W. Va. Code R. § 47-13-13

Current through Register Vol. XLI, No. 24, June 14, 2024

Section 47-13-13 - Criteria and Standards Applicable to Class 6 Wells

13.1. General. This section sets forth requirements for underground injection control programs to regulate Class 6 carbon dioxide geologic sequestration wells. This section establishes criteria and standards for underground injection control programs to regulate any Class 6 carbon dioxide geologic sequestration injection wells, for long-term containment of a gaseous, liquid, or supercritical carbon dioxide stream in subsurface geologic formations.

13.1.1. This subpart also applies to owners or operators of permit or rule-authorized Class 1, Class 2, or Class 5 experimental carbon dioxide injection projects who seek to apply for a Class 6 geologic sequestration permit for their well or wells. Owners or operators seeking to convert existing Class 1, Class 2, or Class 5 experimental wells to Class 6 geologic sequestration wells must demonstrate to the Director that the wells were engineered and constructed to meet the requirements at subsection 13.3.1.and ensure protection of USDWs, in lieu of requirements at subsection 13.3.2., 13.3.2.a., and 13.5. By December 10, 2011, owners, or operators of either Class 1 wells previously permitted for the purpose of geologic sequestration or Class 5 experimental technology wells no longer being used for experimental purposes that will continue injection of carbon dioxide for the purpose of GS must apply for a Class 6 permit. A converted well must still meet all other requirements under section 13-13.

13.1.1.a. The construction, operation or maintenance of any non-experimental Class 5 geologic sequestration well is prohibited.

13.1.1.b. Owners or operators of Class 6 wells must obtain a permit. Class 6 wells cannot be authorized by the rule to inject carbon dioxide.

13.1.2. Existing well means a Class 6 well which was authorized prior to August 25, 1988, or a well which has become a Class 6 well as a result of a change in the definition of the injected waste into a hazardous waste.

13.1.3. Transitioning to a Class 6 Well from a Class 2 Well. Owners or operators that are injecting carbon dioxide for the primary purpose of long-term storage into an oil and gas reservoir must apply for and obtain a Class 6 geologic sequestration permit when there is an increased risk to USDWs compared to Class 2 operations. In determining if there is an increased risk to USDWs, the owner or operator as well as the Director must consider:

13.1.3.a. Increase in reservoir pressure within the injection zone(s);

13.1.3.b. Increase in carbon dioxide injection rates;

13.1.3.c. Decrease in reservoir production rates;

13.1.3.d. Distance between the injection zone(s) and USDWs;

13.1.3.e. Suitability of the Class 2 area of review delineation;

13.1.3.f. Quality of abandoned well plugs within the area of review;

13.1.3.g. The owner's or operator's plan for recovery of carbon dioxide at the cessation of injection;

13.1.3.h. The source and properties of injected carbon dioxide; and

13.1.3.i. Any additional site-specific factors as determined by the Director.

13.2. Minimum Criteria for Siting.

13.2.1. Owners or operators of Class 6 wells must demonstrate to the satisfaction of the Director that the wells will be sited in areas with a suitable geologic system. The owners or operators must demonstrate that the geologic system comprises:

13.2.1.a. An injection zone(s) of sufficient areal extent, thickness, porosity, and permeability to receive the total anticipated volume of the carbon dioxide stream;

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

13.2.2. The Director may require owners or operators of Class 6 wells to identify and characterize additional zones that will impede vertical fluid movement, are free of faults and fractures that may interfere with containment, allow for pressure dissipation, and provide additional opportunities for monitoring, mitigation, and remediation.

13.3. Construction Requirements. The Director shall prescribe requirements for the construction of Class 6 injection wells. Existing wells shall achieve compliance with such requirements according to a specific compliance schedule established by the Director as a condition of the permit. New wells shall be in compliance with construction requirements before injection operations begin. The owner or operator of a proposed injection well shall submit plans to the Director for testing, drilling, and construction and obtain the approval of the initial plans as a condition of the permit. The Director's approval of any modifications of the plan shall be obtained before incorporating them into the construction of the injection well. At a minimum, such requirements shall prescribe that:

13.3.1. Each Class 6 well is constructed and completed to:

13.3.1.a. Prevent the movement of fluids into or between USDWs or into any unauthorized zones;

13.3.1.b. Permit the use of appropriate testing devices and workover tools; and

13.3.1.c. Permit continuous monitoring of the annulus space between the injection tubing and long string casing.

