Section 730.108 Mechanical Integrity

a)  The owner or operator must demonstrate mechanical integrity when required by other Sections. An injection well has mechanical integrity if both of the following conditions are fulfilled:

1)  There is no significant leak in the casing, tubing, or packer; and

2)  There is no significant fluid movement into an underground source of drinking water through vertical channels adjacent to the injection bore.

b)  One of the following tests must be used to demonstrate the absence of significant leaks pursuant to subsection (a)(1):

1)  Following an initial pressure test, monitoring of the tubing-casing annulus pressure with sufficient frequency to be representative, as determined by the Agency, while maintaining an annulus pressure different from atmospheric pressure measured at the surface; or

2)  A pressure test with liquid or gas.

c)  One of the following methods may be used to determine the absence of significant fluid movement pursuant to subsection (a)(2):

1)  The results of a temperature or noise log;

2)  For Class III injection wells where the nature of the casing precludes the use of the logging techniques prescribed at subsection (c)(1), cementing records demonstrating the presence of adequate cement to prevent migration; or

3)  For Class III injection wells where the Agency elects to rely on cementing records to demonstrate the absence of significant fluid movement, the monitoring program prescribed by 35 Ill. Adm. Code 730.113(b) must be designed to verify the absence of significant fluid movement.

d)  The Agency may allow the use of a test to demonstrate mechanical integrity other than those listed in subsections (b) and (c). To obtain approval, the owner or operator must submit a written request to the Agency that sets forth the proposed test and all technical data supporting its use. The Agency must approve the request if the test will reliably demonstrate the mechanical integrity of wells for which its use is proposed.

e)  In conducting and evaluating the tests enumerated in this Section or others to be allowed by the Agency, the owner or operator and the Agency must apply methods and standards generally accepted in the industry. When the owner or operator reports the results of mechanical integrity tests to the Agency, it must include a description of the test and the method used. In making its evaluation, the Agency must review monitoring and other test data submitted since the previous evaluation.

f)  The Agency may require additional or alternative tests if the results presented by the owner or operator pursuant to subsection (e) are not satisfactory to the Agency to demonstrate that there is no movement of fluid into or between USDWs resulting from the injection activity.

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

Section 730.109 Criteria for Establishing Permitting Priorities

In determining priorities for setting times for owners or operators to submit applications for authorization to inject pursuant to the procedures of 35 Ill. Adm. Code 704.161, the Agency must base these priorities upon consideration of the following factors:

a)  Any injection wells known or suspected to be contaminating underground sources of drinking water;

b)  Any injection wells known to be injecting fluids containing hazardous contaminants;

c)  The likelihood of contamination of underground sources of drinking water;

d)  Any potentially affected population;

e)  Any injection wells violating existing Illinois requirements;

f)  Coordination with the issuance of permits required by other State or federal permit programs;

g)  The age and depth of the injection well; and

h)  The expiration dates of existing Illinois permits, if any.

(Source: Amended at 31 Ill. Reg. 1281, effective December 20, 2006)

Section 730.110 Plugging and Abandoning Wells

a)  Requirements for Class I, II, and III injection wells.

1)  Prior to abandoning a Class I or Class III injection well, the well must be plugged with cement in a manner that will not allow the movement of fluids either into or between underground sources of drinking water. The Agency may allow Class III injection wells to use other plugging materials if it is satisfied that such materials will prevent movement of fluids into or between underground sources of drinking water.

2)  Placement of the cement plugs must be accomplished by one of the following means:

A)  The Balance Method;

B)  The Dump Bailer Method;

C)  The Two-Plug Method; or

D)  An alternative method approved by the Agency in the permit that will reliably provide a comparable level of protection to underground sources of drinking water.

3)  The well to be abandoned must be in a state of static equilibrium with the mud weight equalized top to bottom, either by circulating the mud in the well at least once or by a comparable method prescribed by the Agency, prior to the placement of the cement plug.

4)  The plugging and abandonment required in 35 Ill. Adm. Code 704.181(f) and 704.188 must also demonstrate adequate protection of USDWs in the case of a Class III injection well that underlies or is in an aquifer that has been exempted pursuant to Section 730.104. The Agency must prescribe aquifer cleanup and monitoring where it deems it necessary and feasible to insure adequate protection of USDWs.

b)  Requirements for Class IV injection wells. Prior to abandoning a Class IV injection well, the owner or operator must close the well in accordance with 35 Ill. Adm. Code 704.145(b).

c)  Requirements for Class V injection wells.

1)  Prior to abandoning a Class V injection well, the owner or operator must close the well in a manner that prevents the movement of fluid containing any contaminant into an underground source of drinking water if the presence of that contaminant may cause a violation of any primary drinking water regulation pursuant to 35 Ill. Adm. Code 611, may cause a violation of any of the ground water quality standards of 35 Ill. Adm. Code 620, or may otherwise adversely affect the health of persons. Closure requirements for motor vehicle waste disposal wells and large-capacity cesspools are listed at Section 704.289.

2)  The owner or operator must dispose of or otherwise manage any soil, gravel, sludge, liquids, or other materials removed from or adjacent to the well in accordance with all applicable federal, State, and local regulations and requirements.

(Source: Amended at 31 Ill. Reg. 1281, effective December 20, 2006)

SUBPART B: CRITERIA AND STANDARDS APPLICABLE TO CLASS I NON-HAZARDOUS WASTE INJECTION WELLS

Section 730.111 Applicability

This Subpart B establishes criteria and standards for underground injection control programs to regulate Class I non-hazardous waste injection wells.

BOARD NOTE: Derived from 40 CFR 146.11 (2005).

(Source: Amended at 31 Ill. Reg. 1281, effective December 20, 2006)

Section 730.112 Construction Requirements

a)  All Class I injection wells must be sited in such a fashion that they inject into a formation which is beneath the lowermost formation containing, within 402 meters (one-quarter mile) of the well bore, an underground source of drinking water.

b)  All Class I injection wells must be cased and cemented to prevent the movement of fluids into or between underground sources of drinking water. The casing and cement used in the construction of each newly drilled well must be designed for the life expectancy of the well. In determining and specifying casing and cementing requirements, the following factors must be considered:

1)  The depth to the injection zone;

2)  The injection pressure, external pressure, internal pressure, and axial loading;

3)  The hole size;

4)  The size and grade of all casing strings (wall thickness, diameter, nominal weight, length, joint specification, and construction material);

5)  The corrosiveness of injected fluid, formation fluids, and temperatures;

6)  The lithology of the injection and confining intervals; and

7)  The type or grade of cement.

c)  A Class I injection well, except a municipal well injecting non-corrosive wastes, must protect underground sources of drinking water against movement of fluids from the injection zone upward through the well. An operator may do this by injecting fluids through tubing with a packer set immediately above the injection zone, or tubing with an approved fluid seal as an alternative. The tubing, packer, and fluid seal must be designed for the expected service.

1)  The use of other alternatives to a packer may be allowed with the written approval of the Agency. To obtain approval, the operator must submit a written request to the Agency that sets forth the proposed alternative and all technical data supporting its use. The Agency must approve the request if the alternative method will reliably provide a comparable level of protection to underground sources of drinking water. The Agency may approve an alternative method solely for an individual well; however, the Agency may promulgate criteria approving alternatives pursuant to 35 Ill. Adm. Code 702.106.

2)  In determining and specifying requirements for tubing, packer, or alternatives the following factors must be considered:

A)  The depth of setting;

B)  Characteristics of the injection fluid (chemical content, corrosiveness, and density);

C)  The injection pressure;

D)  The annular pressure;

E)  The rate, temperature, and volume of injected fluid; and

F)  The size of the casing.

d)  Appropriate logs and other tests must be conducted during the drilling and construction of new Class I injection wells. A descriptive report interpreting the results of such logs and tests must be prepared by a knowledgeable log analyst and submitted to the Agency. At a minimum, such logs and tests must include the following information:

1)  Deviation checks on all holes constructed by first drilling a pilot hole, and then enlarging the pilot hole by reaming or another method. Such checks must be at sufficiently frequent intervals to assure that vertical avenues for fluid migration in the form of diverging holes are not created during drilling.

2)  Such other logs and tests as may be needed after taking into account the availability of similar data in the area of the drilling site, the construction plan, and the need for additional information, that may arise from time to time as the construction of the well progresses. In determining which logs and tests must be required, the following logs must be considered for use in the following situations:

A)  For surface casing intended to protect underground sources of drinking water, the following:

i)  Resistivity, spontaneous potential, and caliper logs before the casing is installed; and

ii)  A cement bond, temperature, or density log after the casing is set and cemented.

B)  For intermediate and long strings of casing intended to facilitate injection, the following:

i)  Resistivity, spontaneous potential, porosity, and gamma ray logs before the casing is installed;

ii)  Fracture finder logs; and

iii)  A cement bond, temperature, or density log after the casing is set and cemented.

e)  At a minimum, the following information concerning the injection formation must be determined or calculated for new Class I injection wells:

1)  Fluid pressure;

2)  Temperature;

3)  Fracture pressure;

4)  Other physical and chemical characteristics of the injection matrix; and

5)  Physical and chemical characteristics of the formation fluids.

(Source: Amended at 31 Ill. Reg. 1281, effective December 20, 2006)

Section 730.113 Operating, Monitoring, and Reporting Requirements

a)  Operating Requirements. Operating requirements must, at a minimum, specify the following:

1)  That, except during stimulation, injection pressure at the wellhead must not exceed a maximum that must be calculated so as to assure that the pressure in the injection zone during injection does not initiate new fractures or propagate existing fractures in the injection zone. In no case must injection pressure initiate fractures in the confining zone or cause the movement of injection or formation fluids into an underground source of drinking water;

2)  That injection between the outermost casing protecting underground sources of drinking water and the well bore is prohibited; and

3)  That, unless an alternative to a packer has been approved pursuant to Section 730.112(c), the annulus between the tubing and the long string of casings must be filled with a fluid approved by permit condition, and a pressure prescribed by permit condition must be maintained on the annulus.

b)  Monitoring Requirements. Monitoring requirements must, at a minimum, include all of the following:

1)  The analysis of the injected fluids with sufficient frequency to yield representative data of their characteristics;

2)  Installation and use of continuous recording devices to monitor injection pressure, flow rate, and volume, and the pressure on the annulus between the tubing and the long string of casing;

3)  A demonstration of mechanical integrity pursuant to Section 730.108 at least once every five years during the life of the well; and

4)  The type, number, and location of wells within the area of review to be used to monitor any migration of fluids into and pressure in the underground sources of drinking water, the parameters to be measured, and the frequency of monitoring.

c)  Reporting Requirements. Reporting requirements must, at a minimum, include:

1)  Quarterly reports to the Agency on each of the following:

A)  The physical, chemical, and other relevant characteristics of injection fluids;

B)  The monthly average, maximum, and minimum values for injection pressure, flow rate and volume, and annular pressure; and

C)  The results of monitoring prescribed pursuant to subsection (b)(4).

2)  Reporting the results, with the first quarterly report after the completion of each of the following:

A)  Periodic tests of mechanical integrity;

B)  Any other test of the injection well conducted by the permittee if required by permit condition; and

C)  Any well work over.

d)  Ambient Monitoring

1)  Based on a site-specific assessment of the potential for fluid movement from the well or injection zone and on the potential value of monitoring wells to detect such movement, the Agency must require the owner or operator to develop a monitoring program. At a minimum, the Agency must require monitoring of the pressure buildup in the injection zone annually, including at a minimum, a shut down of the well for a time sufficient to conduct a valid observation of the pressure fall-off curve.

2)  When prescribing a monitoring system the Agency may also require:

A)  Continuous monitoring for pressure changes in the first aquifer overlying the confining zone. When such a well is installed, the owner or operator must, on a quarterly basis, sample the aquifer and analyze for constituents specified by permit condition;

B)  The use of indirect, geophysical techniques to determine the position of the waste front, the water quality in a formation designated by permit condition or to provide other site-specific data;

C)  Periodic monitoring of the ground water quality in the first aquifer overlying the injection zone;

D)  Periodic monitoring of the ground water quality in the lowermost USDW; and

E)  Any additional monitoring necessary to determine whether fluids are moving into or between USDWs.

BOARD NOTE: Derived from 40 CFR 146.13 (2017).

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

Section 730.114 Information to be Considered by the Agency

This Section sets forth the information that must be considered by the Agency in authorizing a Class I injection well. For an existing or converted new Class I injection well, the Agency may rely on the existing permit file for those items of information listed below which are current and accurate in the file. For a newly drilled Class I injection well, the Agency must require the submission of all the information listed below. For both existing and new Class I injection wells, certain maps, cross-sections, tabulations of wells within the area of review, and other data may be included in the application by reference, provided they are current, readily available to the Agency (for example, in the Agency’s files) and sufficiently identified to be retrieved.

a)  Prior to the issuance of a permit for an existing Class I injection well to operate or the construction or conversion of a new Class I injection well, the Agency must consider the following:

1)  Information required in 35 Ill. Adm. Code 702.120 through 702.124 and 704.161(c);

2)  A map showing the injection well for which a permit is sought and the applicable area of review. Within the area of review, the map must show the number, or name, and location of all producing wells, injection wells, abandoned wells, dry holes, surface bodies of water, springs, mines (surface and subsurface), quarries, water wells, and other pertinent surface features including residences and roads. The map should also show faults, if known or suspected. Only information of public record is required to be included on this map;

3)  A tabulation of data on all wells within the area of review that penetrate into the proposed injection zone. Such data must include a description of each well’s type, construction, date drilled, location, depth, record of plugging or completion, and any additional information the Agency may require;

4)  Maps and cross-sections indicating the general vertical and lateral limits of all underground sources of drinking water within the area of review, their position relative to the injection formation, and the direction of water movement, where known, in each underground source of drinking water that may be affected by the proposed injection;

5)  Maps and cross-sections detailing the geologic structure of the local area;

6)  Generalized maps and cross-sections illustrating the regional geologic setting;

7)  Proposed operating data, including the following information:

A)  The average and maximum daily rate and volume of the fluid to be injected;

B)  The average and maximum injection pressure; and

C)  The source and an analysis of the chemical, physical, radiological, and biological characteristics of injection fluids;

8)  A proposed formation testing program to obtain an analysis of the chemical, physical, and radiological characteristics of and other information on the receiving formation;

9)  A proposed stimulation program;

10)  The proposed injection procedure;

11)  Schematic or other appropriate drawings of the surface and subsurface construction details of the system;

12)  Contingency plans to cope with all shut-ins or well failures so as to prevent migration of fluids into any underground source of drinking water;

13)  Plans (including maps) for meeting the monitoring requirements in Section 730.113(b);

14)  For wells within the area of review that penetrate the injection zone but are not properly completed or plugged, the corrective action proposed to be taken pursuant to 35 Ill. Adm. Code 704.193;

15)  Construction procedures including a cementing and casing program; logging procedures; deviation checks; and a drilling, testing, and coring program; and

16)  A certificate that the applicant has assured, through a performance bond or other appropriate means, the resources necessary to close, plug, or abandon the well as required by 35 Ill. Adm. Code 704.189.

b)  Prior to granting approval for the operation of a Class I injection well, the Agency must consider the following information:

1)  All available logging and testing program data on the well;

2)  A demonstration of mechanical integrity pursuant to Section 730.108;

3)  The anticipated maximum pressure and flow rate at that the permittee will operate;

4)  The results of the formation testing program;

5)  The actual injection procedure;

6)  The compatibility of injected waste with fluids in the injection zone and minerals in both the injection zone and the confining zone; and

7)  The status of corrective action on defective wells in the area of review.

c)  Prior to granting approval for the plugging and abandonment of a Class I injection well, the Agency must consider the following information:

1)  The type and number of plugs to be used;

2)  The placement of each plug including the elevation of the top and bottom;

3)  The type and grade and quantity of cement to be used;

4)  The method for placement of the plugs; and

5)  The procedure to be used to meet the requirements of Section 730.110(c).

(Source: Amended at 31 Ill. Reg. 1281, effective December 20, 2006)

SUBPART C: CRITERIA AND STANDARDS APPLICABLE TO CLASS II INJECTION WELLS

Section 730.121 Adoption of Criteria and Standards Applicable to Class II Injection Wells by the Illinois Department of Natural Resources, Office of Mines and Minerals

The criteria and standards for Class II injection wells will be adopted by the Illinois Department of Natural Resources, Office of Mines and Minerals pursuant to Section 1425 of the SDWA (42 USC 300h-4).

BOARD NOTE: This Section corresponds with subpart C of 40 CFR 146 (2011).

(Source: Amended at 36 Ill. Reg. 1661, January 20, 2012)

SUBPART D: CRITERIA AND STANDARDS APPLICABLE TO CLASS III INJECTION WELLS

Section 730.131 Applicability

This Subpart D establishes criteria and standards for underground injection control programs to regulate Class III injection wells.

