow and 

18 Geomechanical Fault-slip Analysis. Energy Conversion and Management. 48(6):1798–1807. 

19 January, 2007. 

20 

21 W. N. Sams, W, G. Bromhal, S. Jikich, T. Ertekin, and D.H. Smith. 2005. Field-Project Designs 

22 for Carbon Dioxide Sequestration and Enhanced Coalbed Methane Production. Energy & Fuels 

23 2005, 19, 2287-2297. 
Deliberative draft – do not cite or distribute Page 170 

1 

2 Streit, J.E. and R.R. Hillis. 2004. Estimating Fault Stability and Sustainable Fluid Pressures for 

3 Underground Storage of CO2 in Porous Rock. Energy. 29(9-10):1445–1456. July – August 2004. 

4 

5 Streit, J. E. and A.F. Siggins. 2004. Predicting, Monitoring and Controlling Geomechanical 

6 Effects of CO2 Injection. 7th International Conference on Greenhouse Gas Control 

7 Technologies (GHGT-7). September 2004. Vancouver, Canada. 

8 

9 Turley, C., et al. 2006. Reviewing the Impact of Increased Atmospheric CO2 on Oceanic pH and 

10 the Marine Ecosystem, Avoiding Dangerous Climate Change (2006). Cambridge: Cambridge 

11 University Press, 65-70. 

12 

13 USEPA 1990. Federal Financial Responsibility Demonstrations for Owners and Operators of 

14 Class II Oil-and Gas-Related Injection Wells. EPA 570/9-90-003. May. EPA 2008d. 

15 

16 USEPA 2008x. Climate Change – Climate Economics. Economic Analyses. Last updated May 

17 7, 2008. http://www.epa.gov/climatechange/economics/economicanalyses.html

18 

19 USEPA 2008x. CO2 GS Risk Assessment Document. [Finalize when cite-able] 

20 

21 USEPA 2008x. CO2 Sequestration Baseline Document. [Finalize when cite-able] 

22 
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1 USEPA 2008x. Information Collection Request for the National Underground Injection Control 

2 Regulations. [Finalize when cite-able] 

3 

4 USEPA 2008x. CO2 GS Technology & Cost Document. [Finalize when cite-able] 

5 

6 USEPA. 2007. Using the Class V Experimental Technology Well Classification for Pilot 

7 Carbon Geologic Sequestration Projects – UIC Program Guidance (UICPG # 83). March 2007. 

8 

9 USEPA. 2008a. Computational Modeling of Underground Injection of Carbon Dioxide for 

10 Determination of Area-of-review and Potential Risk to USDWs. [Finalize when cite-able] 

11 

12 USEPA. 2008b. Technical Support Document: Vulnerability Evaluation Framework. [Finalize 

13 when cite-able] 

14 

15 Vodnik, D. et al. 2006. “Small-scale spatial variation in soil CO2 concentration in a natural 

16 carbon dioxide spring and some related plant responses.” Geoderma 133 (2006): 309-19. 

17 

18 Westermark, R. V.; Dauben, D.; Robinowitz, S. 2004. “Enhanced Oil Recovery with Horizontal 

19 Waterflooding, Osage County, Oklahoma”, SPE 89373, presented at the 2004 SPE/DOE 

20 Fourteenth Symposium on Improved Oil Recovery, Tulsa, OK, April 17-21, 2004. 

21 
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1 Wilson, E.J. 2004. Managing the Risks of Geologic Carbon Sequestration: A Regulatory and 

2 Legal Analysis. Department of Engineering and Public Policy. Carnegie Mellon University. 

3 October, 2004. 

4 

5 WRI. 2007. J. Logan, J. Venezia, and K. Larsen. Issue Brief: Opportunities and Challenges for 

6 Carbon Capture and Sequestration. WRI Issue Brief, No. 1. World Resources Institute. October, 

7 2007. Washington, DC. 
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1 [Minimum Federal Requirements Under the Underground Injection Control (UIC) 

2 Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells, Page 173 of 211] 

3 

4 

5 List of Subjects in 40 CFR Part 146 

6 Environmental protection, Hazardous waste, Indian lands, Reporting and record keeping 

7 requirements, Water supply. 

8 

9 

10 Dated: 

11 

12 

13 

14 Stephen L. Johnson, 

15 

16 Administrator. 

17 

18 

19 For the reasons set forth in the preamble, title 40 chapter I of the Code of Federal Regulations is 

20 amended as follows:

21 

22 

23 
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1 PART 144—UNDERGROUND INJECTION CONTROL PROGRAM

2 

3 1. The authority citation for part 144 continues to read as follows: 

4 Authority: 42 U.S.C. 300f et seq.; Resource Conservation and Recovery Act, 42 U.S.C. 

5 6901 et seq.

6 

7 Subpart A —General Provisions 

8 

9 2. Section 144.1 is amended as follows: 

10 a. Adding new paragraph (f)(1)(viii); and 

11 b. Revising the first two sentences in paragraph (g) as follows. 

12 

13 §144.1 Purpose and scope of part 144. 

14 * * * * * 

15 (f) *** 

16 (1) *** 

17 (viii) Subpart H of this part sets forth requirements for owners or operators of Class VI 

18 injection wells. 

19 (g) Scope of the permit or rule requirement. The UIC Permit Program regulates 

20 underground injections by six classes of wells (see definition of ‘‘well injection,’’ §144.3). The 

21 six classes of wells are set forth in §144.6. All owners or operators of these injection wells must 

22 be authorized either by permit or rule by the Director. *** 

23 
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1 3. Section 144.6 is amended as follows: 

2 a. Revising paragraph (e) to read as follows; and 

3 b. Adding new paragraph (f) to read as follows. 

4 

5 §144.6 Classification of wells. 

6 * * * * *

7 (e) Class V. Injection wells not included in Class I, II, III, IV, or VI. Specific types of 

8 Class V injection wells are described in §144.81. 

9 (f) Class VI. Wells used for geologic sequestration of carbon dioxide beneath the 

10 lowermost formation containing a USDW. 

11 

12 Subpart B —General Program Requirements 

13 

14 4. Revising paragraph §144.15 to read as follows. 

15 §144.15 Prohibition of non-experimental Class V wells for geologic sequestration. 

16 The construction, operation or maintenance of any non-experimental Class V geologic 

17 sequestration well is prohibited. 