13.3.2. Casing and cementing of Class 6 wells.

13.3.2.a. Casing and cement or other materials used in the construction of each Class 6 well must have sufficient structural strength and be designed for the life of the geologic sequestration project. All well materials must be compatible with fluids with which the materials may be expected to come into contact and must meet or exceed standards developed for such materials by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director. The casing and cementing program must be designed to prevent the movement of fluids into or between USDWs. In order to allow the Director to determine and specify casing and cementing requirements, the owner or operator must provide the following information:

13.3.2.a.1. Depth to the injection zone(s);

13.3.2.a.2. Injection pressure, external pressure, internal pressure, and axial loading;

13.3.2.a.3. Hole size;

13.3.2.a.4. Size and grade of all casing strings (wall thickness, external diameter, nominal weight, length, joint specification, and construction material);

13.3.2.a.5. Corrosiveness of the carbon dioxide stream and formation fluids;

13.3.2.a.6. Down-hole temperatures;

13.3.2.a.7. Lithology of injection and confining zone(s);

13.3.2.a.8. Type or grade of cement and cement additives; and

13.3.2.a.9. Quantity, chemical composition, and temperature of the carbon dioxide stream.

13.3.2.b. 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.

13.3.2.c. 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.

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

13.3.2.e. Cement and cement additives must be compatible with the carbon dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the geologic sequestration project. The integrity and location of the cement shall be verified using technology capable of evaluating cement quality radially and identifying the location of channels to ensure that USDWs are not endangered.

13.3.3. Tubing and packer.

13.3.3.a. Tubing and packer materials used in the construction of each Class 6 well must be compatible with fluids with which the materials may be expected to come into contact and must meet or exceed standards developed for such materials by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director.

13.3.3.b. All owners or operators of Class 6 wells must inject fluids through tubing with a packer set at a depth opposite a cemented interval at the location approved by the Director.

13.3.3.c. In order for the Director to determine and specify requirements for tubing and packer, the owner or operator must submit the following information:

13.3.3.c.1. Depth of setting;

13.3.3.c.2. Characteristics of the carbon dioxide stream (chemical content, corrosiveness, temperature, and density) and formation fluids;

13.3.3.c.3. Maximum proposed injection pressure;

13.3.3.c.4. Maximum proposed annular pressure;

13.3.3.c.5. Proposed injection rate (intermittent or continuous) and volume and/or mass of the carbon dioxide stream;

13.3.3.c.6. Size of tubing and casing; and

13.3.3.c.7. Tubing tensile, burst, and collapse strengths.

13.4. Abandonment of Class 6 Wells. Owners and operators shall abandon Class 6 wells in a manner to be prescribed by the Director under sub-division 14.7.6., in addition to the following:

13.4.1. Prior to the well plugging, the owner or operator must flush each Class 6 injection well with a buffer fluid, determine bottomhole reservoir pressure, and perform a final external mechanical integrity test.

13.4.2. Well plugging plan. The owner or operator of a Class 6 well must prepare, maintain, and comply with a plan that is acceptable to the Director. The requirement to maintain and implement an approved plan is directly enforceable regardless of whether the requirement is a condition of the permit. The well plugging plan must be submitted as part of the permit application and must include the following information:

13.4.2.a. Appropriate tests or measures for determining bottomhole reservoir pressure;

13.4.2.b. Appropriate testing methods to ensure external mechanical integrity as specified in section 6.2;

13.4.2.c. The type and number of plugs to be used;

13.4.2.d. The placement of each plug, including the elevation of the top and bottom of each plug;

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

13.4.2.f. The method of placement of the plugs.

13.4.3. Notice of intent to plug. The owner or operator must notify the Director in writing pursuant to subsection 13.6.3.a.5., at least 60 days before plugging of a well. At this time, if any changes have been made to the original well plugging plan, the owner or operator must also provide the revised well plugging plan. The Director may allow for a shorter notice period. Any amendments to the injection well plugging plan must be approved by the Director, must be incorporated into the permit, and are subject to the permit modification requirements at sections 14.18 and 14.20 of this rule, as appropriate.

13.4.4. Plugging report. Within 60 days after plugging, the owner or operator must submit, pursuant to subsection 13.6.3.a.5., a plugging report to the Director. The report must be certified as accurate by the owner or operator and by the person who performed the plugging operation (if other than the owner or operator). The owner or operator shall retain the well plugging report for 10 years following site closure.

13.5. Logging, Sampling, and Testing Prior to Injection Well Operation.

13.5.1. During the drilling and construction of a Class 6 injection well, the owner or operator must run appropriate logs, surveys and tests to determine or verify the depth, thickness, porosity, permeability, and lithology of, and the salinity of any formation fluids in all relevant geologic formations to ensure conformance with the injection well construction requirements under section 13.3 and to establish accurate baseline data against which future measurements may be compared. The owner or operator must submit to the Director a descriptive report prepared by a knowledgeable log analyst that includes an interpretation of the results of such logs and tests. At a minimum, such logs and tests must include:

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

13.5.1.b. Before and upon installation of the surface casing:

13.5.1.b.1. Resistivity, spontaneous potential, and caliper logs before the casing is installed; and

13.5.1.b.2. A cement bond and variable density log to evaluate cement quality radially, and a temperature log after the casing is set and cemented.