(Source: Amended at 31 Ill. Reg. 1281, effective December 20, 2006)

Section 730.132 Construction Requirements

a)  A new Class III injection well must be cased and cemented to prevent the migration of fluids into or between underground sources of drinking water. The Agency may waive the cementing requirements for a new well in existing projects or portions of existing projects if it has substantial evidence that no contamination of underground sources of drinking water would result. The casing and cement used in the construction of each newly drilled well must be designed for the life expectancy of the well. In determining and specifying casing and cementing requirements, the following factors must be considered:

1)  The depth to the injection zone;

2)  The injection pressure, external pressure, internal pressure, axial loading, etc.;

3)  The hole size;

4)  The size and grade of all casing strings (wall thickness, diameter, nominal weight, length, joint specification, and construction material);

5)  The corrosiveness of injected fluids and formation fluids;

6)  The lithology of injection and confining zones; and

7)  The type and grade of cement.

b)  Appropriate logs and other tests must be conducted during the drilling and construction of a new Class III injection well. A descriptive report interpreting the results of such logs and tests must be prepared by a knowledgeable log analyst and submitted to the Agency. The logs and tests appropriate to each type of Class III injection well must be determined based on the intended function, depth, construction, and other characteristics of the well; the availability of similar data in the area of the drilling site; and the need for additional information that may arise from time to time as the construction of the well progresses. Deviation checks must be conducted on all holes where pilot holes and reaming are used, unless the hole will be cased and cemented by circulating cement to the surface. If deviation checks are necessary, they must be conducted at sufficiently frequent intervals to assure that vertical avenues for fluid migration in the form of diverging holes are not created during drilling.

c)  If the injection zone is a formation that is naturally water-bearing, the following information concerning the injection zone must be determined or calculated for a new Class III injection well or project:

1)  The fluid pressure;

2)  The fracture pressure; and

3)  The physical and chemical characteristics of the formation fluids.

d)  If the injection formation is not a water-bearing formation, the information in subsection (c)(2) must be submitted.

e)  If injection is into a formation that contains water with less than 10,000 mg/ℓ TDS, monitoring wells must be completed into the injection zone and into any underground sources of drinking water above the injection zone that could be affected by the mining operation. These wells must be located in such a fashion as to detect any excursion of injection fluids, process by-products, or formation fluids outside the mining area or zone. If the operation may be affected by subsidence or catastrophic collapse, the monitoring wells must be located so that they will not be physically affected.

f)  If injection is into a formation that does not contain water with less than 10,000 mg/ℓ TDS, no monitoring wells are necessary in the injection stratum.

g)  If the injection well penetrates a USDW in an area subject to subsidence or catastrophic collapse, an adequate number of monitoring wells must be completed into the USDW to detect any movement of injected fluids, process by-products, or formation fluids into the USDW. The monitoring wells must be located outside the physical influence of the subsidence or catastrophic collapse.

h)  In determining the number, location, construction, and frequency of monitoring of the monitoring wells the following criteria must be considered:

1)  The population relying on the USDW affected or potentially affected by the injection operation;

2)  The proximity of the injection operation to points of withdrawal of drinking water;

3)  The local geology and hydrology;

4)  The operating pressures and whether a negative pressure gradient is being maintained;

5)  The nature and volume of the injected fluid, the formation water, and the process by-products; and

6)  The injection well density.

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

Section 730.133 Operating, Monitoring, and Reporting Requirements

a)  Operating Requirements. Operating requirements prescribed must, at a minimum, specify each of the following:

1)  That, except during well stimulation, the injection pressure at the wellhead must be calculated so as to assure that the pressure in the injection zone during injection does not initiate new fractures or propagate existing fractures in the injection zone. In no case must injection pressure initiate fractures in the confining zone or cause the migration of injection or formation fluids into an underground source of drinking water; and

2)  That injection between the outermost casing protecting underground sources of drinking water and the well bore is prohibited.

b)  Monitoring Requirements

1)  Monitoring requirements must, at a minimum, specify the following information:

A)  Monitoring of the nature of injected fluids with sufficient frequency to yield representative data on its characteristics. Whenever the injection fluid is modified to the extent that the analysis required by Section 730.134(a)(7)(C) is incorrect or incomplete, the owner or operator must provide the Agency with a new analysis as required by Section 730.134(a)(7)(C);

B)  Monitoring of injection pressure and either flow rate or volume semimonthly, or metering and daily recording of injected and produced fluid volumes, as appropriate;

C)  Demonstration of mechanical integrity pursuant to Section 730.108 at least once every five years during the life of the well for salt solution mining;

D)  Monitoring of the fluid level in the injection zone semi-monthly, where appropriate, and monitoring of the parameters chosen to measure water quality in the monitoring wells required by Section 730.132(e) semi-monthly; and

E)  Quarterly monitoring of wells required by Section 730.132(g).

2)  A Class III injection well may be monitored on a field or project basis, rather than on an individual well basis, by manifold monitoring. Manifold monitoring may be used in cases of facilities consisting of more than one injection well operating with a common manifold. Separate monitoring systems for each well are not required provided the owner or operator demonstrates that manifold monitoring is comparable to individual well monitoring.

c)  Reporting Requirements

1)  Reporting requirements must, at a minimum, include the following information:

A)  Quarterly reporting to the Agency on required monitoring; and

B)  Results of mechanical integrity and any other periodic test required by the Agency reported with the first regular quarterly report after the completion of the test.

2)  Monitoring may be reported on a project or field basis rather than individual well basis where manifold monitoring is used.

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

Section 730.134 Information to be Considered by the Agency

This Section sets forth information that must be considered by the Agency in authorizing a Class III injection well. Certain maps, cross-sections, tabulations of wells within the area of review, and other data may be included in the application by reference provided they are current, readily available to the Agency (for example, in the Agency’s files) and sufficiently identified to be retrieved.

a)  Prior to the issuance of a permit to operate an existing Class III injection well or area or for the construction of a new Class III injection well, the Agency must consider the following:

1)  The information required in 35 Ill. Adm. Code 702.120 through 702.124 and 704.161(c);

2)  A map showing the injection well or project area for which the permit is sought and the applicable area of review. Within the area of review, the map must show the number or name and location of all existing producing wells, injection wells, abandoned wells, dry holes, public water systems, and water wells. The map may also show surface bodies of waters, mines (surface and subsurface), quarries and other pertinent surface features including residences and roads, and faults if known or suspected. Only information of public record and pertinent information known to the applicant is required to be included on this map;

3)  A tabulation of data reasonably available from public records or otherwise known to the applicant on wells within the area of review included on the map required pursuant to subsection (a)(2) that penetrate the proposed injection zone. Such data must include a description of each well’s type, construction, date drilled, location, depth, record of plugging and completion, and any additional information the Agency may require. In cases where the information would be repetitive and the wells are of similar age, type, and construction the Agency may elect to only require data on a representative number of wells;

4)  Maps and cross-sections indicating the vertical limits of all underground sources of drinking water within the area of review, their position relative to the injection formation and the direction of water movements, where known, in every underground source of drinking water that may be affected by the proposed injection;

5)  Maps and cross-sections detailing the geologic structure of the local area;

6)  Generalized map and cross-sections illustrating the regional geologic setting;

7)  Proposed operating data, as follows:

A)  The average and maximum daily rate and volume of fluid to be injected;

B)  The average and maximum injection pressure; and

C)  Qualitative analysis and ranges in concentrations of all constituents of injected fluids. The applicant may request confidentiality as specified in 35 Ill. Adm. Code 101.107. If the information is proprietary an applicant may, in lieu of the ranges in concentrations, choose to submit maximum concentrations that must not be exceeded. In such a case the applicant must retain records of the undisclosed concentrations and provide them upon request to the Agency as part of any enforcement investigation;

8)  A proposed formation testing program to obtain the information required by Section 730.132(c);

9)  A proposed stimulation program;

10)  The proposed injection procedure;

11)  Schematic or other appropriate drawings of the surface and subsurface construction details of the system;

12)  Plans (including maps) for meeting the monitoring requirements of Section 730.133(b);

13)  Expected changes in pressure, native fluid displacement, direction of movement of injection fluid;

14)  Contingency plans to cope with all shut-ins or well failures so as to prevent the migration of contaminating fluids into underground sources of drinking water;

15)  A certificate that the applicant has assured, through a performance bond or other appropriate means, the resources necessary to close, plug, or abandon the well as required by 35 Ill. Adm. Code 704.189; and

16)  The corrective action proposed to be taken pursuant to 35 Ill. Adm. Code 704.193.

b)  Prior to granting approval for the operation of a Class III injection well, the Agency must consider the following information:

1)  All available logging and testing data on the well;

2)  A satisfactory demonstration of mechanical integrity for all new wells and for all existing salt solution pursuant to Section 730.108;

3)  The anticipated maximum pressure and flow rate at which the permittee will operate;

4)  The results of the formation testing program;

5)  The actual injection procedures; and

6)  The status of corrective action on defective wells in the area of review.

c)  Prior to granting approval for the plugging and abandonment of a Class III injection well, the Agency must consider the following information:

1)  The type and number of plugs to be used;

2)  The placement of each plug including the elevation of the top and bottom;

3)  The type, grade, and quantity of cement to be used;

4)  The method of placement of the plugs; and

5)  The procedure to be used to meet the requirements of Section 730.110(c).

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

SUBPART F: CRITERIA AND STANDARDS APPLICABLE TO CLASS V INJECTION WELLS

Section 730.151 Applicability

This Subpart F sets forth criteria and standards for underground injection control programs to regulate all injection not regulated in Subparts B, D, and E. A Class II injection well, however, is not regulated by this Subpart F.

a)  Generally, a well covered by this Subpart F injects non-hazardous fluids into or above formations that contain underground sources of drinking water. It includes all wells listed in Section 730.105(e) but is not limited to those types of injection wells.

b)  It also includes a well not covered in Class IV that injects radioactive materials listed in table II, column 2 in appendix B to 10 CFR 20 (Water Effluent Concentrations), incorporated by reference in 35 Ill. Adm. Code 720.111(b).

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

730.152 Inventory and Assessment (Repealed)

(Source: Repealed at 18 Ill. Reg. 18391, effective December 20, 1994)

SUBPART G: CRITERIA AND STANDARDS APPLICABLE TO CLASS I HAZARDOUS WASTE INJECTION WELLS

Section 730.161 Applicability and Definitions

a)  This Subpart G establishes criteria and standards for underground injection control programs to regulate Class I hazardous waste injection wells. Unless otherwise noted, this Subpart G supplements the requirements of Subpart A and applies instead of Subpart B to a Class I hazardous waste injection well.

b)  Definitions. The following definitions apply for the purposes of this Subpart G:

“Cone of influence” means that area around the well within which increased injection zone pressures caused by injection into the hazardous waste injection well would be sufficient to drive fluids into a USDW.

“Existing well” means a Class I hazardous waste injection well that had a UIC permit or UIC permit by rule prior to August 25, 1988, or a well that has become a Class I hazardous waste injection well as a result of a change in the definition of the injected waste which would render the waste hazardous pursuant to 35 Ill. Adm. Code 721.103.

“Injection interval” means that part of the injection zone in which the well is screened, or in which the waste is otherwise directly emplaced.

“New well” means any Class I hazardous waste injection well that is not an existing well.

“Transmissive fault or fracture” is a fault or fracture that has sufficient permeability and vertical extent to allow fluids to move between formations.

BOARD NOTE: Derived from 40 CFR 146.61 (2017).

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

Section 730.162 Minimum Criteria for Siting

a)  All Class I hazardous waste injection wells must be sited such that they inject into a formation that is beneath the lowermost formation containing, within 402 meters (one-quarter mile) of the well bore, a USDW.

b)  The siting of a Class I hazardous waste injection well must be limited to an area that is geologically suitable. The Agency must determine geologic suitability based upon its consideration of the following:

1)  An analysis of the structural and stratigraphic geology, the hydrogeology, and the seismicity of the region;

2)  An analysis of the local geology and hydrogeology of the well site, including, at a minimum, detailed information regarding stratigraphy, structure, and rock properties; aquifer hydrodynamics; and mineral resources; and

3)  A determination that the geology of the area can be described confidently and that limits of waste fate and transport can be accurately predicted through the use of models.

c)  Class I hazardous waste injection wells must be sited such that the following is true:

1)  The injection zone has sufficient permeability, porosity, thickness, and area extent to prevent migration of fluids into USDWs; and

2)  The confining zone is as follows:

A)  It is laterally continuous and free of transecting, transmissive faults, or fractures over an area sufficient to prevent the movement of fluids into a USDW; and

B)  It contains at least one formation of sufficient thickness and with lithologic and stress characteristics capable of preventing vertical propagation of fractures.

d)  Alternative Injection Zone Demonstrations

1)  The owner or operator must demonstrate one of the following alternatives:

A)  That the confining zone is separated from the base of the lowermost USDW by at least one sequence of permeable and less permeable strata that will provide an added layer of protection for the USDW in the event of fluid movement in an unlocated borehole or transmissive fault;

B)  That, within the area of review, the piezometric surface of the fluid in the injection zone is less than the piezometric surface of the lowermost USDW, considering density effects, injection pressures, and any significant pumping in the overlying USDW; or

C)  There is no USDW present.

2)  The owner or operator of a site that does not meet the requirements in subsection (d)(1), (d)(2), or (d)(3) may petition the Board for an adjusted standard pursuant to Subpart D of 35 Ill. Adm. Code 104. The Board may grant an adjusted standard approving such a site if it determines that because of site geology, nature of the wastes involved, or other considerations; abandoned boreholes; or other conduits would not cause an endangerment of USDWs. A petition for an adjusted standard pursuant to this subsection (d)(4) must include the following components:

A)  Those portions of a permit application for the particular injection activities and site that are relevant to the Board’s determination; and

B)  Such other relevant information that the Board may by order require pursuant to 35 Ill. Adm. Code 104.228.

BOARD NOTE: Derived from 40 CFR 146.62 (2017).

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

Section 730.163 Area of Review

For the purposes of Class I hazardous waste injection wells, this Section applies instead of Section 730.106. The area of review for a Class I hazardous waste injection well must be a two-mile radius around the well bore. The Agency may specify by permit condition a larger area of review in the UIC permit if it determines in writing that the larger area is necessary based on the calculated cone of influence of the well.

BOARD NOTE: Derived from 40 CFR 146.63 (2005).

(Source: Amended at 31 Ill. Reg. 1281, effective December 20, 2006)

Section 730.164 Corrective Action for Wells in the Area of Review

For the purposes of a Class I hazardous waste injection well, this Section applies instead of 35 Ill. Adm. Code 704.193 and Section 730.107.

a)  The owner or operator of a Class I hazardous waste injection well must, as part of the permit application, submit a plan to the Agency outlining the protocol used to accomplish both of the following:

1)  Identify all wells penetrating the confining zone or injection zone within the area of review; and

2)  Determine whether wells are adequately completed or plugged.

b)  The owner or operator of a Class I hazardous waste injection well must identify the location of all wells within the area of review that penetrate the injection zone or the confining zone and must submit both of the following, as required in Section 730.170(a):

1)  A tabulation of all wells within the area of review that penetrate the injection zone or the confining zone; and

2)  A description of each well or type of well and any records of its plugging or completion.

c)  For wells that the Agency determines are improperly plugged, completed, or abandoned or for which plugging or completion information is unavailable, the applicant must also submit a plan consisting of such steps or modification as are necessary to prevent movement of fluids into or between USDWs. Where the plan is adequate, the Agency must incorporate it into the permit as a condition. Where the Agency’s review of an application indicates the permittee’s plan is inadequate (based at a minimum on the factors in subsection (e)), the Agency must do the appropriate of the following:

1)  It must require the applicant to revise the plan;

2)  It must prescribe a plan for corrective action as a condition of the permit; or

3)  It must deny the application.

d)  Requirements

1)  Existing Injection Wells. Any permit issued for an existing Class I hazardous waste injection well requiring corrective action other than pressure limitations must include a compliance schedule pursuant to 35 Ill. Adm. Code 702.162 requiring any corrective action accepted or prescribed pursuant to subsection (c). Any such compliance schedule must provide for compliance no later than two years following issuance of the permit and must require observance of appropriate pressure limitations pursuant to subsection (d)(3) until all other corrective action measures have been implemented.

2)  New Injection Wells. No owner or operator of a new Class I hazardous waste injection well may begin injection until all corrective actions required pursuant to this Section have been taken.

3)  The Agency may require pressure limitations instead of plugging. If pressure limitations are used instead of plugging, the Agency must require as a permit condition that injection pressure be limited so that pressure in the injection zone at the site of any improperly completed or abandoned well within the area of review would not be sufficient to drive fluids into or between USDWs. This pressure limitation must satisfy the corrective action requirements. Alternatively, such injection pressure limitation may be made part of a compliance schedule pursuant to 35 Ill. Adm. Code 702.162 and may be required to be maintained until all other required corrective actions have been implemented.

e)  The Agency must consider the following criteria and factors in determining the adequacy of corrective action proposed by the applicant pursuant to subsection (c) and in determining the additional steps needed to prevent fluid movement into and between USDWs:

1)  The nature and volume of injected fluid;

2)  The nature of native fluids or byproducts of injection;

3)  Geology;

4)  Hydrology;

5)  The history of the injection operation;

6)  Any completion and plugging records;

7)  The closure procedures in effect at the time the well was closed;

8)  Any hydraulic connections with USDWs;

9)  The reliability of the procedures used to identify abandoned wells; and

10)  Any other factors that might affect the movement of fluids into or between USDWs.