18 

19 5. Adding new paragraph §144.18 to read as follows. 

20 §144.18 Requirements for Class VI wells. 

21 Owners or operators of Class VI wells must obtain a permit. Class VI wells are not 

22 authorized by rule to inject. 

23 
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1 Subpart D—Authorization by Permit 

2 

3 6. Revising the first two sentences in §144.36(a) to read as follows:

4 

5 §144.36 Duration of permits. 

6 (a) Permits for Class I and V wells shall be effective for a fixed term not to exceed 10 years. 

7 UIC Permits for Class II, III and VI wells shall be issued for a period up to the operating life of 

8 the facility. *** 

9 

10 7. Revising the second sentence in §144.39(a); and revising the second sentence in 

11 §144.39(a)(3) as follows. 

12 

13 §144.39 Modification or revocation and reissuance of permits. 

14 * * * * * 

15 (a) *** For Class I hazardous waste injection wells, Class II, Class III or Class VI wells 

16 the following may be causes for revocation and reissuance as well as modification; and for all 

17 other wells the following may be cause for revocation or reissuance as well as modification when 

18 the permittee requests or agrees. *** 

19 (3) *** Permits other than for Class I hazardous waste injection wells, Class II, Class III 

20 or Class VI wells may be modified during their terms for this cause only as follows: *** 

21 * * * * * 

22 

23 Subpart E—Permit Conditions 
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1 

2 8. Revising the first sentence in §144.51(q)(1) to read as follows; and revising the first sentence 

3 in §144.51(q)(2) as follows: 

4 

5 §144.51 Conditions applicable to all permits. 

6 * * * * * 

7 (q) *** 

8 (1) The owner or operator of a Class I, II, III or VI well permitted under this part shall 

9 establish mechanical integrity prior to commencing injection or on a schedule determined 

10 by the Director. Thereafter the owner or operator of Class I, II, and III wells must 

11 maintain mechanical integrity as defined in §146.8 and the owner or operator of Class VI 

12 wells must maintain mechanical integrity as defined in §146.89 of this chapter. *** 

13 

14 (2) When the Director determines that a Class I, II, III or VI well lacks mechanical 

15 integrity pursuant to §146.8 or §146.89 for Class VI of this chapter, he/she shall give 

16 written notice of his/her determination to the owner or operator. *** 

17 * * * * * 

18 9. Revising §144.52(a)(8) to read as follows: 

19 

20 §144.52 Establishing permit conditions. 

21 

22 (a) * * * * * 
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1 (8) Mechanical integrity. A permit for any Class I, II, III or VI well or injection project 

2 which lacks mechanical integrity shall include, and for any Class V well may include, a 

3 condition prohibiting injection operations until the permittee shows to the satisfaction of 

4 the Director under §146.08 or§146.89 for Class VI that the well has mechanical integrity. 

5 * * * * * 

6 

7 10. Revising the first sentence in §144.55(a) as follows: 

8 

9 §144.55 Corrective Action. 

10 

11 (a) Coverage. Applicants for Class I, II, (other than existing), III or VI injection well permits 

12 shall identify the location of all known wells within the injection well's area of review which 

13 penetrate the injection zone, or in the case of Class II wells operating over the fracture pressure 

14 of the injection formation, all known wells within the area of review penetrating formations 

15 affected by the increase in pressure. Applicants for Class VI shall perform corrective action as 

16 specified in §146.84.*** 

17 * * * * * 

18 

19 

20 Subpart G—Requirements for Owners and Operators of Class V Injection Wells 

21 

22 11. Revising the first sentence in §144.80(e) to read as follows; and adding §144.80(f) to read as 

23 follows. 
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1 

2 §144.80 What is a Class V injection well?

3 * * * * * 

4 (e) Class V. Injection wells not included in Class I, II, III, IV or VI. *** 

5 (f) Class VI. Wells used for geologic sequestration of carbon dioxide. 

6 

7 PART 146—UNDERGROUND INJECTION CONTROL PROGRAM: CRITERIA AND 

8 STANDARDS 

9 

10 12. The authority citation for part 146 continues to read as follows: 

11 Authority: 42 U.S.C. 300f et seq.; Resource Conservation and Recovery Act, 42 U.S.C. 

12 6901 et seq.

13 

14 13. Section 146.5 is amended as follows: 

15 a. Revising the first sentence in paragraph (e); and 

16 b. Adding paragraph (f). 

17 §146.5 Classification of injection wells. 

18 * * * * * 

19 (e) Class V. Injection wells not included in Class I, II, III, IV or VI. *** 

20 (f) Class VI. Wells used for geologic sequestration of carbon dioxide beneath the 

21 lowermost formation containing an underground source of drinking water (USDW). 

22 

23 14. Subpart H is added to read as follows: 
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1 Subpart H—Criteria and Standards Applicable to Class VI Wells 

2 Sec. 

3 146.81 Applicability. 

4 146.82 Required Class VI permit information. 

5 146.83 Minimum criteria for siting. 

6 146.84 Area of review and corrective action. 

7 146.85 Financial responsibility. 

8 146.86 Injection well construction requirements. 

9 146.87 Logging, sampling, and testing prior to injection well operation. 

10 146.88 Injection well operating requirements. 

11 146.89 Mechanical integrity. 

12 146.90 Testing and monitoring requirements. 

13 146.91 Reporting requirements. 

14 146.92 Injection well plugging.

15 146.93 Post-injection site care and closure. 

16 146.94 Emergency and remedial response. 

17 

18 Subpart H—Criteria and Standards Applicable to Class VI Wells 

19 §146.81 Applicability. 

20 (a) This subpart establishes criteria and standards for underground injection control programs to 

21 regulate Class VI carbon dioxide geologic sequestration injection wells. 
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1 (b) This subpart applies to wells used to inject carbon dioxide specifically for the purpose of 

2 geologic sequestration, i.e., the long-term containment of a gaseous, liquid or supercritical 

3 carbon dioxide stream in subsurface geologic formations. 

4 (c) This subpart applies to owners and operators of permit or rule-authorized Class I industrial, 

5 Class II, or Class V experimental carbon dioxide injection projects who seek to apply for a Class 

6 VI geologic sequestration permit for their well or wells. If the Director determines that USDWs 

7 will not be endangered, such wells are exempt, at the Director’s discretion, from the casing and 

8 cementing requirements at §§146.86(b) and 146.87(a)(1)–(3). 