13.5.1.c. Before and upon installation of the long string casing:

13.5.1.c.1. Resistivity, spontaneous potential, porosity, caliper, gamma ray, fracture finder logs, and any other logs the Director requires for the given geology before the casing is installed; and

13.5.1.c.2. A cement bond and variable density log, and a temperature log after the casing is set and cemented.

13.5.1.d. A series of tests designed to demonstrate the internal and external mechanical integrity of injection wells, which may include:

13.5.1.d.1. A pressure test with liquid or gas;

13.5.1.d.2. A tracer survey such as oxygen-activation logging;

13.5.1.d.3. A temperature or noise log;

13.5.1.d.4. A casing inspection log; and

13.5.1.e. Any alternative methods that provide equivalent or better information and that are required by and/or approved of by the Director.

13.5.2. The owner or operator must take whole cores or sidewall cores of the injection zone and confining system and formation fluid samples from the injection zone(s) and must submit to the Director a detailed report prepared by a log analyst that includes: Well log analyses (including well logs), core analyses, and formation fluid sample information. The Director may accept information on cores from nearby wells if the owner or operator can demonstrate that core retrieval is not possible and that such cores are representative of conditions at the well. The Director may require the owner or operator to core other formations in the borehole.

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

13.5.4 At a minimum, the owner or operator must determine or calculate the following information concerning the injection and confining zone(s):

13.5.4.a. Fracture pressure;

13.5.4.b. Other physical and chemical characteristics of the injection and confining zone(s); and

13.5.4.c. Physical and chemical characteristics of the formation fluids in the injection zone(s).

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

13.5.5.a. A pressure fall-off test; and,

13.5.5.b. A pump test; or

13.5.5.c. Injectivity tests.

13.5.6. The owner or operator must provide the Director with the opportunity to witness all logging and testing by this subpart. The owner or operator must submit a schedule of such activities to the Director 30 days prior to conducting the first test and submit any changes to the schedule 30 days prior to the next scheduled test.

13.6. Operating, Monitoring, and Reporting Requirements.

13.6.1. Operating Requirements: The Director shall, under subdivision 14.7.3., prescribe requirements governing the operation of injection wells in the permit. Requirements for Class 6 wells shall, at a minimum, specify that:

13.6.1.a. Except during stimulation, the owner or operator must ensure that injection pressure does not exceed 90 percent of the fracture pressure of the injection zone(s) so as to ensure that the injection does not initiate new fractures or propagate existing fractures in the injection zone(s). In no case may injection pressure initiate fractures in the confining zone(s) or cause the movement of injection or formation fluids that endangers a USDW. Pursuant to requirements at subsection 13.8.1.i., all stimulation programs must be approved by the Director as part of the permit application and incorporated into the permit.

13.6.1.b. Injection between the outermost casing protecting underground sources of drinking water and the well bore is prohibited; and

13.6.1.b.1. The owner or operator must fill the annulus between the tubing and the long string casing with a non-corrosive fluid approved by the Director. The owner or operator must maintain on the annulus a pressure that exceeds the operating injection pressure, unless the Director determines that such requirement might harm the integrity of the well or endanger USDWs.

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

13.6.1.d. The owner or operator must install and use:

13.6.1.d.1. Continuous recording devices to monitor: The injection pressure; the rate, volume and/or mass, and temperature of the carbon dioxide stream; and the pressure on the annulus between the tubing and the long string casing and annulus fluid volume; and

13.6.1.d.2. Alarms and automatic surface shut-off systems or, at the discretion of the Director, down-hole shut-off systems (e.g., automatic shut-off, check valves) for onshore wells or, other mechanical devices that provide equivalent protection; and

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

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

13.6.1.e.1. Immediately cease injection;

13.6.1.e.2. Take all steps reasonably necessary to determine whether there may have been a release of the injected carbon dioxide stream or formation fluids into any unauthorized zone;

13.6.1.e.3. Notify the Director within 24 hours;

13.6.1.e.4. Restore and demonstrate mechanical integrity to the satisfaction of the Director prior to resuming injection; and

13.6.1.e.5. Notify the Director when injection can be expected to resume.

13.6.2. Testing and monitoring requirements. The owner or operator of a Class 6 well must prepare, maintain, and comply with a testing and monitoring plan to verify that the geologic sequestration project is operating as permitted and is not endangering USDWs. The requirement to maintain and implement an approved plan is directly enforceable regardless of whether the requirement is a condition of the permit. The testing and monitoring plan must be submitted with the permit application, for Director approval, and must include a description of how the owner or operator will meet the requirements of this section, including accessing sites for all necessary monitoring and testing during the life of the project. Testing and monitoring associated with geologic sequestration projects must, at a minimum, include:

13.6.2.a. Analysis of the carbon dioxide stream with sufficient frequency to yield data representative of its chemical and physical characteristics;