BOARD NOTE: Derived from 40 CFR 146.64 (2017).

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

Section 730.165 Construction Requirements

a)  General. All existing and new Class I hazardous waste injection wells must be constructed and completed to accomplish each of the following:

1)  Prevent the movement of fluids into or between USDWs or into any unauthorized zones;

2)  Permit the use of appropriate testing devices and workover tools; and

3)  Permit continuous monitoring of injection tubing and long string casing as required pursuant to Section 730.167(f);

b)  Compatibility. All well materials must be compatible with fluids with which the materials may be expected to come into contact. The owner or operator must employ any compatibility testing method specified by permit condition. The owner or operator may otherwise refer to “Technical Assistance Document: Corrosion, Its Detection and Control in Injection Wells”, USEPA publication number EPA-570/9-87-002, incorporated by reference at 35 Ill. Adm. Code 720.111.

c)  Casing and Cementing New Wells

1)  Casing and cement used in the construction of each newly drilled well must be designed for the life expectancy of the well, including the post-closure care period. The casing and cementing program must be designed to prevent the movement of fluids into or between USDWs, and to prevent potential leaks of fluids from the well. The Agency must consider the following information as required by Section 730.170 in determining and specifying casing and cementing requirements:

A)  The depth to the injection zone;

B)  The injection pressure, external pressure, internal pressure, and axial loading;

C)  The hole size;

D)  The size and grade of all casing strings (well thickness, diameter, nominal weight, length, joint specification, and construction material);

E)  The corrosiveness of injected fluid, formation fluids, and temperature;

F)  The lithology of the injection and confining zones;

G)  The type or grade of cement; and

H)  The quantity and chemical composition of the injected fluid.

2)  One surface casing string must, at a minimum, extend into the confining bed below the lowest formation that contains a USDW and be cemented by circulating cement from the base of the casing to the surface, using a minimum of 120 percent of the calculated annular volume. The Agency may require more than 120 percent when the geology or other circumstances warrant it.

3)  At least one long string casing, using a sufficient number of centralizers, must extend to the injection zone and must be cemented by circulating cement to the surface in one or more stages:

A)  Of sufficient quantity and quality to withstand the maximum operating pressure; and

B)  In a quantity no less than 120 percent of the calculated volume necessary to fill the annular space. The Agency must require more than 120 percent when the geology or other circumstances warrant it.

4)  Circulation of cement may be accomplished by staging. The Agency may approve an alternative method of cementing in cases where the cement cannot be recirculated to the surface, provided the owner or operator can demonstrate by using logs that the cement is continuous and does not allow fluid movement behind the well bore.

5)  Casings, including any casing connections, must be rated to have sufficient structural strength to withstand both of the following conditions for the design life of the well:

A)  The maximum burst and collapse pressures that may be experienced during the construction, operation, and closure of the well; and

B)  The maximum tensile stress that may be experienced at any point along the length of the casing during the construction, operating, and closure of the well.

6)  At a minimum, cement and cement additives must be of sufficient quality and quantity to maintain integrity over the design life of the well.

d)  Tubing and Packer

1)  All Class I hazardous waste injection wells must inject fluids through tubing with a packer set at a point specified by permit condition.

2)  In determining and specifying requirements for tubing and packer, the following factors must be considered:

A)  The depth of setting;

B)  The characteristics of injection fluid (chemical content, corrosiveness, temperature, and density);

C)  The injection pressure;

D)  The annular pressure;

E)  The rate (intermittent or continuous), temperature, and volume of injected fluid;

F)  The size of casing; and

G)  The tubing tensile, burst, and collapse strengths.

3)  The Agency may approve the use of a fluid seal if it determines in writing that the following conditions are met:

A)  The operator demonstrates that the seal will provide a level of protection comparable to a packer;

B)  The operator demonstrates that the staff is, and will remain, adequately trained to operate and maintain the well and to identify and interpret variations in parameters of concern;

C)  The permit contains specific limitations on variations in annular pressure and loss of annular fluid;

D)  The design and construction of the well allows continuous monitoring of the annular pressure and mass balance of annular fluid; and

E)  A secondary system is used to monitor the interface between the annulus fluid and the injection fluid and the permit contains requirements for testing the system every three months and recording the results.

BOARD NOTE: Derived from 40 CFR 146.65 (2017).

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

Section 730.166 Logging, Sampling, and Testing Prior to New Well Operation

a)  During the drilling and construction of a new Class I hazardous waste injection well, the owner or operator must run appropriate logs and tests to determine or verify the depth, thickness, porosity, permeability, rock type, and the salinity of any entrained fluids in, all relevant geologic units to assure conformance with performance standards set forth in Section 730.165 and to establish accurate baseline data against which future measurements may be compared. A descriptive report interpreting results of such logs and tests must be prepared by a knowledgeable log analyst and submitted to the Agency. At a minimum, such logs and tests must include the following information:

1)  Deviation checks during drilling on all holes constructed by drilling a pilot hole that is enlarged by reaming or another method. Such checks must be at sufficiently frequent intervals to determine the location of the borehole and to assure that vertical avenues for fluid movement in the form of diverging holes are not created during drilling; and

2)  Such other logs and tests as may be needed after taking into account the availability of similar data in the area of the drilling site, the construction plan, and the need for additional information that may arise from time to time as the construction of the well progresses. At a minimum, the following logs must be required in the indicated situations:

A)  Upon installation of the surface casing, the following information:

i)  Resistivity, spontaneous potential, and caliber logs before the casing is installed; and

ii)  A cement bond and variable density log, and a temperature log after the casing is set and cemented; and

B)  Upon installation of the long string casing, the following information:

i)  Resistivity, spontaneous potential, porosity, caliper, gamma ray, and fracture finder logs before the casing is installed; and

ii)  A cement bond and variable density log, and a temperature log after the casing is set and cemented; and

C)  The Agency must allow the use of an alternative to the above logs when an alternative will provide equivalent or better information; and

3)  A mechanical integrity test consisting of the following:

A)  A pressure test with liquid or gas;

B)  A radioactive tracer survey;

C)  A temperature or noise log;

D)  A casing inspection log, if required by permit condition; and

E)  Any other test required by permit condition.

b)  Whole cores or sidewall cores of the confining and injection zones and formation fluid samples from the injection zone must be taken. The Agency may accept cores from nearby wells if the owner or operator can demonstrate that core retrieval is not possible and that such cores are representative of conditions at the well. The Agency may require the owner or operator to core other formations in the borehole.

c)  The fluid temperature, pH, conductivity, pressure, and the static fluid level of the injection zone must be recorded.

d)  At a minimum, the following information concerning the injection and confining zones must be determined or calculated for Class I hazardous waste injection wells:

1)  The fracture pressure;

2)  Other physical and chemical characteristics of the injection and confining zones; and

3)  The physical and chemical characteristics of the formation fluids in the injection zone.

e)  Upon completion, but prior to operation, the owner or operator must conduct the following tests to verify hydrogeologic characteristics of the injection zone:

1)  A pump test; or

2)  Injectivity tests.

f)  The Agency must have the opportunity to witness all logging and testing required by this Subpart G. The owner or operator must submit a schedule of such activities to the Agency not less than 30 days prior to conducting the first test.

BOARD NOTE: Derived from 40 CFR 146.66 (2005).

(Source: Amended at 31 Ill. Reg. 1281, effective December 20, 2006)

Section 730.167 Operating Requirements

a)  Except during stimulation, the owner or operator must assure that injection pressure at the wellhead does not exceed a maximum that must be calculated so as to assure that the pressure in the injection zone during injection does not initiate new fractures or propagate existing fractures in the injection zone. The owner or operator must assure that the injection pressure does not initiate fractures or propagate existing fractures in the confining zone, nor cause the movement of injection or formation fluids into a USDW.

b)  Injection between the outermost casing protecting USDWs and the well bore is prohibited.

c)  The owner or operator must maintain an annulus pressure that exceeds the operating injection pressure, unless the Agency determines in writing that such a requirement might harm the integrity of the well. The fluid in the annulus must be noncorrosive, or must contain a corrosion inhibitor.

d)  The owner or operator must maintain mechanical integrity of the injection well at all times.

e)  Permit requirements for owners or operators of hazardous waste injection wells that inject wastes that have the potential to react with the injection formation to generate gases must include the following:

1)  Conditions limiting the temperature, pH, or acidity of the injected waste; and

2)  Procedures necessary to assure that pressure imbalances that might cause a backflow or blowout do not occur.

f)  The owner or operator must install and use continuous recording devices to monitor each of the following: the injection pressure; the flow rate, volume, and temperature of injected fluids; and the pressure on the annulus between the tubing and the long string casing, and must install and use either of the following:

1)  Automatic alarm and automatic shut-off systems, designed to sound and shut-in the well when pressures and flow rates or other parameters specified by permit condition exceed a range or gradient specified in the permit; or

2)  Automatic alarms, designed to sound when the pressures and flow rates or other parameters exceed a rate or gradient specified in the permit, in cases where the owner or operator certifies that a trained operator will be on-site at all times when the well is operating.

g)  If an automatic alarm or shutdown is triggered, the owner or operator must immediately investigate and identify the cause of the alarm or shutoff without undue delay. If, upon such investigation, the well appears to be lacking mechanical integrity, or if monitoring required pursuant to subsection (f) otherwise indicates that the well may be lacking mechanical integrity, the owner or operator must undertake all of the following actions:

1)  It must stop injecting waste fluids unless authorized by permit condition to continue or resume injection;

2)  It must take all necessary steps to determine the presence or absence of a leak; and

3)  It must notify the Agency within 24 hours after the alarm or shutdown.

h)  If a loss of mechanical integrity is discovered pursuant to subsection (g) or during periodic mechanical integrity testing, the owner or operator must undertake all of the following actions:

1)  It must immediately cease injection of waste fluids;

2)  It must take all steps reasonably necessary to determine whether there may have been a release of hazardous wastes or hazardous waste constituents into any unauthorized zone;

3)  It must notify the Agency within 24 hours after loss of mechanical integrity is discovered;

4)  It must notify the Agency when injection can be expected to resume; and

5)  It must restore and demonstrate mechanical integrity pursuant to Section 730.108 prior to resuming injection of waste fluids.

i)  Whenever the owner or operator obtains evidence that there may have been a release of injected wastes into an unauthorized zone, the following must occur:

1)  The owner or operator must immediately cease injection of waste fluids, and undertake all of the following actions:

A)  It must notify the Agency within 24 hours of obtaining such evidence;

B)  It must take all necessary steps to identify and characterize the extent of any release;

C)  It must comply with any remediation plan specified by permit condition;

D)  It must implement any remediation plan specified by permit condition; and

E)  Where such release is into a USDW currently serving as a water supply, it must place a notice in a newspaper of general circulation.

2)  The Agency must permit the operator to resume injection prior to completing cleanup action if the owner or operator demonstrates that the injection operation will not endanger USDWs.

j)  The owner or operator must notify the Agency and obtain a permit modification prior to conducting any well workover.

BOARD NOTE: Derived from 40 CFR 146.67 (2017).

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

Section 730.168 Testing and Monitoring Requirements

Testing and monitoring requirements must at a minimum include:

a)  Monitoring of the injected wastes.

1)  The owner or operator must develop and follow an approved written waste analysis plan that describes the procedures to be carried out to obtain a detailed chemical and physical analysis of a representative sample of the waste, including the quality assurance procedures used. At a minimum, the plan must specify all of the following:

A)  The parameters for which the waste will be analyzed and the rationale for the selection of these parameters;

B)  The test methods that will be used to test for these parameters; and

C)  The sampling method that will be used to obtain a representative sample of the waste to be analyzed.

2)  The owner or operator must repeat the analysis of the injected wastes as described in the waste analysis plan at frequencies specified in the waste analysis plan and when process or operating changes occur that may significantly alter the characteristics of the waste stream.

3)  The owner or operator must conduct continuous or periodic monitoring of selected parameters as required by permit condition.

4)  The owner or operator must assure that the plan remains accurate and the analyses remain representative.

b)  Hydrogeologic compatibility determination. The owner or operator must submit information demonstrating that the wastestream and its anticipated reaction products will not alter the permeability, thickness, or other relevant characteristics of the confining or injection zones such that they would no longer meet the requirements specified in Section 730.162.

c)  Compatibility of well materials.

1)  The owner or operator must demonstrate that the waste stream will be compatible with the well materials with which the waste is expected to come into contact, and submit to the Agency a description of the methodology used to make that determination. Compatibility, for the purposes of this requirement, is established if contact with injected fluids will not cause the well materials to fail to satisfy any design requirement imposed pursuant to Section 730.165(b).

2)  The Agency must require continuous corrosion monitoring of the construction materials used in the well for wells injecting corrosive waste, and may require such monitoring for other wastes, by any of the following means:

A)  Placing coupons of the well construction materials in contact with the waste stream;

B)  Routing the waste stream through a loop constructed with the material used in the well; or

C)  Using an alternative method approved by permit condition.

3)  If a corrosion monitoring program is required, both of the following must occur:

A)  The test must use materials identical to those used in the construction of the well, and such materials must be continuously exposed to the operating pressures and temperatures (measured at the well head) and flow rates of the injection operation; and

B)  The owner or operator must monitor the materials for loss of mass, thickness, cracking, pitting, and other signs of corrosion on a quarterly basis to ensure that the well components meet the minimum standards for material strength and performance set forth in Section 730.165(b).

d)  Periodic mechanical integrity testing. In fulfilling the requirements of Section 730.108, the owner or operator of a Class I hazardous waste injection well must conduct the mechanical integrity testing as follows:

1)  The long string casing, injection tube, and annular seal must be tested by means of an approved pressure test with a liquid or gas annually and whenever there has been a well workover;

2)  The bottom-hole cement must be tested by means of an approved radioactive tracer survey annually;

3)  An approved temperature, noise, or other approved log must be run at least once every five years to test for movement of fluid along the borehole. The Agency may require such tests whenever the well is worked over;

4)  Running casing inspection logs.

A)  Casing inspection logs must be run whenever the owner or operator conducts a workover in which the injection string is pulled, unless the Agency by permit allows otherwise for either of the following reasons:

i)  Due to well construction or other factors that limit the test’s reliability; or

ii)  Based on the satisfactory results of a casing inspection log run within the previous five years.

B)  The Agency may require by permit that the owner or operator run a casing inspection log if it determines in writing that it has reason to believe that the integrity of the long string casing of the well may be adversely affected by naturally-occurring or man-made events; and

5)  Any other test specified by permit condition in accordance with the procedures set forth in Section 730.108(d) may also be used.

e)  Ambient monitoring.

1)  Based on a site-specific assessment of the potential for fluid movement from the well or injection zone, and on the potential value of monitoring wells to detect such movement, the Agency must require the owner or operator to develop a monitoring program. At a minimum, the Agency must require monitoring of the pressure buildup in the injection zone annually, including at a minimum, a shut down of the well for a time sufficient to conduct a valid observation of the pressure fall-off curve.

2)  When prescribing a monitoring system the Agency may also require any of the following actions that it determines in writing is necessary:

A)  Continuous monitoring for pressure changes in the first aquifer overlying the confining zone. When such a well is installed, the owner or operator must, on a quarterly basis, sample the aquifer, and analyze for constituents specified by permit condition;

B)  The use of indirect, geophysical techniques to determine the position of the waste front, the water quality in a formation designated by permit condition, or to provide other site-specific data;

C)  Periodic monitoring of the groundwater quality in the first aquifer overlying the injection zone;

D)  Periodic monitoring of the ground water quality in the lowermost USDW;

E)  Any additional monitoring necessary to determine whether fluids are moving into or between USDWs; or

F)  Seismicity monitoring, when the Agency has reason to believe that the injection activity may have the capacity to cause seismic disturbances.

BOARD NOTE: Derived from 40 CFR 146.68 (1992) (2005).

(Source: Amended at 31 Ill. Reg. 1281, effective December 20, 2006)

Section 730.169 Reporting Requirements

Reporting requirements must, at a minimum, include the following:

a)  Quarterly reports to the Agency containing the following information:

1)  The maximum injection pressure;

2)  A description of any event that exceeds operating parameters for annulus pressure or injection pressure as specified in the permit;

3)  A description of any event that triggers an alarm or shutdown device required pursuant to Section 730.167(f) and the response taken;

4)  The total volume of fluid injected;

5)  Any change in the annular fluid volume;

6)  The physical, chemical, and other relevant characteristics of injected fluids; and

7)  The results of monitoring prescribed pursuant to Section 730.168; and

b)  Reporting, within 30 days or with the next quarterly report, whichever comes later, the results of any of the following activities:

1)  Periodic tests of mechanical integrity;

2)  Any other test of the injection well conducted by the permittee if required by permit condition; and

3)  Any well workover.

BOARD NOTE: Derived from 40 CFR 146.69 (2005).