9 (d) Definitions. The following definitions apply to this subpart. To the extent that these 

10 definitions conflict with those in §146.3 these definitions govern: 

11 Area of review means the region surrounding the geologic sequestration project that may 

12 be impacted by the injection activity. The area of review is based on computational 

13 modeling that accounts for the physical and chemical properties of all phases of the 

14 injected carbon dioxide stream. 

15 

16 Carbon dioxide plume means the underground extent, in three dimensions, of an injected 

17 carbon dioxide stream. 

18 

19 Carbon dioxide stream means carbon dioxide that has been captured from an emission 

20 source (e.g., a power plant), plus incidental associated substances derived from the source 

21 materials and the capture process, and any substances added to the stream to enable or 

22 improve the injection process. This subpart does not apply to any carbon dioxide stream 

23 that meets the definition of a hazardous waste under 40 CFR part 261. 
Deliberative draft – do not cite or distribute Page 182 

1 

2 Confining zone means a geologic formation, group of formations, or part of a formation 

3 stratigraphically overlying the injection zone that acts as a barrier to fluid movement. 

4 

5 Corrective action means the use of Director approved methods to assure that wells within 

6 the area of review do not serve as conduits for the movement of fluids into underground 

7 sources of drinking water (USDW). 

8 

9 Geologic sequestration means the long-term containment of a gaseous, liquid or 

10 supercritical carbon dioxide stream in subsurface geologic formations. This term does 

11 not apply to its capture or transport. 

12 

13 Geologic sequestration project means an injection well or wells used to emplace a carbon 

14 dioxide stream beneath the lowermost formation containing a USDW. It includes the 

15 subsurface three-dimensional extent of the carbon dioxide plume, associated pressure 

16 front, and displaced brine, as well as the surface area above that delineated region. 

17 

18 Injection zone means a geologic formation, group of formations, or part of a formation 

19 that is of sufficient areal extent, thickness, porosity, and permeability to receive carbon 

20 dioxide through a well or wells associated with a geologic sequestration project. 

21 
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1 Post-injection site care means appropriate monitoring and other actions (including 

2 corrective action) needed following cessation of injection to assure that USDWs are not 

3 endangered as required under §146.93. 

4 

5 Pressure front means the zone of elevated pressure that is created by the injection of 

6 carbon dioxide into the subsurface. For the purposes of this subpart, the pressure front of 

7 a carbon dioxide plume refers to a zone where there is a pressure differential sufficient to 

8 cause the movement of injected fluids or formation fluids into a USDW. 

9 

10 Transmissive fault or fracture means a fault or fracture that has sufficient permeability 

11 and vertical extent to allow fluids to move between formations. 

12 

13 §146.82 Required Class VI Permit Information. 

14 This section sets forth the information which the owner or operator must submit to the Director 

15 in order to be permitted as a Class VI well. The application for a permit for construction and 

16 operation of a Class VI well must include the following: 

17 (1) Information required in 40 CFR 144.31 (e)(1) through (6); 

18 (2) A map showing the injection well(s) for which a permit is sought and the applicable 

19 area of review. Within the area of review, the map must show the number, or name and 

20 location of all injection wells, producing wells, abandoned wells, plugged wells or dry 

21 holes, deep stratigraphic boreholes, State or EPA approved subsurface cleanup sites, 

22 surface bodies of water, springs, mines (surface and subsurface), quarries, water wells 
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1 and other pertinent surface features including structures intended for human occupancy 

2 and roads. The map should also show faults, if known or suspected. Only information of 

3 public record is required to be included on this map; 

4 (3) The area of review based on modeling, using data obtained during logging and testing 

5 of the well and the formation as required by paragraphs (12), (18), and (19) of this 

6 section; 

7 (4) Information on the geologic structure and hydrogeologic properties of the proposed 

8 storage site and overlying formations, including: 

9 (i) Maps and cross sections of the area of review;

10 (ii) Location, orientation, and properties of known or suspected faults and 

11 fractures that may transect the confining zone(s) in the area of review and a 

12 determination that they would not interfere with containment; 

13 (iii) Information on seismic history including the presence and depth of seismic 

14 sources and a determination that the seismicity would not interfere with 

15 containment; 

16 (iv) Data on the depth, areal extent, thickness, mineralogy, porosity, permeability 

17 and capillary pressure of the injection and confining zone(s); including 

18 geology/facies changes based on field data which may include geologic cores, 

19 outcrop data, seismic surveys, well logs, and names and lithologic descriptions; 

20 (v) Geomechanical information on fractures, stress, ductility, rock strength, and in 

21 situ fluid pressures within the confining zone; and 
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1 (vi) Geologic and topographic maps and cross sections illustrating regional 

2 geology, hydrogeology, and the geologic structure of the local area. 

3 (5) A tabulation of all wells within the area of review which penetrate the injection or 

4 confining zone(s). Such data must include a description of each well's type, construction, 

5 date drilled, location, depth, record of plugging and/or completion, and any additional 

6 information the Director may require; 

7 (6) Maps and stratigraphic cross sections indicating the general vertical and lateral limits 

8 of all USDWs, water wells and springs within the area of review, their positions relative 

9 to the injection zone(s) and the direction of water movement, where known; 

10 (7) Baseline geochemical data on subsurface formations, including all USDWs in the area 

11 of review; 

12 (8) Proposed operating data: 

13 (i) Average and maximum daily rate and volume of the carbon dioxide stream; 

14 (ii) Average and maximum injection pressure; 

15 (iii) The source of the carbon dioxide stream; and 

16 (iv) An analysis of the chemical and physical characteristics of the carbon dioxide 

17 stream; 
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1 (9) The compatibility of the carbon dioxide stream with fluids in the injection zone and 

2 minerals in both the injection and the confining zone(s), based on the results of the 

3 formation testing program, and with the materials used to construct the well; 

4 (10) Proposed formation testing program to obtain an analysis of the chemical and 

5 physical characteristics of the injection zone and confining zone; 

6 (11) Proposed stimulation program and a determination that stimulation will not interfere 

7 with containment; 

8 (12) The results of the formation testing program as required in paragraph (10) of this 

9 section; 

10 (13) Proposed procedure to outline steps necessary to conduct injection operation; 

11 (14) Schematic or other appropriate drawings of the surface and subsurface construction 

12 details of the well; 

13 (15) Injection well construction procedures that meet the requirements of §146.86; 

14 (16) Proposed area of review and corrective action plan that meets the requirements 

15 under §146.84; 

16 (17) The status of corrective action on wells in the area of review; 

17 (18) All available logging and testing program data on the well required by §146.87; 

18 (19) A demonstration of mechanical integrity pursuant to §146.89; 
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1 (20) A demonstration, satisfactory to the Director, that the applicant has met the financial 

2 responsibility requirements under §146.85; 

3 (21) Proposed testing and monitoring plan required by §146.90; 

4 (22) Proposed injection well plugging plan required by §146.92(b); 

5 (23) Proposed post-injection site care and closure plan required by §146.93(a); 

6 (24) Proposed emergency and remedial response plan required by §146.94; and 

7 (25) Any other information requested by the Director. 