13.6.2.b. Installation and use, except during well workovers as defined in subsection 13.6.1.c., of continuous recording devices to monitor injection pressure, rate, and volume; the pressure on the annulus between the tubing and the long string casing; and the annulus fluid volume added;

13.6.2.c. Corrosion monitoring of the well materials for loss of mass, thickness, cracking, pitting, and other signs of corrosion, which must be performed on a quarterly basis to ensure that the well components meet the minimum standards for material strength and performance set forth in subsection 13.3.2. and 13.3.2.a., by:

13.6.2.c.1. Analyzing coupons of the well construction materials placed in contact with the carbon dioxide stream; or

13.6.2.c.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

13.6.2.c.3. Using an alternative method approved by the Director;

13.6.2.d. Periodic monitoring of the groundwater quality and geochemical changes above the confining zone(s) that may be a result of carbon dioxide movement through the confining zone(s) or additional identified zones including:

13.6.2.d.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

13.6.2.d.2. The monitoring frequency and spatial distribution of monitoring wells based on baseline geochemical data that has been collected under subsection 13.8.1.f. and on any modeling results in the area of review evaluation required by subsection 14.9.3.

13.6.2.e. A demonstration of external mechanical integrity pursuant to subsection 6.2.3. at least once per year until the injection well is plugged; and, if required by the Director, a casing inspection log pursuant to requirements at subsection 6.2.3.e.1. at a frequency established in the testing and monitoring plan;

13.6.2.f. A pressure fall-off test at least once every 5 years unless more frequent testing is required by the Director based on site-specific information;

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

13.6.2.g.1. Direct methods in the injection zone(s); and,

13.6.2.g.2. Indirect methods (e.g., seismic, electrical, gravity, or electromagnetic surveys and/or down-hole carbon dioxide detection tools), unless the Director determines, based on site-specific geology, that such methods are not appropriate;

13.6.2.h. The Director may require surface air monitoring and/or soil gas monitoring to detect movement of carbon dioxide that could endanger a USDW.

13.6.2.h.1. Design of Class 6 surface air and/or soil gas monitoring must be based on potential risks to USDWs within the area of review;

13.6.2.h.2. The monitoring frequency and spatial distribution of surface air monitoring and/or soil gas monitoring must be decided using baseline data, and the monitoring plan must describe how the proposed monitoring will yield useful information on the area of review delineation and/or compliance with standards under § 47 CSR 13-14.1.;

13.6.2.h.3. If an owner or operator demonstrates that monitoring employed under 40 CFR 98.440 to 98.449 of this chapter (Clean Air Act, 42 U.S.C. 7401et seq.) accomplishes the goals of 13.6.2.h.1., and 13.6.2.h.2 above, and meets the requirements pursuant to 13.6.3.a.3.E., a Director that requires surface air/soil gas monitoring must approve the use of monitoring employed under 40 CFR 98.440 to 98.449 of this chapter. Compliance with 40 CFR 98.440 to 98.449 of this chapter pursuant to this provision is considered a condition of the Class 6 permit;

13.6.2.i. Any additional monitoring, as required by the Director, necessary to support, upgrade, and improve computational modeling of the area of review evaluation required under subsection 14.9.3. and to determine compliance with standards under section 14.1 of this rule;

13.6.2.j. The owner or operator shall periodically review the testing and monitoring plan to incorporate monitoring data collected under this subpart, operational data collected under section 13.6., and the most recent area of review reevaluation performed under subsection 14.9.5. In no case shall the owner or operator review the testing and monitoring plan less often than once every five years. Based on this review, the owner or operator shall submit an amended testing and monitoring plan or demonstrate to the Director that no amendment to the testing and monitoring plan is needed. Any amendments to the testing and monitoring plan must be approved by the Director, must be incorporated into the permit, and are subject to the permit modification requirements at sections 14.8 and 14.20 of this rule, as appropriate. Amended plans or demonstrations shall be submitted to the Director as follows:

13.6.2.j.1. Within one year of an area of review reevaluation;

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

13.6.2.j.3. When required by the Director.

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

13.6.3. Reporting requirements: The Director shall prescribe the form, manner, content, and frequency of reporting by the operator. The operator shall be required to identify the types of tests and methods used to generate the monitoring data. At a minimum, requirements shall include:

13.6.3.a. The owner or operator must, at a minimum, provide, as specified in 13.6.3.a.5., the following reports to the Director, for each permitted Class 6 well:

13.6.3.a.1. Semi-annual reports containing:

13.6.3.a.1.A. Any changes to the physical, chemical, and other relevant characteristics of the carbon dioxide stream from the proposed operating data;

13.6.3.a.1.B. Monthly average, maximum, and minimum values for injection pressure, flow rate and volume, and annular pressure;

13.6.3.a.1.C. A description of any event that exceeds operating parameters for annulus pressure or injection pressure specified in the permit;

13.6.3.a.1.D. A description of any event which triggers a shut-off device required pursuant to subsection 13.6.1.d. and the response taken;

13.6.3.a.1.E. The monthly volume and/or mass of the carbon dioxide stream injected over the reporting period and the volume injected cumulatively over the life of the project;

13.6.3.a.1.F. Monthly annulus fluid volume added; and

13.6.3.a.1.G. The results of monitoring prescribed under subsection 13.6.2.