(Source: Amended at 31 Ill. Reg. 1281, effective December 20, 2006)

Section 730.170 Information to be Evaluated

This Section sets forth the information that must be evaluated by the Agency in authorizing a Class I hazardous waste injection well. For a new Class I hazardous waste injection well, the owner or operator must submit all the information listed below as part of the permit application. For an existing or converted Class I hazardous waste injection well, the owner or operator must submit all information listed below as part of the permit application except for those items of information that are current, accurate, and available in the existing permit file. For either an existing or a new Class I hazardous waste injection well, certain maps, cross-sections, tabulations of wells within the area of review, and other data may be included in the application by reference, provided they are current, readily available to the Agency (for example, in the permitting Agency’s file), and sufficiently identifiable to be retrieved.

a)  Before issuing a permit for an existing Class I hazardous waste injection well to operate, or the construction or conversion of a new Class I hazardous waste injection well, the Agency must review the following to assure that the requirements of this Part and 35 Ill. Adm. Code 702 and 704 are met:

1)  Information required in 35 Ill. Adm. Code 704.161;

2)  A map showing the injection well for which a permit is sought and the applicable area of review. Within the area of review, the map must show the number or name and location of all producing wells, injection wells, abandoned wells, dry holes, surface bodies of water, springs, mines (surface and subsurface), quarries, water wells, and other pertinent surface features, including residences and roads. The map must also show faults, if known or suspected;

3)  A tabulation of all wells within the area of review that penetrate the proposed injection zone or confining zone. Such data must include a description of each well’s type, construction, date drilled, location, depth, record of plugging or completion, and any additional information the Agency may require;

4)  The protocol followed to identify, locate, and ascertain the condition of abandoned wells within the area of review that penetrate the injection or the confining zones;

5)  Maps and cross-sections indicating the general vertical and lateral limits of all underground sources of drinking water within the area of review, their position relative to the injection formation, and the direction of water movement, where known, in each underground source of drinking water that may be affected by the proposed injection;

6)  Maps and cross-sections detailing the geologic structure of the local area;

7)  Maps and cross-sections illustrating the regional geologic setting;

8)  Proposed operating data, as follows:

A)  The average and maximum daily rate and volume of the fluid to be injected; and

B)  The average and maximum injection pressure;

9)  The proposed formation testing program to obtain an analysis of the chemical, physical, and radiological characteristics of and other information on the injection formation and the confining zone;

10)  The proposed stimulation program;

11)  The proposed injection procedure;

12)  Schematic or other appropriate drawings of the surface and subsurface construction details of the well;

13)  The contingency plan to cope with all shut-ins or well failures so as to prevent migration of fluids into any USDW;

14)  The plans (including maps) for meeting monitoring requirements of Section 730.168;

15)  For wells within the area of review that penetrate the injection zone or the confining zone but are not properly completed or plugged, the corrective action to be taken pursuant to Section 730.164;

16)  The construction procedures including a cementing and casing program, well materials specification and their life expectancy; logging procedures; deviation checks; and a drilling, testing, and coring program; and

17)  A demonstration, pursuant to Subpart G of 35 Ill. Adm. Code 704, that the applicant has the resources necessary to close, plug, or abandon the well and for post-closure care.

b)  Before the Agency grants approval for the operation of a Class I hazardous waste injection well, the owner or operator must submit, and the Agency must review, the following information, which must be included in the completion report:

1)  All available logging and testing program data on the well;

2)  A demonstration of mechanical integrity pursuant to Section 730.168;

3)  The anticipated maximum pressure and flow rate at which the permittee will operate;

4)  The results of the injection zone and confining zone testing program as required in Section 730.170(a)(9);

5)  The actual injection procedure;

6)  The compatibility of injected waste with fluids in the injection zone and minerals in both the injection zone and the confining zone and with the materials used to construct the well;

7)  The calculated area of review based on data obtained during logging and testing of the well and the formation and, where necessary, revisions to the information submitted pursuant to Section 730.170(a)(2) and (a)(3); and

8)  The status of corrective action on wells identified in Section 730.170(a)(15).

c)  Prior to granting approval for the plugging and abandonment (i.e., closure) of a Class I hazardous waste injection well, the Agency must review the information required in Sections 730.171(a)(4) and 730.172(a).

d)  Any permit issued for a Class I hazardous waste injection well for disposal on the premises where the waste is generated must contain a certification by the owner or operator that the following facts are true:

1)  The generator of the hazardous waste has a program to reduce the volume or quantity and toxicity of such waste to the degree determined by the generator to be economically practicable; and

2)  Injection of the waste is that practicable method of disposal currently available to the generator that minimizes the present and future threatto human health and the environment.

BOARD NOTE: Derived from 40 CFR 146.70 (2005).

(Source: Amended at 31 Ill. Reg. 1281, effective December 20, 2006)

Section 730.171 Closure

a)  Closure Plan. The owner or operator of a Class I hazardous waste injection well must prepare, maintain, and comply with a plan for closure of the well that meets the requirements of subsection (d) and is specified by permit condition. The obligation to implement the closure plan survives the termination of a permit or the cessation of injection activities. The requirement to maintain and implement an approved plan is directly enforceable regardless of whether the requirement is a condition of the permit.

1)  The owner or operator must submit the plan as a part of the permit application and, upon approval by the Agency, such plan must be a condition of any permit issued.

2)  The owner or operator must submit any proposed significant revision to the method of closure reflected in the plan for approval by the Agency no later than the date on which notice of closure is required to be submitted to the Agency pursuant to subsection (b).

3)  The plan must assure financial responsibility, as required in 35 Ill. Adm. Code 704.189.

4)  The plan must include the following information:

A)  The type and number of plugs to be used;

B)  The placement of each plug including the evaluation of the top and bottom of each plug;

C)  The type and grade and quantity of material to be used in plugging;

D)  The method of placement of the plugs;

E)  Any proposed test or measure to be made;

F)  The amount, size, and location (by depth) of casing and any other materials to be left in the well;

G)  The method and location where casing is to be parted, if applicable;

H)  The procedure to be used to meet the requirements of subsection (d)(5); and

I)  The estimated cost of closure.

5)  The Agency must modify a closure plan following the procedures of Subpart C of 35 Ill. Adm. Code 702.

6)  An owner or operator of a Class I hazardous waste injection well who stops injection temporarily may keep the well open if the following conditions are fulfilled:

A)  The owner or operator has received authorization from the Agency; and

B)  The owner or operator has described actions or procedures, satisfactory to the Agency, that the owner or operator will take actions to ensure that the well will not endanger USDWs during the period of temporary disuse. These actions and procedures must include compliance with the technical requirements applicable to active injection wells unless otherwise waived by permit condition.

BOARD NOTE: An Agency determination on authorizing keeping the well open is in the nature of a permit determination, and the owner or operator may appeal the Agency’s determination to the Board.

7)  The owner or operator of a well that has ceased operations for more than two years must notify the Agency at least 30 days prior to resuming operation of the well.

b)  Notice of Intent to Close. The owner or operator must notify the Agency at least 60 days before closure of a well.

c)  Closure Report. Within 60 days after closure, or at the time of the next quarterly report (whichever is less), the owner or operator must submit a closure report to the Agency. If the quarterly report is due less than 15 days after completion of closure, then the report must be submitted within 60 days after closure. The report must be certified as accurate by the owner or operator and by the person who performed the closure operation (if other than the owner or operator). Such report must consist of either of the following documents:

1)  A statement that the well was closed in accordance with the closure plan previously submitted and approved by the Agency; or

2)  Where actual closure differed from the plan previously submitted, a written statement specifying the differences between the previous plan and the actual closure.

d)  Standards for Well Closure

1)  Prior to closing the well, the owner or operator must observe and record the pressure decay for a time specified by permit condition. The Agency must analyze the pressure decay and the transient pressure observations conducted pursuant to Section 730.168(e)(1)(A) and determine whether the injection activity has conformed to predicted values.

2)  Prior to well closure, appropriate mechanical integrity testing must be conducted to ensure the integrity of that portion of the long string casing and cement that will be left in the ground after closure. Testing methods may include the following:

A)  Pressure tests with liquid or gas;

B)  Radioactive tracer surveys;

C)  Noise, temperature, pipe evaluation, or cement bond logs; and

D)  Any other test required by permit condition.

3)  Prior to well closure, the well must be flushed with a buffer fluid.

4)  Upon closure, a Class I hazardous waste injection well must be plugged with cement in a manner that will not allow the movement of fluids into or between USDWs.

5)  Placement of the cement plugs must be accomplished by one of the following means:

A)  The Balance Method;

B)  The Dump Bailer Method;

C)  The Two-Plug Method; or

D)  An alternative method, specified by permit condition, that will reliably provide a comparable level of protection.

6)  Each plug used must be appropriately tagged and tested for seal and stability before closure is completed.

7)  The well to be closed must be in a state of static equilibrium with the mud weight equalized top to bottom, either by circulating the mud in the well at least once or by a comparable method prescribed by permit condition, prior to the placement of the cement plugs.

BOARD NOTE: Derived from 40 CFR 146.71 (2017).

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

Section 730.172 Post-Closure Care

a)  The owner or operator of a Class I hazardous waste injection well must prepare, maintain, and comply with a plan for post-closure care that meets the requirements of subsection (b) and is specified by permit condition. The obligation to implement the post-closure plan survives the termination of a permit or the cessation of injection activities. The requirement to maintain an approved plan is directly enforceable regardless of whether the requirement is a condition of the permit.

1)  The owner or operator must submit the plan as a part of the permit application and, upon approval by the Agency, such plan must be a condition of any permit issued.

2)  The owner or operator must submit any proposed significant revision to the plan as appropriate over the life of the well, but no later than the date of the closure report required pursuant to Section 730.171(c).

3)  The plan must assure financial responsibility, as required in Section 730.173.

4)  The plan must include the following information:

A)  The pressure in the injection zone before injection began;

B)  The anticipated pressure in the injection zone at the time of closure;

C)  The predicted time until pressure in the injection zone decays to the point that the well’s cone of influence no longer intersects the base of the lowermost USDW;

D)  The predicted position of the waste front at closure;

E)  The status of any cleanups required pursuant to Section 730.164; and

F)  The estimated cost of proposed post-closure care.

5)  At the request of the owner or operator, or on its own initiative, the Agency may modify the post-closure plan after submission of the closure report following the procedures in 35 Ill. Adm. Code 705.128.

b)  The owner or operator must undertake each of the following activities:

1)  It must continue and complete any cleanup action required pursuant to Section 730.164, if applicable;

2)  It must continue to conduct any groundwater monitoring required under the permit until pressure in the injection zone decays to the point that the well’s cone of influence no longer intersects the base of the lowermost USDW. The Agency must extend the period of post-closure monitoring if it determines in writing that the well may endanger a USDW;

3)  It must submit a survey plat to the local zoning authority designated by permit condition. The plat must indicate the location of the well relative to permanently surveyed benchmarks. A copy of the plat must be submitted to USEPA, Region 5;

4)  It must notify the Illinois Department of Natural Resources, Office of Mines and Minerals, the State Department of Public Health, and any unit of local government authorized to grant permits under the Water Well Construction Code [415 ILCS 30] in the area where the well is located as to the depth and location of the well and the confining zone; and

5)  It must retain, for a period of three years following well closure, records reflecting the nature, composition, and volume of all injected fluids. Owners or operators must deliver the records to the Agency at the conclusion of the retention period.

c)  Each owner of a Class I hazardous waste injection well, and the owner of the surface or subsurface property on or in which a Class I hazardous waste injection well is located, must record a notation on the deed to the facility property or on some other instrument that is normally examined during title search that will in perpetuity provide any potential purchaser of the property the following information:

1)  The fact that land has been used to manage hazardous waste;

2)  The names of the Illinois Department of Natural Resources, Office of Mines and Minerals and the local zoning authority with which the plat was filed, as well as the address of USEPA Region 5; and

3)  The type and volume of waste injected, the injection interval or intervals into which it was injected, and the period over which injection occurred.

d)  In addition to the requirements stated in this Section, each owner of a Class I hazardous waste injection well must comply with any other State or federal law or local ordinance that requires the reporting of any potential environmental or physical impairment of real property to subsequent or prospective owners.

BOARD NOTE: The Responsible Property Transfer Act of 1988 [765 ILCS 90] (RPTA) formerly required the disclosure and recordation of any environmental impairment of real property in Illinois. The General Assembly repealed that statute in P.A. 92-299, Section 5, effective August 9, 2001. Section 10 of that repeal provided for continued maintenance of documents prepared and recorded under RPTA prior to its repeal.

BOARD NOTE: Derived from 40 CFR 146.72 (2017).

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

Section 730.173 Financial Responsibility for Post-Closure Care

The owner or operator must demonstrate and maintain financial responsibility for post-closure care by using a trust fund, surety bond, letter of credit, financial test, insurance, or corporate guarantee that meets the specifications for the mechanisms and instruments revised as appropriate to cover closure and post-closure care in Subpart G of 35 Ill. Adm. Code 704. The amount of the funds available must be no less than the amount identified in Section 730.172(a)(4)(F). The obligation to maintain financial responsibility for post-closure care survives the termination of a permit or the cessation of injection. The requirement to maintain financial responsibility is enforceable whether or not the requirement is a condition of the permit.

BOARD NOTE: Derived from 40 CFR 146.73 (2005).

(Source: Amended at 31 Ill. Reg. 1281, effective December 20, 2006)

SUBPART H: CRITERIA AND STANDARDS APPLICABLE TO CLASS VI WELLS

Section 730.181 Applicability

a)  This Subpart H establishes criteria and standards for Class VI carbon dioxide geologic sequestration injection wells.

b)  This Subpart H applies to any injection well that is used to inject carbon dioxide specifically for the purpose of geologic sequestration.

c)  This Subpart H also applies to the owner or operator of a permit or rule-authorized Class I, Class II, or Class V experimental carbon dioxide injection well that seeks to apply for a Class VI geologic sequestration permit for its well. An owner or operator that seeks to convert an existing Class I, Class II, or Class V experimental injection well to a Class VI geologic sequestration well must demonstrate to the Agency that the well was engineered and constructed to meet the requirements of Section 146.86(a) and to ensure protection of USDWs, in lieu of requirements at Sections 146.86(b) and 146.87(a). The owner or operator of either a Class I injection well that was previously permitted for the purpose of geologic sequestration or a Class V experimental technology injection well that is no longer being used for experimental purposes and which will continue injection of carbon dioxide for the purpose of geologic sequestration must apply for a Class VI permit. A converted well must still meet all other requirements of this Part.

d)  Definitions. The following definitions apply to this Subpart H. To the extent that these definitions conflict with those that appear in 35 Ill. Adm. Code 702.110 or Section 730.103, the definitions of this Section govern for Class VI wells:

“Area of review” means the region surrounding the geologic sequestration project where a USDW may be endangered by the injection activity. The area of review is delineated using computational modeling that accounts for the physical and chemical properties of all phases of the injected carbon dioxide stream and displaced fluids, and is based on available site characterization, monitoring, and operational data, as set forth in Section 730.184.

“Carbon dioxide plume” means the sub-surface three-dimensional extent underground of an injected carbon dioxide stream.

“Carbon dioxide stream” means carbon dioxide that has been captured from an emission source (e.g., a power plant), plus incidental associated substances derived from the source materials and the capture process, and any substances added to the stream to enable or improve the injection process. This Subpart H does not apply to any carbon dioxide stream that meets the definition of a hazardous waste in 35 Ill. Adm. Code 721.103.

“Confining zone” means a geologic formation, a group of formations, or a part of a formation that stratigraphically overlies an injection zone and which acts as barrier to fluid movement. For a Class VI injection well that is operating under a permit that includes alternative injection well depth requirements, “confining zone” means a geologic formation, a group of formations, or a part of a formation that stratigraphically overlies and underlies the injection zone.

“Corrective action” means the use of Agency-approved methods to ensure that wells within an area of review do not serve as conduits for the movement of fluids into a USDW.

“Geologic sequestration” means the long-term containment of a gaseous, liquid, or supercritical carbon dioxide stream in subsurface geologic formations. This term does not apply to carbon dioxide capture or transport.

“Geologic sequestration project” means any of the following three types of injection wells:

An injection well or wells that are used to emplace a carbon dioxide stream beneath the lowermost formation containing a USDW;

An injection well or wells that are used for geologic sequestration of carbon dioxide and which have been granted a permit that includes alternative injection well depth requirements pursuant to requirements at Section 730.195; or

An injection well or wells that are used for geologic sequestration of carbon dioxide and which have received an expansion to the areal extent of an existing Class II enhanced oil recovery or enhanced gas recovery aquifer exemption pursuant to Section 730.104 and 35 Ill. Adm. Code 704.123(d).

A geologic sequestration project includes the subsurface three-dimensional extent of the carbon dioxide plume, the associated area of elevated pressure, and displaced fluids, as well as the surface area above that delineated region.

“Injection zone” means a geologic formation, a group of formations, or a part of a formation that is of sufficient areal extent, thickness, porosity, and permeability to receive carbon dioxide through a well or wells associated with a geologic sequestration project.

“Post-injection site care” means appropriate monitoring and other actions (including corrective action) needed following cessation of injection to ensure that no USDW is endangered, as required under Section 730.193.