8 

9 §146.83 Minimum criteria for siting.

10 (a) Owners or operators of Class VI wells must demonstrate to the satisfaction of the Director 

11 that the wells will be sited in areas with a suitable geologic system. The geologic system must 

12 be comprised of: 

13 (1) An injection zone of sufficient areal extent, thickness, porosity, and permeability to 

14 receive the total anticipated volume of the carbon dioxide stream; 

15 (2) A confining zone(s) that is free of transmissive faults or fractures and of sufficient 

16 areal extent and integrity to contain the injected carbon dioxide stream and displaced 

17 formation fluids and allow injection at proposed maximum pressures and volumes 

18 without initiating or propagating fractures in the confining zone(s); and 

19 (b) At the Director’s discretion, owners or operators of Class VI wells must identify and 

20 characterize additional zones that will impede vertical fluid movement, are free of faults and 
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1 fractures that may interfere with containment, allow for pressure dissipation, and provide 

2 additional opportunities for monitoring, mitigation and remediation. 

3 

4 §146.84 Area of review and corrective action. 

5 (a) The area of review is the region surrounding the geologic sequestration project that may be 

6 impacted by the injection activity. The area of review is based on computational modeling that 

7 accounts for the physical and chemical properties of all phases of the injected carbon dioxide 

8 stream. 

9 (b) The owner or operator of a Class VI well must prepare, maintain, and comply with a plan to 

10 delineate the area of review for a proposed geologic sequestration project, periodically reevaluate 

11 the delineation, and perform corrective action that meets the requirements of this section and is 

12 acceptable to the Director. As a part of the permit application for approval by the Director, the 

13 owner or operator must submit an area of review and corrective action plan that includes the 

14 following information: 

15 (1) The method for delineating the area of review that meets the requirements of 

16 paragraph (c) of this section, including the model to be used, assumptions that will be 

17 made, and the site characterization data on which the model will be based; 

18 (2) A description of: 

19 (i) the minimum fixed frequency, not to exceed 10 years, the owner or operator 

20 proposes to reevaluate the area of review; 
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1 (ii) the monitoring and operational conditions that would warrant a reevaluation 

2 of the area of review prior to the next scheduled reevaluation as determined by the 

3 minimum fixed frequency established in (b)(2)(i) of this section. 

4 (iii) how monitoring and operational data (e.g., injection rate and pressure) will be 

5 used to inform an area of review reevaluation; and 

6 (iv) how corrective action will be conducted to meet the requirements of 

7 paragraph (d) of this section, including what corrective action will be performed 

8 prior to injection and what, if any, portions of the area of review in which 

9 corrective action will be addressed on a phased basis; how corrective action will 

10 be adjusted if there are changes in the area of review; and how site access will be 

11 guaranteed for future corrective action.

12 (c) Owners or operators of Class VI wells must perform the following actions to delineate the 

13 area of review, identify all wells that require corrective action, and perform corrective action on 

14 those wells: 

15 (1) Predict, using computational modeling, the projected lateral and vertical migration of 

16 the carbon dioxide plume and formation fluids in the subsurface from the commencement 

17 of injection activities until the plume movement ceases, pressure differentials sufficient to 

18 cause the movement of injected fluids or formation fluids into a USDW are no longer 

19 present, or after a fixed time period as determined by the Director. The model must: 

20 (i) be based on detailed geologic data collected to characterize the injection zone, 

21 confining zone and any additional zones; and anticipated operating data, including 

22 injection pressures, rates and total volumes over the proposed life of the 

23 geological sequestration project; 
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1 (ii) take into account any geologic heterogeneities, data quality, and their possible 

2 impact on model predictions; and 

3 (iii) consider potential migration through faults, fractures, and artificial 

4 penetrations. 

5 (2) Using methods approved by the Director, identify all penetrations, including active 

6 and abandoned wells and underground mines, in the area of review that may penetrate the 

7 confining zone. Provide a description of each well’s type, construction, date drilled, 

8 location, depth, record of plugging and/or completion, and any additional information the 

9 Director may require; and 

10 (3) Determine which abandoned wells in the area of review have been plugged (as 

11 required by §149.92) in a manner that prevents the movement of carbon dioxide or 

12 associated fluids that may endanger USDWs. 

13 (d) Owners or operators of Class VI wells must perform corrective action on all wells in the area 

14 of review that are determined to need corrective action using methods necessary to prevent the 

15 movement of fluid into or between USDWs including use of corrosion resistant materials, where 

16 appropriate. 

17 (e) If monitoring data indicate an endangerment to USDWs, the owner or operator must notify 

18 the Director and cease operations as required by §146.94. 

19 (f) At the minimum fixed frequency, not to exceed 10 years, as specified in the area of review 

20 and corrective action plan, or when monitoring and operational conditions warrant, owners or 

21 operators must: 

22 (1) reevaluate the area of review in the same manner specified in paragraph (c)(1) of this 

23 section; 
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1 (2) identify all wells in the reevaluated area of review that require corrective action in the 

2 same manner specified in paragraph (c)(2) of this section; 

3 (3) perform corrective action on wells requiring corrective action in the reevaluated area 

4 of review in the same manner specified in paragraph (c)(3) of this section; and 

5 (4) submit an amended area of review and corrective action plan or demonstrate to the 

6 Director through monitoring data and modeling results that no amendment to the area 

7 of review and corrective action plan is needed. 