13.6.3.a.2. Report, within 30 days, the results of:

13.6.3.a.2.A. Periodic tests of mechanical integrity;

13.6.3.a.2.B. Any well workover; and,

13.6.3.a.2.C. Any other test of the injection well conducted by the permittee if required by the Director.

13.6.3.a.3. Report, within 24 hours:

13.6.3.a.3.A. Any evidence that the injected carbon dioxide stream or associated pressure front may cause an endangerment to a USDW;

13.6.3.a.3.B. Any noncompliance with a permit condition, or malfunction of the injection system, which may cause fluid migration into or between USDWs;

13.6.3.a.3.C. Any triggering of a shut-off system (i.e., down-hole or at the surface);

13.6.3.a.3.D. Any failure to maintain mechanical integrity; or.

13.6.3.a.3.E. Pursuant to compliance with the requirement at subsection 13.6.2.h for surface air/soil gas monitoring or other monitoring technologies, if required by the Director, any release of carbon dioxide to the atmosphere or biosphere.

13.6.3.a.4. Owners or operators must notify the Director in writing 30 days in advance of:

13.6.3.a.4.A. Any planned well workover;

13.6.3.a.4.B. Any planned stimulation activities, other than stimulation for formation testing conducted under subsection 13.8.3.d., and

13.6.3.a.4.C. Any other planned test of the injection well conducted by the permittee.

13.6.3.a.5. Regardless of whether a State has primary enforcement responsibility, owners or operators must submit all required reports, submittals, and notifications under subpart H of 40 CFR 146 to EPA in an electronic format approved by EPA.

13.6.3.a.6. Records shall be retained by the owner or operator as follows:

13.6.3.a.6.A. All data collected under §47-13-13.8 for Class permit applications shall be retained throughout the life of the geologic sequestration project and for 10 years following site closure.

13.6.3.a.6.B. Data on the nature and composition of all injected fluids collected pursuant to subsection 13.6.2.a. shall be retained until 10 years after site closure. The Director may require the owner or operator to deliver the records to the Director at the conclusion of the retention period.

13.6.3.a.6.C. Monitoring data collected pursuant to subsections 13.6.2.b. through 13.6.2.i. shall be retained for 10 years after it is collected.

13.6.3.a.6.D. 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 subsections 13.9.6. and 13.9.8. shall be retained for 10 years following site closure.

13.6.3.a.6.E. The Director has authority to require the owner or operator to retain any records required in this subpart for longer than 10 years after site closure.

13.7. Emergency and Remedial Response.

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

13.7.2. 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:

13.7.2.a. Immediately cease injection;

13.7.2.b. Take all steps reasonably necessary to identify and characterize any release;

13.7.2.c. Notify the Director within 24 hours; and

13.7.2.d. Implement the emergency and remedial response plan approved by the Director.

13.7.3. The Director may allow the operator to resume injection prior to remediation if the owner or operator demonstrates that the injection operation will not endanger USDWs.

13.7.4. The owner or operator shall periodically review the emergency and remedial response plan developed under paragraph (a) of this section. In no case shall the owner or operator review the emergency and remedial response plan less often than once every 5 years. Based on this review, the owner or operator shall submit an amended emergency and remedial response plan or demonstrate to the Director that no amendment to the emergency and remedial response plan is needed. Any amendments to the emergency and remedial response plan must be approved by the Director, must be incorporated into the permit, and are subject to the permit modification requirements at sections 14.8 and 14.20 of this rule, as appropriate. Amended plans or demonstrations shall be submitted to the Director as follows:

13.7.4.a. Within one year of an area of review reevaluation;

13.7.4.b. Following any significant changes to the facility, such as addition of injection or monitoring wells, on a schedule determined by the Director; or

13.7.4.c. When required by the Director.