“Pressure front” means the zone of elevated pressure that is created by the injection of carbon dioxide into the subsurface. For the purposes of this Subpart H, the pressure front of a carbon dioxide plume refers to a zone where there is a pressure differential sufficient to cause the movement of injected fluids or formation fluids into a USDW.

“Site closure” means the point or time, as determined by the Agency pursuant to Section 730.193, at which the owner or operator of a geologic sequestration site is released from post-injection site care responsibilities.

“Transmissive fault or fracture” means a fault or fracture that has sufficient permeability and vertical extent to allow fluids to move between formations.

BOARD NOTE: This Section corresponds with 40 CFR 146.81 (2017).

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

Section 730.182 Required Class VI Injection Well Permit Information

This Section sets forth the information that the Agency must consider when authorizing a Class VI injection well. For a converted Class I, Class II, or Class V experimental injection well, certain maps, cross-sections, tabulations of wells within the area of review, and other data may be included in the application by reference, provided they are current, readily available to the Agency, and sufficiently identified as to be retrieved. In cases where USEPA issues the permit, all the information in this Section must be submitted to the USEPA, Region 5.

a)  Prior to the issuance of a permit for the construction of a new Class VI injection well or the conversion of an existing Class I, Class II, or Class V injection well to a Class VI injection well, the owner or operator must submit, pursuant to Section 730.191(e), and the Agency must consider, the following:

1)  The information required by 35 Ill. Adm. Code 702.123(a) through (f);

2)  A map showing the injection well for which a permit is sought and the applicable area of review consistent with Section 730.184. Within the area of review, the map must show the number or name and location of all injection wells, producing wells, abandoned wells, plugged wells, or dry holes; deep stratigraphic boreholes; Agency or USEPA-approved subsurface cleanup sites; surface bodies of water, springs, mines (surface and subsurface), quarries, water wells; and other pertinent surface features, including structures intended for human occupancy, state boundaries, and roads. The map should also show faults, if known or suspected. Only information of public record is required to be included on this map;

3)  Information on the geologic structure and hydrogeologic properties of the proposed storage site and overlying formations, including the following documents and information:

A)  Maps and cross sections of the area of review;

B)  The location, orientation, and properties of known or suspected faults and fractures that may transect the confining zones in the area of review and a determination that the faults and fractures would not interfere with containment;

C)  Data on the depth, areal extent, thickness, mineralogy, porosity, permeability, and capillary pressure of the injection and confining zones; including geology and facies changes based on field data, which may include geologic cores, outcrop data, seismic surveys, well logs, and names and lithologic descriptions;

D)  Geomechanical information on fractures, stress, ductility, rock strength, and in-situ fluid pressures within the confining zones;

E)  Information on the seismic history that includes the presence and depth of seismic sources and a determination that the seismicity would not interfere with containment; and

F)  Geologic and topographic maps and cross sections that illustrate regional geology, hydrogeology, and the geologic structure of the local area;

4)  A tabulation of all wells within the area of review that penetrate the injection or confining zones. The tabulated data must include a description of each well’s type, construction, date drilled, location, depth, applicable records of plugging and completion, and any additional information that the Agency may require to evaluate the request for a permit;

5)  Maps and stratigraphic cross sections indicating the general vertical and lateral limits of all USDWs, water wells, and springs within the area of review, their positions relative to the injection zones, and the direction of water movement, where known;

6)  Baseline geochemical data on subsurface formations that includes all USDWs in the area of review;

7)  Proposed operating data for the proposed geologic sequestration site that includes that following items of information:

A)  The average and maximum daily rate and volume or mass, and the total anticipated volume or mass, of the carbon dioxide stream;

B)  The average and maximum injection pressures;

C)  The sources of the carbon dioxide stream; and

D)  An analysis of the chemical and physical characteristics of the carbon dioxide stream;

8)  A proposed program for pre-operational formation testing that fulfills the requirements of Section 730.187 to obtain an analysis of the chemical and physical characteristics of the injection zones and confining zones;

9)  A proposed stimulation program, a description of stimulation fluids to be used, and a determination that stimulation will not interfere with containment;

10)  A proposed procedure to outline steps necessary to conduct injection operation;

11)  Schematics or other appropriate drawings of the surface and subsurface construction details of the well;

12)  Injection well construction procedures that fulfill the requirements of Section 730.186;

13)  A proposed area of review and corrective action plan that fulfills the requirements of Section 730.184;

14)  A demonstration which is sufficient to support an Agency determination that the applicant has met the financial responsibility requirements under Section 730.185;

15)  A proposed testing and monitoring plan, as required by Section 730.190;

16)  A proposed injection well plugging plan, as required by Section 730.192(b);

17)  A proposed post-injection site care and site closure plan, as required by Section 730.193(a);

18)  At the Agency’s discretion, a demonstration of an alternative post-injection site care timeframe required, as required by Section 730.193(c);

19)  A proposed emergency and remedial response plan, as required by Section 730.194(a);

20)  A list of contacts, submitted to the Agency, for those states identified to be within the area of review of the Class VI project based on information provided pursuant to subsection (a)(2); and

21)  Any other information requested by the Agency that would support an Agency determination whether to issue the requested permit.

b)  Pursuant to this Section, and as required by 40 CFR 145.23(f)(13), the Agency must notify any states that the Agency determines are within the area of review of the Class VI project based on information submitted pursuant to subsections (a)(2) and (a)(20) of the permit application in writing.

c)  Prior to granting a permit for the operation of a Class VI injection well, the Agency must consider the following information:

1)  The final area of review based on modeling, using data obtained during the logging and testing of the well and the formation required by subsections (c)(2), (c)(3), (c)(4), (c)(6), (c)(7), and (c)(10);

2)  Any relevant updates to the information on the geologic structure and hydrogeologic properties of the proposed storage site and overlying formations, submitted pursuant to subsection (a)(3), based on data obtained during the logging and testing of the well and the formation required by subsections (c)(3), (c)(4), (c)(6), (c)(7), and (c)(10);

3)  Information on the compatibility of the carbon dioxide stream with fluids in the injection zones and minerals in both the injection and the confining zones, based on the results of the formation testing program, and with the materials used to construct the well;

4)  The results of the formation testing program required by subsection (a)(8);

5)  Final injection well construction procedures that fulfill the requirements of Section 730.186;

6)  The status of any corrective action on wells in the area of review;

7)  All available logging and testing program data on the well required by Section 730.187;

8)  A demonstration of mechanical integrity pursuant to Section 730.189;

9)  Any updates to the proposed area of review and corrective action plan, the testing and monitoring plan, the injection well plugging plan, the post-injection site care and site closure plan, or the emergency and remedial response plan, and any updates to the alternative post-injection site care timeframe demonstration, which the applicant has submitted pursuant to subsection (a), that are necessary to address new information collected during logging and testing of the well and the formation, as required by this Section; and

10)  Any other information requested by the Agency.

d)  An owner or operator which seeks a permit that includes alternative injection well depth requirements to the generally applicable requirement to inject below the lowermost USDW must also refer to Section 730.195 and submit a supplemental report, as required at Section 730.195(a). The supplemental report is not part of the permit application.

BOARD NOTE: This Section corresponds with 40 CFR 146.82 (2017).

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

Section 730.183 Minimum Criteria for Siting

a)  The owner or operator of a Class VI injection well must sufficiently demonstrate to support an Agency determination that the wells will be sited in areas with a suitable geologic system. The owner or operator must sufficiently demonstrate that the geologic system comprises both of the following elements:

1)  An injection zone of sufficient areal extent, thickness, porosity, and permeability to receive the total anticipated volume of the carbon dioxide stream; and

2)  Confining zones free of transmissive faults or fractures and of sufficient areal extent and integrity to contain the injected carbon dioxide stream and displaced formation fluids and allow injection at proposed maximum pressures and volumes without initiating or propagating fractures in the confining zones.

b)  The Agency may require the owner or operator of a Class VI injection well to identify and characterize additional zones that will impede vertical fluid movement; that are free of faults and fractures which may interfere with containment; that allow for pressure dissipation; and that provide additional opportunities for monitoring, mitigation, and remediation.

BOARD NOTE: This Section corresponds with 40 CFR 146.83 (2011).

(Source: Added at 36 Ill. Reg. 1661, January 20, 2012)

Section 730.184 Area of Review and Corrective Action

a)  The area of review is the region surrounding the geologic sequestration project where the injection activity may endanger a USDW. The area of review is delineated using computational modeling that accounts for the physical and chemical properties of all phases of the injected carbon dioxide stream and which is based on available site characterization, monitoring, and operational data.

b)  The owner or operator of a Class VI injection well must prepare, maintain, and comply with a plan to delineate the area of review for a proposed geologic sequestration project; must periodically reevaluate the delineation; and must perform corrective action that meets the requirements of this Section and which is sufficient to support an Agency determination that the corrective action is acceptable. The requirement to maintain and implement an approved plan is directly enforceable regardless of whether the requirement is a condition of the permit. As a part of the permit application to the Agency, the owner or operator must submit an area of review and corrective action plan that includes the following information:

1)  The method that the owner or operator will use for delineating the area of review which meets the requirements of subsection (c), including the model that the owner or operator will use, assumptions that the owner or operator will make, and the site characterization data on which the owner or operator will base the model;

2)  A description of each of the following:

A)  The minimum fixed frequency, not to exceed five years, at which the owner or operator proposes to reevaluate the area of review;

B)  The monitoring and operational conditions that would warrant a reevaluation of the area of review prior to the next scheduled reevaluation as determined by the minimum fixed frequency established pursuant to subsection (b)(2)(A);

C)  How monitoring and operational data (e.g., injection rate, pressure, etc.) will be used to inform an area of review reevaluation; and

D)  How the owner or operator will conduct corrective action to meet the requirements of subsection (d), including the following information:

i)  What corrective action the owner or operator will perform prior to injection;

ii)  What, if any, portions of the area of review the owner or operator will address with corrective action on a phased basis and how that phasing will be determined;

iii)  How the owner or operator will adjust corrective action if there are changes in the area of review; and

iv)  How the owner or operator will guarantee site access for future corrective action.

c)  The owner or operator of a Class VI injection well must perform the following actions to delineate the area of review and identify all wells that require corrective action:

1)  The owner or operator must predict, using existing site characterization, monitoring and operational data, and computational modeling, the projected lateral and vertical migration of the carbon dioxide plume and formation fluids in the subsurface from the commencement of injection activities until the plume movement ceases, until pressure differentials sufficient to cause the movement of injected fluids or formation fluids into a USDW are no longer present, or until the end of a fixed time period determined by the Agency. The model must fulfill the following requirements:

A)  The model must be based on detailed geologic data collected to characterize the injection zones, confining zones and any additional zones; and anticipated operating data, including injection pressures, rates, and total volumes over the proposed life of the geologic sequestration project;

B)  The model must take into account any geologic heterogeneities, other discontinuities, data quality, and their possible impact on model predictions; and

C)  The model must consider potential migration through faults, fractures, and artificial penetrations;

2)  Using methods approved by the Agency, the owner or operator must identify all penetrations, including active and abandoned wells and underground mines, in the area of review that may penetrate the confining zones and must provide a description of each well’s type, construction, date drilled, location, depth, record of plugging and/ or completion, and any additional information the Agency may require; and

3)  The owner or operator must determine which abandoned wells in the area of review have been plugged in a manner that prevents the movement of carbon dioxide or other fluids that may endanger USDWs, including use of materials compatible with the carbon dioxide stream.

d)  The owner or operator of a Class VI injection well must perform corrective action on all wells in the area of review that are determined to need corrective action, using methods designed to prevent the movement of fluid into or between USDWs, including use of materials compatible with the carbon dioxide stream, where appropriate.

e)  At the minimum fixed frequency, not to exceed five years, as specified in the area of review and corrective action plan, or when monitoring and operational conditions warrant, the owner or operator of a Class VI injection well must fulfill each of the following requirements:

1)  The owner or operator must reevaluate the area of review in the same manner specified in subsection (c)(1);

2)  The owner or operator must identify all wells in the reevaluated area of review that require corrective action in the same manner specified in subsection (c);

3)  The owner or operator must perform corrective action on wells requiring corrective action in the reevaluated area of review in the same manner specified in subsection (d); and

4)  The owner or operator must submit an amended area of review and corrective action plan or demonstrate through monitoring data and modeling results sufficiently to support an Agency finding that no amendment to the area of review and corrective action plan is needed. Any amendments to the area of review and corrective action plan must be approved by the Agency, must be incorporated into the permit, and are subject to the permit modification requirements set forth in 35 Ill. Adm. Code 704.262 or 704.264, as appropriate.

f)  The emergency and remedial response plan (as required by Section 730.194) and the demonstration of financial responsibility (as described by Section 730.185) must account for the area of review delineated as specified in subsection (c)(1) or the most recently evaluated area of review delineated pursuant to subsection (e), regardless of whether corrective action in the area of review is phased.

g)  The owner or operator must retain all modeling inputs and data used to support area of review reevaluations under subsection (e) for 10 years.

BOARD NOTE: This Section corresponds with 40 CFR 146.84 (2017).

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

Section 730.185 Financial Responsibility

a)  The owner or operator of an injection well to which this Subpart H applies must demonstrate and maintain financial responsibility that the Agency has determined fulfills the following conditions:

1)  The financial responsibility instruments used must be from the following list of qualifying instruments:

A)  A trust fund;

B)  A surety bond;

C)  A letter of credit;

D)  Insurance;

E)  Self insurance (i.e., the financial test and corporate guarantee);

F)  An escrow account; or

G)  Any other instruments that the Agency determines are satisfactory.

2)  The qualifying instruments must be sufficient to cover the following costs:

A)  The costs of corrective action (that meets the requirements of Section 730.184);

B)  The costs of injection well plugging (that meets the requirements of Section 730.192);

C)  The costs of post-injection site care and site closure (that meets the requirements of Section 730.193); and

D)  The costs of emergency and remedial response (that meets the requirements of Section 730.194).

3)  The financial responsibility instruments must be sufficient to address endangerment of underground sources of drinking water.

4)  The qualifying financial responsibility instruments must comprise protective conditions of coverage.

A)  Protective conditions of coverage must include, at a minimum, cancellation, renewal, and continuation provisions; specifications on when the provider becomes liable following a notice of cancellation if there is a failure to renew with a new qualifying financial instrument, and requirements for the provider to meet a minimum rating, minimum capitalization, and have the ability to pass the bond rating when applicable.

i)  Cancellation. For purposes of this Subpart H, the owner or operator must provide that its financial mechanism may not cancel, terminate, or fail to renew, except for failure to pay that financial instrument. If there is a failure to pay the financial instrument, the financial institution may elect to cancel, terminate, or fail to renew the instrument by sending notice by certified mail to the owner or operator and the Agency. The cancellation must not be final for 120 days after receipt of cancellation notice by the owner or operator and the Agency. The owner or operator must provide an alternative financial responsibility demonstration within 60 days after notice of cancellation, and if an alternate financial responsibility demonstration is not acceptable (or possible), any funds from the instrument being cancelled must be released within 60 days of notification by the Agency.

ii)  Renewal. For purposes of this Subpart H, an owner or operator must renew all financial instruments, if an instrument expires, for the entire term of the geologic sequestration project. The instrument may be automatically renewed, as long as the owner or operator has the option of renewal at the face amount of the expiring instrument. The automatic renewal of an instrument must, at a minimum, provide the holder with the option of renewal at the face amount of the expiring financial instrument.

iii)  Cancellation, termination, or failure to renew may not occur and the financial instrument will remain in full force and effect in the event that any of the following occurs on or before the date of expiration: the Agency deems the facility abandoned; or the permit is revoked or a new permit is denied; closure is ordered by the Agency or a court of competent jurisdiction; the owner or operator is named as debtor in a voluntary or involuntary bankruptcy proceeding under Title 11 of the United States Code; or the amount due on the instrument is fully paid.

B)  This subsection (a)(4)(B) would correspond with 40 CFR 706.85(a)(4)(ii) if such existed. USEPA codified a paragraph (a)(4)(i) without a paragraph (a)(4)(ii). Illinois codification requirements do not allow codification of a subsection level unless multiple subsections exist at that level. This statement maintains structural consistency with the corresponding federal rules.

5)  The qualifying financial responsibility instruments must be approved by the Agency.

A)  The Agency must consider and approve the financial responsibility demonstration for all the phases of the geologic sequestration project prior to issuing a Class VI injection well permit (Section 730.182).

B)  The owner or operator must provide any updated information related to their financial responsibility instruments on an annual basis and if there are any changes, the Agency must evaluate, within a reasonable time, the financial responsibility demonstration to confirm that the instruments used remain adequate for use. The owner or operator must maintain financial responsibility requirements regardless of the status of the Agency’s review of the financial responsibility demonstration.

C)  The Agency must disapprove the use of a financial instrument if the Agency determines that it is not sufficient to meet the requirements of this Section.

6)  The owner or operator may demonstrate financial responsibility by using one or multiple qualifying financial instruments for specific phases of the geologic sequestration project.