8 (g) The emergency and remedial response plan (as required by §146.94) and a demonstration of 

9 financial responsibility (as described by §146.85) must account for the entire area of review, 

10 regardless of whether or not corrective action in the area of review is phased. 

11 

12 §146.85 Financial responsibility. 

13 (a) The owner or operator must demonstrate and maintain financial responsibility and resources 

14 for corrective action (that meets the requirements of §146.84), injection well plugging (that 

15 meets the requirements of §146.92), post-injection site care and closure (that meets the 

16 requirements of §146.93), and emergency and remedial response (that meets the requirements of 

17 §146.94) in a manner prescribed by the Director until: 

18 (1) The Director receives and approves the completed post-injection site care and closure 

19 plan; and 

20 (2) The Director determines that the site has reached the end of the post injection site care 

21 period. 

22 (b) The owner or operator must provide to the Director, at a frequency determined by the 

23 Director, written updates of adjustments to the cost estimate to account for any amendments to 
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1 the area of review and corrective action plan (§146.84), the injection well plugging plan 

2 (§146.92), and the post-injection site care and closure plan (§146.93). 

3 (c) The owner or operator must notify the Director of adverse financial conditions such as 

4 bankruptcy, that may affect the ability to carry out injection well plugging and post-injection site 

5 care and closure. 

6 (d) The operator must provide an adjustment of the cost estimate to the Director if the Director 

7 has reason to believe that the original demonstration is no longer adequate to cover the cost of 

8 injection well plugging (as required by §146.92) and post-injection site care and closure (as 

9 required by §146.93). 

10 

11 §146.86 Injection well construction requirements. 

12 (a) General. The owner or operator must ensure that all Class VI wells are constructed and 

13 completed to: 

14 (1) Prevent the movement of fluids into or between USDWs or into any unauthorized 

15 zones; 

16 (2) Permit the use of appropriate testing devices and workover tools; and 

17 (3) Permit continuous monitoring of the annulus space between the injection tubing and 

18 long string casing. 

19 (b) Casing and Cementing of Class VI Wells.

20 (1) Casing and cement or other materials used in the construction of each Class VI well 

21 must have sufficient structural strength and be designed for the life of the geologic 

22 sequestration project. All well materials must be compatible with fluids with which the 

23 materials may be expected to come into contact and meet or exceed standards developed 
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1 for such materials by the American Petroleum Institute, ASTM International, or 

2 comparable standards acceptable to the Director. The casing and cementing program 

3 must be designed to prevent the movement of fluids into or between USDWs. In order to 

4 allow the Director to determine and specify casing and cementing requirements, the 

5 owner or operator must provide the following information: 

6 (i) Depth to the injection zone; 

7 (ii) Injection pressure, external pressure, internal pressure and axial loading; 

8 (iii) Hole size; 

9 (iv) Size and grade of all casing strings (wall thickness, external diameter, 

10 nominal weight, length, joint specification and construction material); 

11 (v) Corrosiveness of the carbon dioxide stream, and formation fluids; 

12 (vi) Down-hole temperatures; 

13 (vii) Lithology of injection and confining zones; 

14 (viii) Type or grade of cement; and 

15 (ix) Quantity, chemical composition, and temperature of the carbon dioxide 

16 stream. 

17 (2) Surface casing must extend through the base of the lowermost USDW and be 

18 cemented to the surface. 

19 (3) At least one long string casing, using a sufficient number of centralizers, must extend 

20 to the injection zone and must be cemented by circulating cement to the surface in one or 

21 more stages. 

22 (4) Circulation of cement may be accomplished by staging. The Director may approve an 

23 alternative method of cementing in cases where the cement cannot be recirculated to the 
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1 surface, provided the owner or operator can demonstrate by using logs that the cement 

2 does not allow fluid movement behind the well bore. 

3 (5) Cement and cement additives must be compatible with the carbon dioxide stream and 

4 formation fluids and of sufficient quality and quantity to maintain integrity over the 

5 design life the geologic sequestration project. The integrity and location of the cement 

6 shall be verified using technology capable of evaluating cement quality radially and 

7 identifying the location of channels to ensure that USDWs are not endangered. 

8 (c) Tubing and packer.

9 (1) All owner and operators of Class VI wells must inject fluids through tubing with a 

10 packer set at a depth opposite a cemented interval at the location approved by the 

11 Director. 

12 (2) In order for the Director to determine and specify requirements for tubing and packer, 

13 the owner or operator must submit the following information: 

14 (i) Depth of setting; 

15 (ii) Characteristics of the carbon dioxide stream (chemical content, corrosiveness, 

16 temperature, and density); 

17 (iii) Injection pressure; 

18 (iv) Annular pressure; 

19 (v) Injection rate (intermittent or continuous) and volume of the carbon dioxide 

20 stream; 

21 (vi) Size of casing; and 

22 (vii) Tubing tensile, burst, and collapse strengths. 

23 
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1 §146.87 Logging, sampling, and testing prior to injection well operation.

2 (a) During the drilling and construction of a Class VI injection well, the owner or operator must 

3 run appropriate logs, surveys and tests to determine or verify the depth, thickness, porosity, 

4 permeability, and lithology of, and the salinity of any formation fluids in, all relevant geologic 

5 formations to assure conformance with the injection well construction requirements under 

6 §146.86, and to establish accurate baseline data against which future measurements may be 

7 compared. The owner or operator must submit to the Director a descriptive report prepared by a 

8 knowledgeable log analyst that includes an interpretation of the results of such logs and tests. At 

9 a minimum, such logs and tests must include: 

10 (1) Deviation checks during drilling on all holes constructed by drilling a pilot hole which 

11 are enlarged by reaming or another method. Such checks must be at sufficiently frequent 

12 intervals to determine the location of the borehole and to assure that vertical avenues for 

13 fluid movement in the form of diverging holes are not created during drilling; and 

14 (2) Before and upon installation of the surface casing: 

15 (i) Resistivity, spontaneous potential, and caliper logs before the casing is 

16 installed; and 

17 (ii) A cement bond and variable density log, and a temperature log after the casing 

18 is set and cemented. 

19 (3) Before and upon installation of the long string casing: 

20 (i) Resistivity, spontaneous potential, porosity, caliper, gamma ray, fracture finder 

21 logs, and any other logs the Director requires for the given geology before the 

22 casing is installed; and 
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1 (ii) A cement bond and variable density log, and a temperature log after the casing 

2 is set and cemented. 