13.8. Required Class 6 Permit Information.

13.8.1. Prior to the issuance of a permit for the construction of a new Class 6 well or the conversion of an existing Class 1, Class 2, or Class 5 well to a Class 6 well, the owner or operator shall submit, pursuant to 13.6.3.a.5., and the Director shall consider the following:

13.8.1.a. Information required in section 10.4. of this rule;

13.8.1.b. A map showing the injection well for which a permit is sought and the applicable area of review consistent with section 5.4. and subsection 14.9.2.e. Within the area of review, the map must show the number or name, and location of all injection wells, producing wells, abandoned wells, plugged wells or dry holes, deep stratigraphic boreholes, State- or EPA-approved subsurface cleanup sites, surface bodies of water, springs, mines (surface and subsurface), quarries, water wells, other pertinent surface features including structures intended for human occupancy, State, Tribal, and Territory boundaries, and roads. The map should also show faults, if known or suspected. Only information of public record is required to be included on this map;

13.8.1.c. Information on the geologic structure and hydrogeologic properties of the proposed storage site and overlying formations, including:

13.8.1.c.1. Maps and cross sections of the area of review;

13.8.1.c.2. The location, orientation, and properties of known or suspected faults and fractures that may transect the confining zone(s) in the area of review and a determination that they would not interfere with containment;

13.8.1.c.3. Data on the depth, areal extent, thickness, mineralogy, porosity, permeability, and capillary pressure of the injection and confining zone(s); including geology/facies changes based on field data which may include geologic cores, outcrop data, seismic surveys, well logs, and names and lithologic descriptions;

13.8.1.c.4. Geo-mechanical information on fractures, stress, ductility, rock strength, and in situ fluid pressures within the confining zone(s);

13.8.1.c.5. Information on the seismic history including the presence and depth of seismic sources and a determination that the seismicity would not interfere with containment; and

13.8.1.c.6. Geologic and topographic maps and cross sections illustrating regional geology, hydrogeology, and the geologic structure of the local area.

13.8.1.d. A tabulation of all wells within the area of review which penetrate the injection or confining zone(s). Such data must include a description of each well's type, construction, date drilled, location, depth, record of plugging and/or completion, and any additional information the Director may require;

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

13.8.1.f. Baseline geochemical data on subsurface formations, including all USDWs in the area of review;

13.8.1.g. Proposed operating data for the proposed geologic sequestration site:

13.8.1.g.1. Average and maximum daily rate and volume and/or mass and total anticipated volume and/or mass of the carbon dioxide stream;

13.8.1.g.2. Average and maximum injection pressure;

13.8.1.g.3. The source(s) of the carbon dioxide stream; and

13.8.1.g.4. An analysis of the chemical and physical characteristics of the carbon dioxide stream.

13.8.1.h. Proposed pre-operational formation testing program to obtain an analysis of the chemical and physical characteristics of the injection zone(s) and confining zone(s) and that meets the requirements at section 13.5.;

13.8.1.i. Proposed stimulation program, a description of stimulation fluids to be used and a determination that stimulation will not interfere with containment;

13.8.1.j. Proposed procedure to outline steps necessary to conduct injection operation;

13.8.1.k. Schematics or other appropriate drawings of the surface and subsurface construction details of the well;

13.8.1.l. Injection well construction procedures that meet the requirements of section 13.3;

13.8.1.m. Proposed area of review and corrective action plan that meets the requirements under section 5.4. and subsection 14.9.2.e.;

13.8.1.n. A demonstration, satisfactory to the Director, that the applicant has met the financial responsibility requirements under subsection 14.7.7.;

13.8.1.o. Proposed testing and monitoring plan required by subsection 13.6.2.;

13.8.1.p. Proposed injection well plugging plan required by subsection 13.4.2.;

13.8.1.q. Proposed post-injection site care and site closure plan required by subsection 13.9.1.;

13.8.1.r. At the Director's discretion, a demonstration of an alternative post-injection site care timeframe required by subsection 13.9.3.;

13.8.1.s. Proposed emergency and remedial response plan required by subsection 13.7.1.;

13.8.1.t. A list of contacts, submitted to the Director, for those States, Tribes, and Territories identified to be within the area of review of the Class 6 project based on information provided in subsection 13.8.1.b. of this section; and

13.8.1.u. Any other information requested by the Director.

13.8.2. The Director shall notify, in writing, any States, Tribes, or Territories within the area of review of the Class 6 project based on information provided in paragraphs 13.8.1.b., and 13.8.1.t., of this section of the permit application and pursuant to the requirements at 40CFR 145.23(f)(13).

13.8.3. Prior to granting approval for the operation of a Class 6 well, the Director shall consider the following information:

13.8.3.a. The final area of review based on modeling, using data obtained during logging and testing of the well and the formation as required by subsections 13.8.3.b., 13.8.3.c., 13.8.3.d., 13.8.3.f., 13.8.3.g., and 13.8.3.j.;

13.8.3.b. Any relevant updates, based on data obtained during logging and testing of the well and the formation as required by subsections 13.8.3.c., 13.8.3.d., 13.8.3.f., 13.8.3.g., and 13.8.3.j., to the information on the geologic structure and hydrogeologic properties of the proposed storage site and overlying formations, submitted to satisfy the requirements of subsection 13.8.1.c.;

13.8.3.c. Information on the compatibility of the carbon dioxide stream with fluids in the injection zone(s) and minerals in both the injection and the confining zone(s), based on the results of the formation testing program, and with the materials used to construct the well;