A)  In the event that the owner or operator combines more than one instrument for a specific geologic sequestration phase (e.g., well plugging), such combination must be limited to instruments that are not based on financial strength or performance (i.e., self insurance or performance bond), for example trust funds, surety bonds guaranteeing payment into a trust fund, letters of credit, escrow account, and insurance. In this case, it is the combination of mechanisms, rather than the single mechanism, that must provide financial responsibility for an amount at least equal to the current cost estimate.

B)  When using a third-party instrument to demonstrate financial responsibility, the owner or operator must provide a proof that the third-party provider fulfills either of the following:

i)  The provider must have passed financial strength requirements of subsection (b)(6)(E) based on credit ratings; or

ii)  The provider must have met a minimum rating, minimum capitalization, and have the ability to pass the bond rating set forth in subsection (b)(6)(E), when applicable.

C)  An owner or operator using certain types of third-party instruments must establish a standby trust fund to enable the Agency to be party to the financial responsibility agreement without the Agency being the beneficiary of any funds. The standby trust fund must be used along with other financial responsibility instruments (e.g., surety bonds, letters of credit, or escrow accounts) to provide a location to place funds if needed.

D)  An owner or operator may deposit money to an escrow account to cover financial responsibility requirements. This account must segregate funds sufficient to cover estimated costs for Class VI (geologic sequestration) financial responsibility from other accounts and uses.

E)  An owner or operator or its guarantor may use self insurance to demonstrate financial responsibility for geologic sequestration projects if the owner or operator or its guarantor fulfill the following requirements:

i)  The owner or operator or its guarantor must meet a tangible net worth of an amount approved by the Agency;

ii)  The owner or operator or its guarantor must have a net working capital and tangible net worth each at least six times the sum of the current well plugging, post-injection site care, and site closure cost;

iii)  The owner or operator or its guarantor must have assets located in the United States amounting to at least 90 percent of total assets or at least six times the sum of the current well plugging, post injection site care, and site closure cost;

iv)  The owner or operator or its guarantor must submit a report of its bond rating and financial information annually; and

v)  The owner or operator or its guarantor must either have a bond rating test of AAA, AA, A, or BBB, as issued by Standard & Poor’s, or Aaa, Aa, A, or Baa, as issued by Moody’s, or meet all of the following five financial ratio thresholds: a ratio of total liabilities to net worth less than 2.0; a ratio of current assets to current liabilities greater than 1.5; a ratio of the sum of net income plus depreciation, depletion, and amortization to total liabilities greater than 0.1; a ratio of current assets minus current liabilities to total assets greater than 0.1; and a net profit (revenues minus expenses) greater than 0.

F)  An owner or operator that is not able to meet the corporate financial test criteria of subsection (a)(6)(E) may arrange a corporate guarantee by demonstrating that its corporate parent meets the financial test requirements on its behalf. The corporate parent’s demonstration that it meets the financial test requirement is insufficient if it has not also guaranteed to fulfill the obligations for the owner or operator.

G)  An owner or operator may obtain an insurance policy to cover the estimated costs of geologic sequestration activities that require financial responsibility. This insurance policy must be obtained from a third-party provider.

b)  The requirement to maintain adequate financial responsibility and resources is directly enforceable regardless of whether the requirement is a condition of the permit.

1)  The owner or operator must maintain financial responsibility and resources until both of the following events have occurred:

A)  The Agency has received and approved the completed post-injection site care and site closure plan; and

B)  The Agency has approved site closure.

2)  The owner or operator may be released from a financial instrument in the following circumstances:

A)  The owner or operator has completed the phase of the geologic sequestration project for which the financial instrument was required, and the owner or operator has fulfilled all of its financial obligations, as determined by the Agency, including obtaining financial responsibility for the next phase of the geologic sequestration project, if required; or

B)  The owner or operator has submitted a replacement financial instrument, and the owner or operator has received written approval from the Agency that accepts the new financial instrument and which releases the owner or operator from the previous financial assurance instrument.

c)  The owner or operator must have a detailed written estimate, in current dollars, of the cost of performing corrective action on wells in the area of review, plugging the injection wells, post-injection site care, site closure, and emergency and remedial response.

1)  The cost estimate must be performed for each phase separately, and the cost estimate must be based on the costs to the Agency of hiring a third party to perform the required activities. A third party is a party who is not within the corporate structure of the owner or operator.

2)  During the active life of the geologic sequestration project, the owner or operator must adjust the cost estimate for inflation within 60 days prior to the anniversary date of the establishment of the financial instruments used to comply with subsection (a), and the owner or operator must provide this adjustment to the Agency. The owner or operator must also provide to the Agency written updates of adjustments to the cost estimate within 60 days after any amendments to the area of review and corrective action plan (Section 730.184), the injection well plugging plan (Section 730.192), the post-injection site care and site closure plan (Section 730.193), and the emergency and remedial response plan (Section 730.194).

3)  The Agency must approve any decrease or increase to the initial cost estimate. During the active life of the geologic sequestration project, the owner or operator must revise the cost estimate no later than 60 days after any of the following events has occurred: the Agency has approved the request to modify the area of review and corrective action plan (Section 730.184), the Agency has approved the injection well plugging plan (Section 730.192), the Agency has approved the post-injection site care and site closure plan (Section 730.193), or the Agency has approved the emergency and response plan (Section 730.194), if the change in the plan increases the cost. If the change to the plan decreases the cost, any withdrawal of funds must be approved by the Agency. Any decrease to the value of the financial assurance instrument must first be approved by the Agency. The revised cost estimate must be adjusted for inflation as specified at subsection (c)(2).

4)  Within 60 days after an increase in the current cost estimate to an amount greater than the face amount of a financial instrument currently in use, the owner or operator must either cause the face amount to be increased to an amount at least equal to the current cost estimate and submit evidence of that increase to the Agency, or obtain other financial responsibility instruments to cover the increase. Whenever the current cost estimate decreases, the owner or operator may reduce the face amount of the financial assurance instrument to the amount of the current cost estimate only in accordance with a written approval from the Agency.

d)  The owner or operator must notify the Agency by certified mail of adverse financial conditions, such as bankruptcy, that may affect the ability to carry out injection well plugging and post-injection site care and site closure.

1)  In the event that the owner or operator or the third-party provider of a financial responsibility instrument is going through a bankruptcy, the owner or operator must notify the Agency of the proceeding by certified mail within 10 days after commencement of a voluntary or involuntary proceeding under Title 11 of the United States Code that names the owner or operator as debtor.

2)  The guarantor of a corporate guarantee must make the notification to the Agency required by this subsection (d)(2) if the guarantor is named as debtor, as required under the terms of the corporate guarantee.

3)  An owner or operator who fulfills the requirements of subsection (a) by obtaining a trust fund, surety bond, letter of credit, escrow account, or insurance policy will be deemed to be without the required financial assurance in the event of bankruptcy of the trustee or issuing institution or a suspension or revocation of the authority of the trustee institution to act as trustee of the institution issuing the pertinent financial assurance instrument. The owner or operator must establish other financial assurance within 60 days after such an event.

e)  The owner or operator must provide an adjustment of the cost estimate to the Agency within 60 days after notification of an Agency determination during the annual evaluation of the qualifying financial responsibility instruments that the most recent demonstration is no longer adequate to cover the cost of corrective action (as required by Section 730.184), injection well plugging (as required by Section 730.192), post-injection site care and site closure (as required by Section 730.193), and emergency and remedial response (as required by Section 730.194).

f)  The Agency must approve the use and length of pay-in-periods for trust funds or escrow accounts.

BOARD NOTE: This Section corresponds with 40 CFR 146.85 (2017).

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

Section 730.186 Injection Well Construction Requirements

a)  General. The owner or operator must ensure that its Class VI injection wells are constructed and completed to fulfill the following requirements:

1)  The well construction and completion must prevent the movement of fluids into or between USDWs or into any unauthorized zone;

2)  The well construction and completion must permit the use of appropriate testing devices and workover tools; and

3)  The well construction and completion must permit continuous monitoring of the annulus space between the injection tubing and long-string casing.

b)  Casing and cementing of Class VI injection wells.

1)  The casing, cement, and other materials used in the construction of each Class VI injection well must have sufficient structural strength and be designed to last for the life of the geologic sequestration project. All well materials must be compatible with fluids with which the materials may be expected to come into contact, and the owner or operator must submit sufficient documentation to the Agency to support a determination that the casing, cement, and other materials meet or exceed standards developed for these materials by the American Petroleum Institute, ASTM International, or a comparable industry standards organization. The casing and cementing program must be designed to prevent the movement of fluids into or between USDWs. In order to allow the Agency to determine and specify casing and cementing requirements, the owner or operator must provide the following information to the Agency:

A)  The depth to the injection zones;

B)  The injection pressure, external pressure, internal pressure, and axial loading;

C)  The hole size;

D)  The size and grade of all casing strings (the wall thickness, external diameter, nominal weight, length, joint specification, and construction material);

E)  The corrosiveness of the carbon dioxide stream and formation fluids;

F)  The down-hole temperatures;

G)  The lithology of the injection and confining zones;

H)  The type or grade of cement and cement additives; and

I)  The quantity, chemical composition, and temperature of the carbon dioxide stream.

2)  The surface casing must extend through the base of the lowermost USDW and be cemented to the surface through the use of a single or multiple strings of casing and cement.

3)  At least one long-string casing, using a sufficient number of centralizers, must extend to the injection zone and must be cemented by circulating cement to the surface in one or more stages.

4)  The circulation of cement may be accomplished by staging. The Agency must approve an alternative method of cementing when it determines that the cement cannot be recirculated to the surface, provided the owner or operator can demonstrate, by using logs, that the cement does not allow fluid movement behind the well bore.

5)  The cement and cement additives must be compatible with the carbon dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the geologic sequestration project. The integrity and location of the cement must be verified that uses technology capable of evaluating cement quality radially and which identifies the location of channels to ensure that USDWs are not endangered.

c)  Tubing and packer.

1)  The tubing and packer materials used in the construction of a Class VI injection well must be compatible with fluids with which the materials may be expected to come into contact, and the owner or operator must submit sufficient documentation to the Agency to support a determination that the tubing and packer meet or exceed standards developed for these materials by the American Petroleum Institute, ASTM International, or a comparable industry standards organization.

2)  The owner or operator of a Class VI injection well must inject fluids through tubing with a packer set at a depth opposite a cemented interval at the location approved by the Agency.

3)  In order for the Agency to determine and specify requirements for tubing and packer, the owner or operator must submit the following information to the Agency:

A)  The depth of setting;

B)  The characteristics of the carbon dioxide stream (the chemical content, corrosiveness, temperature, and density) and formation fluids;

C)  The maximum proposed injection pressure;

D)  The maximum proposed annular pressure;

E)  The proposed injection rate (intermittent or continuous) and the volume or mass of the carbon dioxide stream;

F)  The size of the tubing and casing; and

G)  The tubing tensile, burst, and collapse strengths.

BOARD NOTE: This Section corresponds with 40 CFR 146.86 (2011).

(Source: Added at 36 Ill. Reg. 1661, January 20, 2012)

Section 730.187 Logging, Sampling, and Testing Prior to Injection Well Operation

a)  During the drilling and construction of a Class VI injection well, the owner or operator must run appropriate logs, surveys, and tests to determine or verify the depth, thickness, porosity, permeability, and lithology of all relevant geologic formations and the salinity of any formation fluids in those formations, to ensure conformance with the injection well construction requirements under Section 730.186 and to establish accurate baseline data against which future measurements may be compared. The owner or operator must submit to the Agency a descriptive report prepared by a knowledgeable log analyst that includes an interpretation of the results of the logs and tests. At a minimum, these logs and tests must include the following information items:

1)  Deviation checks made during drilling on all holes constructed by drilling a pilot hole that is enlarged by reaming or another method. These checks must be at sufficiently frequent intervals to determine the location of the borehole and to ensure that vertical avenues for fluid movement in the form of diverging holes are not created during drilling;

2)  Before and upon installation of the surface casing, the following:

A)  The resistivity, spontaneous potential, and caliper logs before the casing is installed; and

B)  A cement bond and variable density log, to evaluate cement quality radially, and a temperature log after the casing is set and cemented;

3)  Before and upon installation of the long-string casing, the following:

A)  The resistivity, spontaneous potential, porosity, caliper, gamma ray, fracture finder logs, and any other logs the Agency requires for the given geology before the casing is installed; and

B)  A cement bond and variable density log and a temperature log, after the casing is set and cemented;

4)  A series of tests designed to demonstrate the internal and external mechanical integrity of injection wells, which may include the following:

A)  A pressure test with liquid or gas;

B)  A tracer survey, such as oxygen-activation logging;

C)  A temperature or noise log; and

D)  A casing inspection log; and

5)  Any alternative methods that provide equivalent or better information and which are required by or approved of by the Agency.

b)  The owner or operator must take whole cores or sidewall cores of the injection zone and confining system and formation fluid samples from all injection zones, and the owner or operator must submit a detailed report prepared by a log analyst to the Agency that includes the following information: well log analyses (including well logs), core analyses, and formation fluid sample information. The Agency must accept information on cores from nearby wells if the Agency determines that the owner or operator has demonstrated that core retrieval is not possible and the nearby cores are representative of conditions at the well. The Agency must require the owner or operator to core other formations in the borehole if the Agency determines that coring those other formations is necessary for evaluation of the well project.

c)  The owner or operator must record the fluid temperature, pH, conductivity, reservoir pressure, and static fluid level of each injection zone.

d)  At a minimum, the owner or operator must determine or calculate the following information concerning the injection and confining zones:

1)  The fracture pressure;

2)  Other physical and chemical characteristics of the injection and confining zones; and

3)  The physical and chemical characteristics of the formation fluids in each injection zone.

e)  Upon completion, but prior to operation, the owner or operator must conduct the following tests to verify hydrogeologic characteristics of each injection zone:

1)  A pressure fall-off test and a pump test; or

2)  A pressure fall-off test and injectivity tests.

f)  The owner or operator must provide the Agency with the opportunity to witness all logging and testing by this Subpart H. The owner or operator must submit a schedule of these activities to the Agency no later than 30 days prior to conducting the first test, and the owner or operator must submit any changes to the schedule to the Agency no later than 30 days prior to the next scheduled test.

BOARD NOTE: This Section corresponds with 40 CFR 146.87 (2011).

(Source: Added at 36 Ill. Reg. 1661, January 20, 2012)

Section 730.188 Injection Well Operating Requirements

a)  Except during injection well stimulation, the owner or operator must ensure that injection pressure does not exceed 90 percent of the fracture pressure of the injection zones, so as to ensure that the injection does not initiate new fractures or propagate existing fractures in the injection zones. In no case may injection pressure initiate fractures in the confining zones or cause the movement of injection or formation fluids that endangers a USDW. Pursuant to the requirements of Section 730.182(a)(9), all stimulation programs must be approved by the Agency as part of the permit application and incorporated into the permit.

b)  Injection between the outermost casing that protects any USDW and the well bore is prohibited.

c)  The owner or operator must fill the annulus between the tubing and the long-string casing with a non-corrosive fluid approved by the Agency. The owner or operator must maintain on the annulus a pressure that exceeds the operating injection pressure, unless the Agency determines that such a requirement might harm the integrity of the well or endanger any USDW.

d)  Other than during periods of well workover (maintenance) approved by the Agency in which the sealed tubing-casing annulus is disassembled for maintenance or corrective procedures, the owner or operator must maintain mechanical integrity of the injection well at all times.

e)  The owner or operator must install and use the equipment indicated in subsection (e)(1) and the appropriate of subsection (e)(2) or (e)(3):

1)  Continuous recording devices that monitor each of the following parameters:

A)  The carbon dioxide injection pressure;

B)  The rate, volume or mass, and temperature of the carbon dioxide stream;

C)  The pressure on the annulus between the tubing and the long-string casing; and

D)  The annulus fluid volume.

2)  For onshore wells, alarms and automatic surface shut-off systems or, at the discretion of the Agency, down-hole shut-off systems (e.g., automatic shut-off valves, check valves, etc.) or other mechanical devices that provide equivalent protection.

3)  For wells located offshore but within State territorial waters, alarms and automatic down-hole shut-off systems designed to alert the operator and shut-in the well when operating parameters, such as annulus pressure, injection rate, or other parameters, diverge beyond permitted ranges or gradients specified in the permit.

f)  If a shutdown is triggered (down-hole or at the surface), or if a loss of mechanical integrity is discovered, the owner or operator must immediately investigate and identify the cause of the shutoff as expeditiously as possible. If, upon investigation, or if monitoring required under subsection (e) otherwise indicates that the well may be lacking mechanical integrity, the well appears to be lacking mechanical integrity, the owner or operator must undertake each of the following actions:

1)  The owner or operator must immediately cease injection;

2)  The owner or operator must take all steps reasonably necessary to determine whether there may have been a release of the injected carbon dioxide stream or formation fluids into any unauthorized zone;

3)  The owner or operator must notify the Agency of the event within 24 hours;

4)  The owner or operator must restore and demonstrate the mechanical integrity of the well to the satisfaction of the Agency prior to resuming injection; and

5)  The owner or operator must notify the Agency when injection can be expected to resume.