3 (4) A series of tests designed to demonstrate the internal and external mechanical 

4 integrity of injection wells, which may include: 

5 (i) A pressure test with liquid or gas; 

6 (ii) A tracer survey such as oxygen-activation logging; 

7 (iii) A temperature or noise log; 

8 (iv) A casing inspection log, if required by the Director; and 

9 (5) Any alternative methods that provide equivalent or better information and that are 

10 required of and/or approved of by the Director. 

11 (b) The owner or operator must take and submit to the Director whole cores or sidewall cores of 

12 the injection zone and confining system and formation fluid samples from the injection zone(s). 

13 The Director may accept cores from nearby wells if the owner or operator can demonstrate that 

14 core retrieval is not possible and that such cores are representative of conditions at the well. The 

15 Director may require the owner or operator to core other formations in the borehole. 

16 (c) The owner or operator must record the fluid temperature, pH, conductivity, reservoir pressure 

17 and the static fluid level of the injection zone(s). 

18 (d) At a minimum, the owner or operator must determine or calculate the following information 

19 concerning the injection and confining zone(s): 

20 (1) Fracture pressure; 

21 (2) Other physical and chemical characteristics of the injection and confining zones; and 

22 (3) Physical and chemical characteristics of the formation fluids in the injection zone. 
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1 (e) Upon completion, but prior to operation, the owner or operator must conduct the following 

2 tests to verify hydrogeologic characteristics of the injection zone: 

3 (1) a pump test; or 

4 (2) injectivity tests. 

5 (f) The owner or operator must provide the Director with the opportunity to witness all logging 

6 and testing by this subpart. The owner or operator must submit a schedule of such activities to 

7 the Director 30 days prior to conducting the first test and submit any changes to the schedule 30 

8 days prior to the next scheduled test. 

9 

10 §146.88 Injection well operating requirements. 

11 (a) Except during stimulation, the owner or operator must ensure that injection pressure does not 

12 exceed 90 percent of the fracture pressure of the injection zone so as to assure that the injection 

13 does not initiate new fractures or propagate existing fractures in the injection zone. In no case 

14 may injection pressure initiate fractures in the confining zone(s) or cause the movement of 

15 injection or formation fluids that endangers a USDW. 

16 (b) Injection between the outermost casing protecting USDWs and the well bore is prohibited. 

17 (c) The owner or operator must fill the annulus between the tubing and the long string casing 

18 with a non-corrosive fluid approved by the Director. The owner or operator must maintain on 

19 the annulus a pressure that exceeds the operating injection pressure, unless the Director 

20 determines that such requirement might harm the integrity of the well. 

21 (d) Other than during periods of well workover (maintenance) approved by the Director in which 

22 the sealed tubing-casing annulus is of necessity disassembled for maintenance or corrective 
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1 procedures, the owner or operator must maintain mechanical integrity of the injection well at all 

2 times. 

3 (e) The owner or operator must install and use continuous recording devices to monitor: the 

4 injection pressure; the rate, volume, and temperature of the carbon dioxide stream; and the 

5 pressure on the annulus between the tubing and the long string casing and annulus fluid volume; 

6 and must install and use alarms and automatic down-hole shut-off systems, designed to alert the 

7 operator and shut-in the well when operating parameters such as annulus pressure, injection rate 

8 or other parameters approved by the Director diverge beyond permitted ranges and/or gradients 

9 specified in the permit; 

10 (f) If a down-hole automatic shutdown is triggered or a loss of mechanical integrity is 

11 discovered, the owner or operator must immediately investigate and identify as expeditiously as 

12 possible the cause of the shutoff. If, upon such investigation, the well appears to be lacking 

13 mechanical integrity, or if monitoring required under paragraph (e) of this section otherwise 

14 indicates that the well may be lacking mechanical integrity, the owner or operator must: 

15 (1) Immediately cease injection; 

16 (2) Take all steps reasonably necessary to determine whether there may have been a 

17 release of the injected carbon dioxide stream into any unauthorized zone; 

18 (3) Notify the Director within 24 hours; 

19 (4) Restore and demonstrate mechanical integrity to the satisfaction of the Director prior 

20 to resuming injection; and 
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1 (5) Notify the Director when injection can be expected to resume. 

2 

3 §146.89 Mechanical integrity. 

4 (a) A Class VI well has mechanical integrity if: 

5 (1) There is no significant leak in the casing, tubing or packer; and 

6 (2) There is no significant fluid movement into a USDW through channels adjacent to the 

7 injection well bore. 

8 (b) To evaluate the absence of significant leaks under paragraph (a)(1) of this section, owners or 

9 operators must, following an initial annulus pressure test, continuously monitor injection pressure, 

10 rate, injected volumes, and pressure on the annulus between tubing and long stem casing and 

11 annulus fluid volume as specified in §146.88 (e); 

12 (c) At least once per year, the owner or operator must use one of the following methods to 

13 determine the absence of significant fluid movement under paragraph (a)(2) of this section: 

14 (1) A tracer survey such as oxygen-activation logging; 

15 (2) A temperature or noise log; or 

16 (3) A casing inspection log, if required by the Director. 

17 (d) The Director may require any other test to evaluate mechanical integrity under (a)(1) or (a)(2) 

18 of this section. Also, the Director may allow the use of a test to demonstrate mechanical 
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1 integrity other than those listed above with the written approval of the Administrator. To obtain 

2 approval, the Director must submit a written request to the Administrator, which must set forth 

3 the proposed test and all technical data supporting its use. The Administrator must approve the 

4 request if it will reliably demonstrate the mechanical integrity of wells for which its use is 

5 proposed. Any alternate method approved by the Administrator will be published in the Federal 

6 Register and may be used in all States in accordance with applicable State law unless its use is 

7 restricted at the time of approval by the Administrator. 

8 (e) In conducting and evaluating the tests enumerated in this section or others to be allowed by 

9 the Director, the owner or operator and the Director must apply methods and standards generally 

10 accepted in the industry. When the owner or operator reports the results of mechanical integrity 

11 tests to the Director, he/she shall include a description of the test(s) and the method(s) used. In 

12 making his/her evaluation, the Director must review monitoring and other test data submitted 

13 since the previous evaluation. 