13.8.3.d. The results of the formation testing program required at subsection 13.8.1.h.;

13.8.3.e. Final injection well construction procedures that meet the requirements of section 13.3.;

13.8.3.f. The status of corrective action on wells in the area of review;

13.8.3.g. All available logging and testing program data on the well required by section 13.5.;

13.8.3.h. A demonstration of mechanical integrity pursuant to section 6.2;

13.8.3.i. Any updates to the proposed area of review and corrective action plan, testing and monitoring plan, injection well plugging plan, post-injection site care and site closure plan, or the emergency and remedial response plan submitted under subsection 13.8.1., which are necessary to address new information collected during logging and testing of the well and the formation as required by all paragraphs of this section, and any updates to the alternative post-injection site care timeframe demonstration submitted under subsection 13.8.1., which are necessary to address new information collected during the logging and testing of the well and the formation as required by all paragraphs of this section; and

13.8.3.j. Any other information requested by the Director.

13.8.4. Owners or operators seeking a waiver of the requirement to inject below the lowermost USDW must also refer to subsection 14.8.4. and submit a supplemental report, as required at subsection 14.8.4.a. The supplemental report is not part of the permit application.

13.9. Post-injection Site Care and Site Closure.

13.9.1. The owner or operator of a Class 6 well must prepare, maintain, and comply with a plan for post-injection site care and site closure that meets the requirements of subsection 13.9.1.b. and is acceptable to the Director. The requirement to maintain and implement an approved plan is directly enforceable regardless of whether the requirement is a condition of the permit.

13.9.1.a. The owner or operator must submit the post-injection site care and site closure plan as a part of the permit application to be approved by the Director.

13.9.1.b. The post-injection site care and site closure plan must include the following information:

13.9.1.b.1. The pressure differential between pre-injection and predicted post-injection pressures in the injection zone(s);

13.9.1.b.2. The predicted position of the carbon dioxide plume and associated pressure front at site closure as demonstrated in the area of review evaluation required under subsection 14.9.3.a.;

13.9.1.b.3. A description of post-injection monitoring location, methods, and proposed frequency;

13.9.1.b.4. A proposed schedule for submitting post-injection site care monitoring results to the Director pursuant to subsection 13.6.3.a.5.; and,

13.9.1.b.5. The duration of the post-injection site care timeframe and, if approved by the Director, the demonstration of the alternative post-injection site care timeframe ensures non-endangerment of USDWs.

13.9.1.c. Upon cessation of injection, owners or operators of Class 6 wells must either submit an amended post-injection site care and site closure plan or demonstrate to the Director through monitoring data and modeling results that no amendment to the plan is needed. Any amendments to the post-injection site care and site closure plan must be approved by the Director, be incorporated into the permit, and are subject to the permit modification requirements at sections 14.18 and 14.20 of this rule, as appropriate.

13.9.1.d. At any time during the life of the geologic sequestration project, the owner or operator may modify and resubmit the post-injection site care and site closure plan for the Director's approval within 30 days of such change.

13.9.2. The owner or operator shall monitor the site following the cessation of injection to show the position of the carbon dioxide plume and pressure front and demonstrate that USDWs are not being endangered.

13.9.2.a. Following the cessation of injection, the owner or operator shall continue to conduct monitoring as specified in the Director-approved post-injection site care and site closure plan for at least 50 years or for the duration of the alternative timeframe approved by the Director pursuant to requirements in subsection 13.9.3., unless he/she makes a demonstration under subsection 13.9.2.b. The monitoring must continue until the geologic sequestration project no longer poses an endangerment to USDWs and the demonstration under subsection 13.9.2.b. is submitted and approved by the Director.

13.9.2.b. If the owner or operator can demonstrate to the satisfaction of the Director before 50 years or prior to the end of the approved alternative timeframe based on monitoring and other site-specific data, that the geologic sequestration project no longer poses an endangerment to USDWs, the Director may approve an amendment to the post-injection site care and site closure plan to reduce the frequency of monitoring or may authorize site closure before the end of the 50-year period or prior to the end of the approved alternative timeframe, where he or she has substantial evidence that the geologic sequestration project no longer poses a risk of endangerment to USDWs.

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

13.9.2.d. If the demonstration in subsection 13.9.2.c. cannot be made (i.e., additional monitoring is needed to ensure that the geologic sequestration project does not pose an endangerment to USDWs) at the end of the 50-year period or at the end of the approved alternative timeframe, or if the Director does not approve the demonstration, the owner or operator must submit to the Director a plan to continue post-injection site care until a demonstration can be made and approved by the Director.

13.9.3. Demonstration of alternative post-injection site care timeframe. At the Director's discretion, the Director may approve, in consultation with EPA, an alternative post-injection site care timeframe other than the 50-year default, if an owner or operator can demonstrate during the permitting process that an alternative post-injection site care timeframe is appropriate and ensures non-endangerment of USDWs. The demonstration must be based on significant, site-specific data and information including all data and information collected pursuant to section 13.8. and subsection 13.2.1 and must contain substantial evidence that the geologic sequestration project will no longer pose a risk of endangerment to USDWs at the end of the alternative post-injection site care timeframe.