BOARD NOTE: This Section corresponds with 40 CFR 146.88 (2017).

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

Section 730.189 Mechanical Integrity

a)  A Class VI injection well has mechanical integrity if both of the following conditions exist:

1)  There is no significant leak in the casing, tubing, or packer; and

2)  There is no significant fluid movement into a USDW through channels adjacent to the injection well bore.

b)  To evaluate the absence of significant leaks under subsection (a)(1), the owner or operator must, following an initial annulus pressure test, continuously monitor each of the following parameters:

1)  The injection pressure, rate, and injected volumes;

2)  The pressure on the annulus between the tubing and the long-string casing; and

3)  The annulus fluid volume, as specified in Section 730.188 (e);

c)  At least once per year, the owner or operator must use one of the following methods to determine the absence of significant fluid movement under subsection (a)(2):

1)  An approved tracer survey, such as an oxygen-activation log; or

2)  A temperature or noise log.

d)  If required by the Agency, at a frequency specified in the testing and monitoring plan required by Section 730.190, the owner or operator must run a casing inspection log to determine the presence or absence of corrosion in the long-string casing.

e)  The Agency must require any requested alternative test that the Agency has determined is necessary to evaluate mechanical integrity under subsections (a)(1) or (a)(2) after obtaining the written approval of USEPA.

BOARD NOTE: Corresponding 40 CFR 146.89(e) provides that the Agency must submit a written request to USEPA setting forth the proposed test and all technical data supporting its use to obtain approval for a new mechanical integrity test. USEPA stated that it will approve the request if USEPA determines that the proposed test will reliably demonstrate the mechanical integrity of wells for which its use was proposed. USEPA stated that it will publish any alternative method that USEPA has approved in the Federal Register, and the Agency must approve use of the published method if the Agency has determined that the method is appropriate to evaluate mechanical integrity, unless USEPA restricts its use at the time of approval by USEPA.

f)  In conducting and evaluating the tests enumerated in this Section or others that the Agency has required by permit, the owner or operator and the Agency must apply methods and standards generally accepted in the industry. When the owner or operator reports the results of mechanical integrity tests to the Agency, the owner or operator must include a description of the tests and the methods used. In making its evaluation, the Agency must review monitoring and other test data submitted since the previous evaluation.

g)  The Agency must require additional or alternative tests if the Agency determines that the results presented by the owner or operator pursuant to subsections (a) through (d) are not satisfactory to demonstrate that there is no significant leak in the casing, tubing, or packer or that there is no significant movement of fluid into a USDW resulting from the injection activity, as required by subsections (a)(1) and (a)(2).

BOARD NOTE: This Section corresponds with 40 CFR 146.89 (2017).

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

Section 730.190 Testing and Monitoring Requirements

The owner or operator of a Class VI injection well must prepare, maintain, and comply with a testing and monitoring plan which will verify that the geologic sequestration project is operating as permitted, and that the project is not endangering USDWs. The requirement to maintain and implement an approved testing and monitoring plan is directly enforceable, regardless of whether the requirement is a condition of the permit. The owner or operator must submit the testing and monitoring plan to the Agency with the permit application, and the owner or operator must include a description of how it will meet the requirements of this Section, including accessing sites for all necessary monitoring and testing during the life of the project. Testing and monitoring associated with geologic sequestration projects must, at a minimum, include the following parameters and devices:

a)  Analyses of the carbon dioxide stream with sufficient frequency to yield data representative of the chemical and physical characteristics of the stream;

b)  Installation and use of continuous recording devices to monitor injection pressure, rate, and volume, except during well workovers, as such are defined in Section 730.188(d); the pressure on the annulus between the tubing and the long-string casing; and the annulus fluid volume added;

c)  Corrosion monitoring of the well materials for loss of mass, thickness, cracking, pitting, and other signs of corrosion, which must be performed on a quarterly basis to ensure that the well components fulfill the Agency-approved minimum standards for material strength and performance, as provided in Section 730.186(b), by performing one of the following tests:

1)  Analyzing coupons of the well construction materials placed in contact with the carbon dioxide stream;

2)  Routing the carbon dioxide stream through a loop constructed with the material used in the well and inspecting the materials in the loop; or

3)  Using an alternative method approved by the Agency;

d)  Periodic monitoring of the groundwater quality and geochemical changes above the confining zones that may be a result of carbon dioxide movement through the confining zones or additional identified zones, including the following information:

1)  The location and number of monitoring wells based on specific information about the geologic sequestration project, including injection rate and volume, geology, the presence of artificial penetrations, and other factors; and

2)  The monitoring frequency and spatial distribution of monitoring wells based on baseline geochemical data that has been collected pursuant to Section 730.182(a)(6) and on any modeling results in the area of review evaluation required by Section 730.184(c).

e)  The annual demonstration of external mechanical integrity required by Section 730.189(c) at least once per year until the injection well is plugged; and, if required by the Agency, a casing inspection log undertaken pursuant to Section 730.189(d), at a frequency established in the testing and monitoring plan;

f)  A pressure fall-off test at least once every five years, unless the Agency has required more frequent testing based on site-specific information;

g)  Testing and monitoring to track the extent of the carbon dioxide plume and the presence or absence of elevated pressure (i.e., the pressure front) by using the following types of methods:

1)  Direct methods in the injection zones; and

2)  Indirect methods (e.g., seismic, electrical, gravity, or electromagnetic surveys or down-hole carbon dioxide detection tools), unless the Agency has determined, based on site-specific geology, that these methods are not appropriate;

h)  The Agency must require surface air monitoring or soil gas monitoring if the Agency determines that this monitoring is needed to detect movement of carbon dioxide that could endanger a USDW.

1)  The design of Class VI injection well surface air or soil gas monitoring must be based on potential risks to USDWs within the area of review;

2)  The monitoring frequency and spatial distribution of surface air monitoring or soil gas monitoring must be decided using baseline data, and the monitoring plan must describe how the proposed monitoring will yield useful information on the area of review delineation or compliance with the prohibition against movement of fluid into a USDW set forth in 35 Ill. Adm. Code 704.122;

3)  If the Agency requires surface air or soil gas monitoring, the Agency has determined that monitoring undertaken to comply with subpart RR of 40 CFR 98 accomplishes the goals of subsections (h)(1) and (h)(2), and the owner or operator fulfills the carbon dioxide release reporting requirements set forth in Section 730.191(c)(5), the Agency must approve the use of monitoring undertaken to comply with subpart RR of 40 CFR 98. After approval by the Agency, compliance with subpart RR of 40 CFR 98 pursuant to this subsection (h)(3) is deemed a condition of the Class VI injection well permit;

i)  Any additional monitoring that the Agency has determined is necessary to support, upgrade, and improve the computational modeling of the area of review evaluation that is required by Section 730.184(c) and to determine compliance with the prohibition against movement of fluid into a USDW set forth in 35 Ill. Adm. Code 704.122;

j)  The owner or operator must periodically review the testing and monitoring plan to incorporate monitoring data collected under this Subpart H, operational data collected pursuant to Section 730.188, and the most recent area of review reevaluation performed pursuant to Section 730.184(e). The owner or operator must review the testing and monitoring plan at least once in every five-year period. Based on this review, the owner or operator must submit an amended testing and monitoring plan or demonstrate to the Agency that no amendment to the testing and monitoring plan is needed. Any amendments to the testing and monitoring plan must be approved by the Agency, must be incorporated into the permit, and are subject to the permit modification requirements set forth in 35 Ill. Adm. Code 704.261 or 704.264, as appropriate. The owner or operator must submit amended plans or demonstrations to the Agency as follows:

1)  Within one year after an area of review reevaluation;

2)  Following any significant changes to the facility, such as addition of monitoring wells or newly permitted injection wells within the area of review, on a schedule determined by the Agency; or

3)  When required by the Agency.

k)  A quality assurance and surveillance plan for all testing and monitoring requirements.

BOARD NOTE: This Section corresponds with 40 CFR 146.90 (2017).

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

Section 730.191 Reporting Requirements

The owner or operator of a Class VI injection well must, at a minimum, provide the following reports to the Agency for each permitted Class VI injection well, as specified in subsection (e):

a)  Semi-annual reports containing the following information:

1)  A description of any deviations in the physical, chemical, and other relevant characteristics of the carbon dioxide stream from the proposed operating data submitted to the Agency pursuant to Sections 730.182(a)(7) and (c)(3) and 730.186(b)(1) and (c)(3);

2)  The monthly average, maximum, and minimum values for injection pressure, flow rate and volume, and annular pressure;

3)  A description of any event that exceeds operating parameters for the annulus pressure or injection pressure specified in the permit;

4)  A description of any event that triggers a shut-off device required pursuant to Section 730.188(e) and the response undertaken by the owner or operator;

5)  The monthly volume or mass of the carbon dioxide stream injected over the reporting period and the volume injected cumulatively over the life of the project;

6)  The monthly annulus fluid volume added; and

7)  The results of the monitoring required by Section 730.190.

b)  Report the results within 30 days after completion of any of the following:

1)  Any results of periodic tests of mechanical integrity;

2)  Any well workover; and

3)  Results of any other test of the injection well that the owner or operator has conducted as required by the Agency.

c)  Report any of the following events within 24 hours after the event:

1)  The owner or operator has discovered any evidence that the injected carbon dioxide stream or associated pressure front may cause an endangerment to a USDW;

2)  The owner or operator has discovered any noncompliance with a permit condition, or malfunction of the injection system, which may cause fluid migration into or between USDWs;

3)  The owner or operator has discovered any triggering of a shut-off system (i.e., down-hole or at the surface);

4)  The owner or operator has discovered any failure to maintain mechanical integrity; or

5)  The owner or operator has discovered any release of carbon dioxide to the atmosphere or biosphere through surface air or soil gas monitoring or other monitoring technologies that the Agency has required pursuant to Section 730.190(h).

d)  An owner or operator must notify the Agency in writing 30 days in advance of any of the following:

1)  Any planned well workover;

2)  Any planned stimulation activities, other than stimulation for formation testing conducted pursuant to Section 730.182; and

3)  Any other planned test of the injection well conducted by the owner or operator.

e)  In corresponding 40 CFR 146.91(e), USEPA has stated that owners or operators must submit all required reports, submittals, and notifications under this Subpart H to USEPA in an electronic format approved by USEPA.

f)  The owner or operator must retain records as follows:

1)  The owner or operator must retain all data collected pursuant to Section 730.182 for Class VI permit applications throughout the life of the geologic sequestration project and for 10 years following site closure.

2)  The owner or operator must retain data on the nature and composition of all injected fluids collected pursuant to Section 730.190(a) until 10 years after site closure. The Agency may require the owner or operator to deliver the records to the Agency at the conclusion of the retention period.

3)  The owner or operator must retain monitoring data collected pursuant to Section 730.190(b) through (i) for 10 years after it is collected.

4)  The owner or operator must retain well plugging reports, post-injection site care data, including, if appropriate, data and information used to develop the demonstration of the alternative post-injection site care timeframe, and the site closure report collected pursuant to requirements at Section 730.193(f) and (h) for 10 years following site closure.

5)  The Agency may require the owner or operator to retain any records required by this Subpart H for a period that is longer than 10 years after site closure. Any Agency requirement that the owner or operator retain records for a longer period must be made in writing, the writing must recite a definite longer period, and the Agency must state the reasons for the determination to require the longer period. An owner or operator may appeal any Agency determination made pursuant to this subsection (f)(5) to the Board pursuant to Section 40 of the Act.

BOARD NOTE: This Section corresponds with 40 CFR 146.91 (2017).

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

Section 730.192 Injection Well Plugging

a)  Prior to the well plugging, the owner or operator must flush each Class VI injection well with a buffer fluid, determine bottom-hole reservoir pressure, and perform a final external mechanical integrity test.

b)  Well plugging plan. The owner or operator of a Class VI injection well must prepare, maintain, and comply with a well plugging plan that is acceptable to the Agency. The requirement to maintain and implement an approved well plugging plan is directly enforceable regardless of whether the requirement is a condition of the permit. The owner or operator must submit the well plugging plan as part of the permit application, and the well plugging plan must include the following information:

1)  Appropriate tests or measures for determining bottomhole reservoir pressure;

2)  Appropriate testing methods to ensure external mechanical integrity, as specified in Section 730.189;

3)  The type and number of plugs to be used;

4)  The placement of each plug, including the elevation of the top and bottom of each plug;

5)  The type, grade, and quantity of material to be used in plugging. The material must be compatible with the carbon dioxide stream; and

6)  The method of placement of the plugs.

c)  Notice of intent to plug. The owner or operator must notify the Agency in writing, and USEPA electronically pursuant to Section 730.191(e), at least 60 days before beginning the plugging of a well. The owner or operator must also provide the revised well plugging plan at the time of this notice if any changes have been made to the original well plugging plan. The Agency must allow for a shorter notice period if the Agency determines that the shorter notice period is adequate to complete Agency review of the well plugging plan or that well plugging must occur more promptly. The Agency must approve any amendments to the injection well plugging plan and incorporate the amendments into the permit, and the incorporation of the amendments into the permit is subject to the permit modification requirements set forth in 35 Ill. Adm. Code 704.262 or 704.264, as appropriate.

d)  Plugging report. Within 60 days after plugging, the owner or operator must submit a plugging report to the Agency and electronically to USEPA pursuant to Section 730.191(e). The plugging report must be certified as accurate by the owner or operator and by the person who performed the plugging operation (if other than the owner or operator). The owner or operator must retain the well plugging report for 10 years following site closure.

BOARD NOTE: This Section corresponds with 40 CFR 146.92 (2011).

(Source: Added at 36 Ill. Reg. 1661, January 20, 2012)

Section 730.193 Post-Injection Site Care and Site Closure

a)  The owner or operator of a Class VI injection well must prepare, maintain, and comply with a plan for post-injection site care and site closure that the Agency has determined meets the requirements of subsection (a)(2). The requirement to maintain and implement an approved plan is directly enforceable, regardless of whether the requirement is a condition of the permit.

1)  The owner or operator must submit the post-injection site care and site closure plan to the Agency as a part of the permit application.

2)  The post-injection site care and site closure plan must include the following information:

A)  The pressure differential between pre-injection and predicted post-injection pressures in the injection zones;

B)  The predicted position of the carbon dioxide plume and associated pressure front at site closure, as demonstrated in the area of review evaluation required by Section 730.184(c)(1);

C)  A description of the proposed post-injection monitoring location, methods, and frequency;

D)  A proposed schedule for submitting post-injection site care monitoring results to the Agency pursuant to Section 730.191(e); and

E)  The duration of the post-injection site care timeframe and, if approved by the Agency, the demonstration of the alternative post-injection site care timeframe that ensures non-endangerment of USDWs.

3)  Upon cessation of injection, the owner or operator of a Class VI injection well must either submit an amended post-injection site care and site closure plan or demonstrate to the Agency through monitoring data and modeling results that no amendment to the plan is needed. The Agency must approve any amendments to the post-injection site care and site closure plan and incorporate the amendments into the permit, and the incorporation of the amendments into the permit is subject to the permit modification requirements set forth in 35 Ill. Adm. Code 704.262 or 704.264, as appropriate.

4)  At any time during the life of the geologic sequestration project, the owner or operator may modify and resubmit the post-injection site care and site closure plan for Agency approval. The owner or operator must resubmit the plan to the Agency within 30 days after making any modification.

b)  The owner or operator must monitor the site following the cessation of injection to show the position of the carbon dioxide plume and pressure front and demonstrate that no USDW is being endangered.

1)  Following the cessation of injection, the owner or operator must continue to conduct monitoring as specified in the Agency-approved post-injection site care and site closure plan for at least 50 years or for the duration of the alternative timeframe approved by the Agency pursuant to requirements in subsection (c), unless the owner or operator makes a demonstration under subsection (b)(2). The monitoring must continue until the geologic sequestration project no longer poses an endangerment to USDWs and the demonstration under subsection (b)(2)is submitted and approved by the Agency.

2)  If the Agency determines, based on monitoring and other site-specific data, that the geologic sequestration project no longer poses an endangerment to any USDW before 50 years or prior to the end of the approved alternative timeframe, the Agency must either approve an amendment to the post-injection site care and site closure plan to reduce the frequency of monitoring or authorize site closure before the end of the 50-year period or prior to the end of the approved alternative timeframe.

3)  Prior to authorization for site closure, the owner or operator must submit to the Agency for review and approval a demonstration, based on monitoring and other site-specific data, that no additional monitoring is needed to ensure that the geologic sequestration project does not pose an endangerment to any USDW.

4)  If the owner or operator cannot make the demonstration required by subsection (b)(3) (i.e., the Agency has determined that additional monitoring is needed to ensure that the geologic sequestration project does not pose an endangerment to any USDW or the Agency has not approved the demonstration) at the end of the 50-year period or at the end of the approved alternative timeframe, the owner or operator must submit to the Agency a plan to continue post-injection site care until the owner or operator has made a demonstration that the Agency can approve.

c)  Demonstration of Alternative Post-Injection Site Care Timeframe. If the Agency determines in consultation with USEPA during the permitting process that an alternative post-injection site care timeframe other than the 50-year default is appropriate and ensures non-endangerment of any USDW, the Agency must approve the alternative post-injection site care timeframe. The Agency must base its determination on significant, site-specific data and information, including all data and information collected pursuant to Sections 730.182 and 730.183, and the Agency must determine based on substantial evidence that the geologic sequestration project will no longer pose a risk of endangerment to any USDW at the end of the alternative post-injection site care timeframe.