14 (f) The Director may require additional or alternative tests if the results presented by the owner 

15 or operator under §146.89(d) are not satisfactory to the Director to demonstrate that there is no 

16 significant leak in the casing, tubing or packer or significant movement of fluid into or between 

17 USDWs resulting from the injection activity as stated in paragraphs (a)(1) and (2) above. 

18 

19 §146.90 Testing and monitoring requirements. 

20 The owner or operator of a Class VI well must prepare, maintain, and comply with a testing and 

21 monitoring plan to verify that the geologic sequestration project is operating as permitted and is 

22 not endangering USDWs. The testing and monitoring plan must be submitted with the permit 
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1 application, for Director approval, and must include a description of how the owner or operator 

2 will meet the requirements of this section. Testing and monitoring associated with geologic 

3 sequestration projects must, at a minimum, include: 

4 (a) Analysis of the carbon dioxide stream with sufficient frequency to yield data representative of 

5 its chemical and physical characteristics; 

6 (b) Installation and use, except during well workovers as defined in 146.86(d), of continuous 

7 recording devices to monitor injection pressure, rate and volume; the pressure on the annulus 

8 between the tubing and the long string casing; and the annulus fluid volume; 

9 (c) Corrosion monitoring of the well materials for loss of mass, thickness, cracking, pitting and 

10 other signs of corrosion must be performed on a quarterly basis to ensure that the well 

11 components meet the minimum standards for material strength and performance set forth in 

12 §146.86(b) by: 

13 (1) Placing coupons of the well construction materials in contact with the carbon dioxide 

14 stream; or 

15 (2) Routing the carbon dioxide stream through a loop constructed with the material used 

16 in the well; or 

17 (3) Using an alternative method approved by the Director; 

18 (d) Periodic monitoring of the ground water quality and geochemical changes above the 

19 confining zone(s) that may be a result of carbon dioxide movement through the confining zone 

20 or additional identified zones: 
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1 (1) The location and number of monitoring wells must be based on specific information 

2 about the geologic sequestration project, including injection rate and volume, geology, 

3 the presence of artificial penetrations and other factors; 

4 (2) The monitoring frequency and spatial distribution of monitoring wells must be based 

5 on baseline geochemical data that has been collected under §146.82(a)(6) and any 

6 modeling results in the area of review evaluation required by §146.84(b); 

7 (e) A demonstration of external mechanical integrity pursuant to §146.89(c) at least once per 

8 year throughout the duration of the geologic sequestration project; 

9 (f) A pressure fall-off test at least once every five years unless more frequent testing is required 

10 by the Director based on site specific information; 

11 (g) Testing and monitoring to track the extent of the carbon dioxide plume and the position of the 

12 pressure front by either monitoring for pressure changes in the first formation overlying the 

13 confining zone or using indirect, geophysical techniques (e.g., seismic, electrical, gravity, or 

14 electromagnetic surveys and/or down-hole carbon dioxide detection tools); 

15 (h) At the Director’s discretion, surface air monitoring and/or soil gas monitoring to detect 

16 movement of carbon dioxide that could endanger a USDW. 

17 (1) The testing and monitoring plan must be based on potential vulnerabilities within the 

18 area of review; 

19 (2) The monitoring frequency and spatial distribution of surface air monitoring and/or 

20 soil gas monitoring must reflect baseline data and the monitoring plan must include how 
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1 the proposed monitoring will yield useful information on the area of review delineation 

2 and/or compliance with standards under §144.12; 

3 (i) Any additional monitoring, as required by the Director, necessary to support, upgrade, and 

4 improve computational modeling of the area of review evaluation required under §146.84(b) and 

5 to determine compliance with standards under §144.12; and 

6 (j) A quality assurance and surveillance plan for all testing and monitoring requirements. 

7 

8 §146.91 Reporting requirements. 

9 The owner or operator must, at a minimum, provide the following reports to the Director, for 

10 each permitted Class VI well: 

11 (a) Semi-annual reports containing: 

12 (1) Any changes to the physical, chemical and other relevant characteristics of the carbon 

13 dioxide stream from the proposed operating data; 

14 (2) Monthly average, maximum and minimum values for injection pressure, flow rate and 

15 volume, and annular pressure; 

16 (3) A description of any event that exceeds operating parameters for annulus pressure or 

17 injection pressure as specified in the permit; 
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1 (4) A description of any event which triggers a shutdown device required pursuant to 

2 §146.88(e) and the response taken; 

3 (5) The monthly volume of the carbon dioxide stream injected over the reporting period 

4 and project cumulatively; 

5 (6) Monthly annulus fluid volume added; and 

6 (7) The results of monitoring prescribed under §146.90. 

7 (b) Report, within 30 days the results of: 

8 (1) Periodic tests of mechanical integrity; 

9 (2) Any other test of the injection well conducted by the permittee if required by the 

10 Director; and 

11 (3) Any well workover. 

12 (c) Owners or operators must submit reports in an electronic format acceptable to the Director. 

13 At the discretion of the Director, other formats may be accepted. 

14 

15 §146.92 Injection well plugging.

16 (a) Prior to the well plugging, the owner or operator must flush each Class VI injection well with 

17 a buffer fluid, determine bottomhole reservoir pressure, and perform a final mechanical integrity 

18 test. 
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1 (b) Well Plugging Plan. The owner or operator of a Class VI well must prepare, maintain, and 

2 comply with a plan that is acceptable to the Director. The requirement to maintain and 

3 implement an approved plan is directly enforceable regardless of whether the requirement is a 

4 condition of the permit. The well plugging plan must be submitted as part of the permit 

5 application and must include the following information: 

6 (1) Appropriate test or measure to determine bottomhole reservoir pressure; 

7 (2) Appropriate testing methods to ensure mechanical integrity as specified in §146.89; 

8 (3) The type and number of plugs to be used; 

9 (4) The placement of each plug including the elevation of the top and bottom of each 

10 plug; 

11 (5) The type and grade and quantity of material to be used in plugging. The material must 

12 be compatible with the carbon dioxide stream; and 

13 (6) The method of placement of the plugs. 

14 (c) Notice of intent to plug. The owner or operator must notify the Director at least 60 days 

15 before plugging of a well. At this time, if any changes have been made to the original well 

16 plugging plan, the owner or operator must also provide the revised well plugging plan. At the 

17 discretion of the Director, a shorter notice period may be allowed. 