13.9.3.a. A demonstration of an alternative post-injection site care timeframe must include consideration and documentation of:

13.9.3.a.1. The results of computational modeling performed pursuant to delineation of the area of review under section 5.4.;

13.9.3.a.2. The predicted timeframe for pressure decline within the injection zone, and any other zones, such that formation fluids may not be forced into any USDWs; and/or the timeframe for pressure decline to pre-injection pressures;

13.9.3.a.3. The predicted rate of carbon dioxide plume migration within the injection zone, and the predicted timeframe for the cessation of migration;

13.9.3.a.4. 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;

13.9.3.a.5. The predicted rate of carbon dioxide trapping in the immobile capillary phase, dissolved phase, and/or mineral phase;

13.9.3.a.6. The results of laboratory analyses, research studies, and/or field or site-specific studies to verify the information required in subsections 13.9.3.a.4. and 13.9.3.a.5.;

13.9.3.a.7. A characterization of the confining zone(s) including a demonstration that it is free of transmissive faults, fractures, and micro-fractures and of appropriate thickness, permeability, and integrity to impede fluid (e.g., carbon dioxide, formation fluids) movement;

13.9.3.a.8. The presence of potential conduits for fluid movement including planned injection wells and project monitoring wells associated with the proposed geologic sequestration project or any other projects in proximity to the predicted/modeled, final extent of the carbon dioxide plume and area of elevated pressure;

13.9.3.a.9. A description of the well construction and an assessment of the quality of plugs of all abandoned wells within the area of review;

13.9.3.a.10. The distance between the injection zone and the nearest USDWs above and/or below the injection zone; and

13.9.3.a.11. Any additional site-specific factors required by the Director.

13.9.3.b. Information submitted to support the demonstration in subsection 13.9.3.a., must meet the following criteria:

13.9.3.b.1. All analyses and tests performed to support the demonstration must be accurate, reproducible, and performed in accordance with the established quality assurance standards;

13.9.3.b.2. Estimation techniques must be appropriate and EPA-certified test protocols must be used where available;

13.9.3.b.3. 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;

13.9.3.b.4. Predictive models must be calibrated using existing information (e.g., at Class 1, Class 2, or Class 5 experimental technology well sites) where sufficient data are available;

13.9.3.b.5. Reasonably conservative values and modeling assumptions must be used and disclosed to the Director whenever values are estimated on the basis of known, historical information instead of site-specific measurements;

13.9.3.b.6. An analysis must be performed to identify and assess aspects of the alternative post-injection site care timeframe demonstration that contribute significantly to uncertainty. The owner or operator must conduct sensitivity analyses to determine the effect that significant uncertainty may contribute to the modeling demonstration.

13.9.3.b.7. An approved quality assurance and quality control plan must address all aspects of the demonstration; and,

13.9.3.b.8. Any additional criteria required by the Director.

13.9.4. Notice of intent for site closure. The owner or operator must notify the Director in writing at least 120 days before site closure. At this time, if any changes have been made to the original post-injection site care and site closure plan, the owner or operator must also provide the revised plan. The Director may allow for a shorter notice period.

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

13.9.6. The owner or operator must submit a site closure report to the Director within 90 days of site closure, which must thereafter be retained at a location designated by the Director for 10 years. The report must include:

13.9.6.a. Documentation of appropriate injection and monitoring well plugging as specified in section 13.4. and subsection 13.9.5. The owner or operator must provide a copy of a survey plat which has been submitted to the local zoning authority designated by the Director. The plat must indicate the location of the injection well relative to permanently surveyed benchmarks. The owner or operator must also submit a copy of the plat to the Regional Administrator of the appropriate EPA Regional Office;

13.9.6.b. Documentation of appropriate notification and information to such State, local and Tribal authorities that have authority over drilling activities to enable such State, local, and Tribal authorities to impose appropriate conditions on subsequent drilling activities that may penetrate the injection and confining zone(s); and

13.9.6.c. Records reflecting the nature, composition, and volume of the carbon dioxide stream.

13.9.7. Each owner or operator of a Class 6 injection well must record a notation on the deed to the facility property or any other document that is normally examined during title search that will in perpetuity provide any potential purchaser of the property the following information:

13.9.7.a. The fact that land has been used to sequester carbon dioxide;

13.9.7.b. The name of the State agency, local authority, and/or Tribe with which the survey plat was filed, as well as the address of the Environmental Protection Agency Regional Office to which it was submitted; and

13.9.7.c. The volume of fluid injected, the injection zone or zones into which it was injected, and the period over which injection occurred.

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

W. Va. Code R. § 47-13-13