1)  A demonstration of an alternative post-injection site care timeframe must include consideration and documentation of the following:

A)  The results of computational modeling performed pursuant to delineation of the area of review, as required by Section 730.184;

B)  The predicted timeframe for pressure decline within the injection zone and any other zones, such that formation fluids may not be forced into any USDW, or the timeframe for pressure decline to pre-injection pressures;

C)  The predicted rate of carbon dioxide plume migration within the injection zone and the predicted timeframe for the cessation of migration;

D)  A description of the site-specific processes that will result in carbon dioxide trapping, including immobilization by capillary trapping, dissolution, and mineralization at the site;

E)  The predicted rate of carbon dioxide trapping in the immobile capillary phase, dissolved phase, and mineral phase;

F)  The results of laboratory analyses, research studies, or field or site-specific studies to verify the information required in subsections (c)(1)(D) and (c)(1)(E);

G)  A characterization of the confining zones, including a demonstration that each confining zone is free of transmissive faults, fractures, and micro-fractures and is of appropriate thickness, permeability, and integrity to impede fluid movement (e.g., carbon dioxide, formation fluids, etc.);

H)  The presence of potential conduits for fluid movement, including planned injection wells and project monitoring wells associated with the proposed geologic sequestration project or any other projects in proximity to the predicted or modeled final extent of the carbon dioxide plume and area of elevated pressure;

I)  A description of the well construction and an assessment of the quality of plugs of all abandoned wells within the area of review;

J)  The distance between the injection zone and the nearest USDWs above and below the injection zone; and

K)  Any additional site-specific factors required by the Agency.

2)  Information submitted to support the demonstration required by subsection (c)(1) must meet the following criteria:

A)  All analyses and tests performed to support the demonstration must be accurate and reproducible, and they must have been performed in accordance with the established quality assurance standards;

B)  Estimation techniques must be appropriate, and USEPA-certified test protocols must have been used where available;

C)  Predictive models must be appropriate and tailored to the site conditions, composition of the carbon dioxide stream, and injection and site conditions over the life of the geologic sequestration project;

D)  Predictive models must be calibrated using existing information (e.g., at Class I, Class II, or Class V experimental technology injection well sites) where sufficient data are available;

E)  Reasonably conservative values and modeling assumptions must be used and disclosed to the Agency whenever values are estimated on the basis of known historical information instead of site-specific measurements;

F)  The owner or operator must perform an analysis to identify and assess aspects of the alternative post-injection site care timeframe demonstration that contribute significantly to uncertainty. The owner or operator must conduct sensitivity analyses to determine the effect that significant uncertainty may contribute to the modeling demonstration.

G)  An approved quality assurance and quality control plan must address all aspects of the demonstration; and

H)  Any additional criteria required by the Agency.

d)  Notice of Intent for Site Closure. The owner or operator must notify the Agency in writing at least 120 days before site closure. At the time of this notice, if any changes have been made to the original post-injection site care and site closure plan, the owner or operator must also provide the revised plan. The Agency may allow for a shorter notice period. The Agency must allow for a shorter notice period if the Agency determines that the shorter notice period is adequate to complete Agency review of the post-injection site care and site closure plan or that well closure must occur more promptly.

e)  After the Agency has authorized site closure, the owner or operator must plug all monitoring wells in a manner that will not allow movement of injection or formation fluids which endangers a USDW.

f)  The owner or operator must submit a site closure report to the Agency within 90 days after site closure, which must thereafter be retained at a location designated by the Agency for at least 10 years. The report must include the following records and documentation:

1)  Documentation of the injection and monitoring well plugging as required by Section 730.192 and subsection (e). The owner or operator must provide a copy of a survey plat that the owner or operator has submitted to the local zoning authority designated by the Agency. The plat must indicate the location of the injection well relative to permanently surveyed benchmarks. The owner or operator must also submit a copy of the plat to USEPA Region 5;

2)  Documentation of appropriate notification and information to all State and local authorities that have authority over drilling activities within the area of review, to enable those State and local authorities to impose appropriate conditions on subsequent drilling activities that may penetrate the injection and confining zones; and

BOARD NOTE: The Illinois Department of Natural Resources, Office of Mines and Minerals, Oil and Gas Division and the Illinois Department of Public Health each have some role in regulating well drilling, depending on the type of well. Other State agencies may also have a role. Further, units of local government and agencies of a sister state may regulate well drilling if a portion of the area of review lies within their jurisdiction. The owner or operator must assure that all applicable regulatory entities receive the required notification and information.

3)  Records reflecting the nature, composition, and volume of the carbon dioxide stream.

g)  Each owner or operator of a Class VI injection well must record a notation on the deed to the facility property or any other document that is normally examined during title search that will in perpetuity provide the following information to any potential purchaser of the property:

1)  The fact that land has been used to sequester carbon dioxide;

2)  The name of the county with which the survey plat was filed, as well as the addresses of the Agency and USEPA Region 5; and

3)  The volume of fluid injected, the injection zone or zones into which the fluid was injected, and the period over which injection occurred.

h)  The owner or operator must retain records collected during the post-injection site care period for at least 10 years following site closure. The owner or operator must deliver the records to the Agency at the conclusion of the retention period, and the records must thereafter be retained at a location designated by the Agency for that purpose.

BOARD NOTE: This Section corresponds with 40 CFR 146.93 (2017).

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

Section 730.194 Emergency and Remedial Response

a)  As part of the permit application, the owner or operator must provide the Agency with an emergency and remedial response plan that describes actions the owner or operator must take to address movement of the injection or formation fluids which may cause an endangerment to a USDW during the construction, operation, and post-injection site care periods of the injection well. The requirement to maintain and implement an approved emergency and remedial response plan is directly enforceable regardless of whether the requirement is a condition of the permit.

b)  If the owner or operator obtains evidence that the injected carbon dioxide stream and associated pressure front may cause an endangerment to a USDW, the owner or operator must undertake the following actions:

1)  The owner or operator must immediately cease injection;

2)  The owner or operator must take all steps reasonably necessary to identify and characterize any release;

3)  The owner or operator must notify the Agency within 24 hours after obtaining the evidence; and

4)  The owner or operator must implement the emergency and remedial response plan approved by the Agency.

c)  The Agency must allow the operator to resume injection prior to remediation if the Agency has determined that the injection operation will not endanger any USDW.

d)  The owner or operator must periodically review the emergency and remedial response plan developed pursuant to subsection (a). The owner or operator must review the emergency and remedial response plan at least once in every five year period. Based on this review, the owner or operator must submit an amended emergency and remedial response plan or demonstrate to the Agency that no amendment to the emergency and remedial response plan is needed. The Agency must approve any amendments to the emergency and remedial response plan and incorporate the amendments into the permit, and the incorporation of the amendments into the permit is subject to the permit modification requirements set forth in 35 Ill. Adm. Code 704.262 or 704.264, as appropriate. The owner or operator must submit any amended plans or demonstrations to the Agency as follows:

1)  Within one year of an area of review reevaluation;

2)  Following any significant changes to the facility, such as addition of injection or monitoring wells, on a schedule determined by the Agency; or

3)  When required by the Agency.

BOARD NOTE: This Section corresponds with 40 CFR 146.94 (2017).

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

Section 730.195 Alternative Class VI Injection Well Depth Requirements

This Section specifies the requirements for application of alternative injection well depth requirements for Class VI injection wells that meet certain criteria. This Section sets forth information that an owner or operator seeking application of alternative Class VI injection well depth requirements must submit to the Agency; the information that the Agency must consider when determining whether any well is suitable for application of alternative injection well depth requirements; the procedure for Agency-USEPA Region 5 communication and Agency determination whether a well is suitable for application of alternative injection well depth requirements; and the additional requirements that apply to an owner or operator of a Class VI injection well that has been granted a permit that includes alternative injection well depth requirements.

a)  When seeking a permit that includes alternative injection well depth requirements to the requirement to inject below the lowermost USDW, the owner or operator must submit a supplemental report concurrent with the permit application. The supplemental report must include the following information:

1)  The following demonstrations with regard to the injection zones:

A)  Each is laterally continuous;

B)  None is a USDW;

C)  None is hydraulically connected to a USDW;

D)  None outcrops;

E)  Each has adequate injectivity, volume, and sufficient porosity to safely contain the injected carbon dioxide and formation fluids; and

F)  Each has appropriate geochemistry.

2)  A demonstration that each injection zone is bounded by laterally continuous impermeable confining units above and below the injection zone that are adequate to prevent fluid movement and pressure buildup outside of the injection zone and that the confining units are free of transmissive faults and fractures. The report must further characterize the regional fracture properties and contain a demonstration that these fractures will not interfere with injection, serve as conduits, or endanger USDWs.

3)  A demonstration, using computational modeling, that no fluid movement will endanger any USDW above or below the injection zone. This modeling should be conducted in conjunction with the area of review determination required by Section 730.184, and the modeling is subject to the area of review delineation and well identification requirements set forth in Section 730.184(c) and the periodic reevaluation requirements set forth in Section 730.184(e).

4)  The following demonstrations with regard to well design and construction, in conjunction with the alternative injection well depth requirements:

A)  Well design and construction will ensure isolation of the injectate in lieu of the prohibition against movement of fluids set forth in 730.186(a)(1); and

B)  Well design and construction will meet the well construction requirements set forth in subsection (f).

5)  A description of how the owner or operator will tailor the monitoring and testing and any additional plans to the geologic sequestration project to ensure protection of USDWs above and below each injection zone if the Agency issues a permit that includes alternative injection well depth requirements.

6)  Information on the location of all the public water supplies that will be affected, or which are reasonably likely to be affected, by the carbon sequestration project, and all public water supplies that distribute water drawn from any USDW in the area of review.

7)  Any other information that the Agency determines is necessary to inform the USEPA Region 5’s decision to issue a waiver, as required by subsection (b).

b)  To inform the USEPA Region 5’s decision on whether to grant a waiver of the injection depth requirements pursuant to 40 CFR 146.95, which would allow the Agency to issue a permit that includes alternative injection well depth requirements, the Agency must submit the following documentation to USEPA Region 5:

1)  An evaluation of the following information as it relates to siting, construction, and operation of a geologic sequestration project under a permit that includes alternative injection well depth requirements:

A)  The integrity of the upper and lower confining units;

B)  The suitability of the injection zones (e.g., lateral continuity, lack of transmissive faults and fractures, known current or planned artificial penetrations into the injection zones or formations below the injection zone, etc.);

C)  The potential capacity of the geologic formations to sequester carbon dioxide, accounting for the availability of alternative injection sites;

D)  All other site characterization data, the proposed emergency and remedial response plan, and a demonstration of financial responsibility;

E)  An assessment of community needs, demands, and supply from drinking water resources;

F)  An assessment of planned needs and potential or future use of USDWs and non-USDWs in the area of review;

G)  An assessment of planned or permitted water, hydrocarbon, or mineral resource exploitation potential of the proposed injection formations and other formations both above and below the injection zone to determine if there are any plans to drill through the formation to access resources in or beneath the proposed injection zones or formations;

H)  The proposed plan for securing alternative water resources or treating USDW formation waters in the event of contamination related to the Class VI injection well activity; and

I)  Any other applicable considerations or information that the Agency determines is necessary to aid a determination by USEPA Region 5 to grant a waiver that would allow the Agency to issue a permit that includes alternative injection well depth requirements.

2)  Consultation with the Agency’s Division of Public Water Supply and all agencies of a sister state that have public water system supervision authority over lands within the area of review of a well for which a waiver that would allow the Agency to issue a permit that includes alternative injection well depth requirements is sought.

3)  Any written waiver-related information submitted by the Agency’s Division of Public Water Supply and all agencies of a sister state that have public water system supervision authority to the Agency.

c)  Pursuant to 35 Ill. Adm. Code 705.163 and concurrent with the Class VI injection well permit application notice process, the Agency must give public notice that the owner or operator has sought a permit that includes alternative injection well depth requirements. The notice must clearly state the following information:

1)  The depth of the proposed injection zones;

2)  The location of the injection wells;

3)  The name and depth of each USDW within the area of review;

4)  A map of the area of review;

5)  The names of any public water supplies that will be affected, or which are reasonably likely to be affected, by the carbon sequestration project, and all public water supplies that distribute water drawn from any USDW in the area of review; and

6)  The results of consultation with the Agency’s Division of Public Water Supply and all agencies of a sister state that have public water system supervision authority, as required by subsection (b)(2).

d)  Following the public notice required by subsection (c), the Agency must provide all information received through the waiver application process to USEPA Region 5. USEPA has stated in corresponding 40 CFR 146.95(d) that, based on this information, the USEPA Region 5 must provide written concurrence or non-concurrence regarding the Agency issuing a permit that includes alternative injection well depth requirements.

1)  If USEPA Region 5 determines that additional information is required to support a decision, the Agency must provide that information. At its discretion, USEPA Region 5 may require that public notice of the new information be initiated.

2)  The Agency must not issue a permit that includes alternative injection well depth requirements without having first received the written concurrence of USEPA Region 5.

e)  USEPA has stated in corresponding 40 CFR 146.95(e) that if the Agency issues a permit that includes alternative injection well depth requirements, USEPA will post the following information on its Office of Water website within 30 days after permit issuance:

1)  The depth of the proposed injection zones;

2)  The location of the injection wells;

3)  The name and depth of all USDWs within the area of review;

4)  A map of the area of review;

5)  The names of any public water supplies that will be affected, or which are reasonably likely to be affected, by the carbon sequestration project, and all public water supplies that distribute water drawn from any USDW in the area of review; and

6)  The date of permit issuance.

f)  Upon receipt of a permit that includes alternative injection well depth requirements for geologic sequestration, the owner or operator of the covered Class VI injection well must comply with the following requirements:

1)  All requirements of Sections 730.184, 730.185, 730.187, 730.188, 730.189, 730.191, 730.192, and 730.194.

2)  All requirements of Section 730.186, with the following modified requirements:

A)  The owner or operator must ensure that each Class VI injection well operating under the alternative injection well depth requirements is constructed and completed to prevent movement of fluids into any unauthorized zone that includes a USDW, in lieu of the requirements of Section 730.186(a)(1).

B)  The casing and cementing program must be designed to prevent the movement of fluids into any unauthorized zone that includes a USDW in lieu of the requirements of Section 730.186(b)(1).

C)  The surface casing must extend through the base of the nearest USDW directly above the injection zone. The surface casing must be cemented to the surface. Alternatively, the Agency must require that the casing extend through another formation above the injection zone and below the nearest USDW above the injection zone if the Agency determines that doing so is necessary to prevent movement of fluids into a USDW.

3)  All requirements of Section 730.190, with the following modified requirements:

A)  The owner or operator must monitor the groundwater quality, geochemical changes, and pressure in the first USDWs immediately above and below each injection zone; and in any other formation that the Agency determines is necessary to detect potential movement of fluids into a USDW.

B)  The owner or operator must conduct testing and monitoring to track the extent of the carbon dioxide plume and the presence or absence of elevated pressure (i.e., the pressure front) by using direct methods to monitor for pressure changes in the injection zones. The owner or operator must use indirect methods (e.g., seismic, electrical, gravity, or electromagnetic surveys or down-hole carbon dioxide detection tools) that the Agency determines are necessary based on site-specific geology.

4)  All requirements of Section 730.193, with the following, modified post-injection site care monitoring requirements:

A)  The owner or operator must monitor the groundwater quality, geochemical changes, and pressure in the first USDWs immediately above and below each injection zone; and in any other formation that the Agency determines is necessary to detect potential movement of fluids into a USDW.

B)  The owner or operator must conduct testing and monitoring to track the extent of the carbon dioxide plume and the presence or absence of elevated pressure (i.e., the pressure front) by using direct methods in the injection zones. The owner or operator must use indirect methods (e.g., seismic, electrical, gravity, or electromagnetic surveys or down-hole carbon dioxide detection tools) that the Agency determines are necessary to detect potential movement of fluids into a USDW.

5)  Any additional requirements that the Agency determines are necessary to ensure protection of USDWs above and below the injection zones.

BOARD NOTE: This Section corresponds with 40 CFR 146.95 (2017). The corresponding federal rule calls the administrative permission to allow a well to inject at an alternative depth (i.e., above the lowermost USDW) a “waiver”. While the Board has retained the use of “waiver” with regard to USEPA review of alternative depth requirements, the Board has changed this to some variant of “permit that includes alternative injection well depth requirements”. While the Agency cannot “waive” standards embodied in Board regulations, the Agency can issue a permit that applies alternative standards that are contained in the regulations. The Board believes that this rule includes standards sufficient to guide an Agency permit determination.

(Source: Amended at 42 Ill. Reg. 24145, effective November 19, 2018)

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