18 (d) Plugging report. Within 60 days after plugging or at the time of the next semi-annual report 

19 (whichever occurs earlier) the owner or operator must submit a plugging report to the Director. If 

20 the semi-annual report is due less than 15 days after completion of plugging, then the report must 
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1 be submitted within 60 days after plugging. The report must be certified as accurate by the owner 

2 or operator and by the person who performed the plugging operation (if other than the owner or 

3 operator.) 

4 

5 §146.93 Post-injection site care and closure. 

6 (a) The owner or operator of a Class VI well must prepare, maintain, and comply with a plan for 

7 post-injection site care and closure that meets the requirements of paragraph (2) of this section 

8 and is acceptable to the Director. 

9 (1) The owner or operator must submit the post-injection site care and closure plan as a 

10 part of the permit application to be approved by the Director. 

11 (2) The post-injection site care and closure plan must include the following information: 

12 (i) The pressure differential between pre-injection and predicted post-injection 

13 pressures in the injection zone; 

14 (ii) The predicted position of the carbon dioxide plume and associated pressure 

15 front at site closure as demonstrated in the area of review evaluation required 

16 under §146.84(b); 

17 (iii) A description of post-injection monitoring location, methods, and proposed 

18 frequency; and 
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1 (iv) A proposed schedule for submitting post-injection site care monitoring results 

2 to the Director. 

3 (3) Upon cessation of injection, owners or operators of Class VI wells must either submit 

4 an amended post-injection site care and closure plan or demonstrate to the Director 

5 through monitoring data and modeling results that no amendment to the plan is needed. 

6 (4) The owner or operator may modify and resubmit the post-injection site care and 

7 closure plan for the Director’s approval within 30 days of such change. 

8 (b) The owner or operator shall monitor the site following the cessation of injection to show the 

9 position of the carbon dioxide plume and pressure front and demonstrate that USDWs are not 

10 being endangered. 

11 (1) The owner or operator shall continue to conduct monitoring as specified in the 

12 Director-approved post-injection site care and closure plan for at least 50 years following 

13 the cessation of injection. At the Director’s discretion, the monitoring will continue until 

14 the geologic sequestration project no longer poses an endangerment to USDWs. 

15 (2) If the owner or operator can demonstrate to the satisfaction of the Director before 50 

16 years, based on monitoring and other site-specific data, that the geologic sequestration 

17 project no longer poses an endangerment to USDWs, the Director may approve an 

18 amendment to the post-injection site care and closure plan to reduce the frequency of 

19 monitoring or may authorize site closure. 
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1 (3) Prior to authorization for site closure, the owner or operator must submit to the 

2 Director a demonstration, based on monitoring and other site-specific data, that the 

3 carbon dioxide plume and pressure front have stabilized and that no additional 

4 monitoring is needed to assure that the geologic sequestration project does not pose an 

5 endangerment to USDWs. 

6 (4) If such a demonstration cannot be made (i.e., if the carbon dioxide plume and pressure 

7 front have not stabilized) after the 50 year period, the owner or operator must submit to 

8 the Director a plan to continue post-injection site care. 

9 (c) Notice of intent for site closure. The owner or operator must notify the Director at least 120 

10 days before site closure. At this time, if any changes have been made to the original post11 injection site care and closure plan, the owner or operator must also provide the revised plan. At 

12 the discretion of the Director, a shorter notice period may be allowed. 

13 (d) After the Director has authorized site closure, the owner or operator must plug all monitoring 

14 wells in a manner which will not allow movement of injection or formation fluids that endangers 

15 a USDW. 

16 (e) Once the Director has authorized site closure, the owner or operator must submit a site 

17 closure report within 90 days that must thereafter be retained at a location designated by the 

18 Director. The report must include: 

19 (1) Documentation of appropriate injection and monitoring well plugging as specified in 

20 §146.92 and paragraph (c) of this section. The owner or operator must provide a copy of 

21 a survey plat which has been submitted to the local zoning authority designated by the 
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1 Director. The plat must indicate the location of the injection well relative to permanently 

2 surveyed benchmarks. The owner or operator must also submit a copy of the plat to the 

3 Regional Administrator of the appropriate EPA Regional Office; 

4 (2) Documentation of appropriate notification and information to such State, local and 

5 tribal authorities as have authority over drilling activities to enable such State and local 

6 authorities to impose appropriate conditions on subsequent drilling activities that may 

7 penetrate the injection and confining zone(s); and 

8 (3) Records reflecting the nature, composition and volume of the carbon dioxide stream. 

9 (f) Each owner or operator of a Class VI injection well must record a notation on the deed to the 

10 facility property or any other document that is normally examined during title search that will in 

11 perpetuity provide any potential purchaser of the property the following information: 

12 (1) The fact that land has been used to sequester carbon dioxide; 

13 (2) The name of the State agency, local authority, and/or tribe with which the survey plat 

14 was filed, as well as the address of the Regional Environmental Protection Agency Office 

15 to which it was submitted; and 

16 (3) The volume of fluid injected, the injection zone or zones into which it was injected, 

17 and the period over which injection occurred. 

18 (g) The owner or operator must retain for three years following site closure, records collected 

19 during the post-injection site care period. The owner or operator must deliver the records to the 
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1 Director at the conclusion of the retention period, and the records must thereafter be retained at a 

2 location designated by the Director for that purpose. 

3 

4 §146.94 Emergency and remedial response. 

5 (a) As part of the permit application, the owner or operator must provide the Director with a 

6 emergency and remedial response plan that describes actions to be taken to address movement of 

7 the injection or formation fluids that may cause an endangerment to a USDW during 

8 construction, operation, closure and post-closure periods. 

9 (b) If the owner or operator obtains evidence that the injected carbon dioxide stream and 

10 associated pressure front may cause an endangerment to a USDW, the owner or operator must: 

11 (1) Immediately cease injection; 

12 (2) Take all steps reasonably necessary to identify and characterize any release; 

13 (3) Notify the Director within 24 hours; and 

14 (4) Implement the emergency and remedial response plan approved by the Director. 

15 (c) The Director may allow the operator to resume injection prior to remediation if the owner or 

16 operator demonstrates that the injection operation will not endanger USDWs. 

17 (d) The owner or operator must notify the Director and obtain his approval prior to conducting 

18 any well workover. 
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1 Billing code 6560-50-P 

2