(a) A storage operator shall ensure and demonstrate to the commission that each Class VI well, including a Class II well converted to a Class VI well to use for carbon storage, is constructed and completed to

1. (1) prevent the movement of fluid into or between underground sources of drinking water or into any unauthorized zone;
2. (2) permit the use of appropriate testing devices and workover tools; and
3. (3) permit continuous monitoring of the annulus space between the injection tubing and long string casing.

(b) The casing and cement or other materials used in the construction of each Class VI well must have sufficient structural strength and be designed for the life of the storage facility. All well material must be compatible with fluid with which the material 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 commission. The storage operator's casing and cementing program shall be designed to prevent the movement of fluid into or between underground sources of drinking water. In order to allow the commission to determine and specify casing and cementing requirements for a Class VI well, the storage operator shall provide the following information:

1. (1) depth to the injection zone;
2. (2) injection pressure, external pressure, internal pressure, and axial loading;
3. (3) hole size;
4. (4) size and grade of all casing strings, including wall thickness, external diameter, nominal weight, length, joint specification, and construction material;
5. (5) corrosiveness of the carbon dioxide stream and formation fluid;
6. (6) down-hole temperatures;
7. (7) lithology of injection and confining zone or zones;
8. (8) type or grade of cement and cement additives; and
9. (9) quantity, chemical composition, and temperature of the carbon dioxide stream.

(c) In addition to the requirements of (b) of this section, the following requirements apply to the construction and mechanics of a Class VI well:

1. (1) the surface casing must extend through the base of the lowermost underground source of drinking water and be cemented to the surface through the use of a single or multiple strings of casing and cement;
2. (2) 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;
3. (3) the circulation of cement may be accomplished by staging; the commission may approve an alternative method of cementing in cases where the cement cannot be recirculated to the surface, provided the storage operator can demonstrate by using logs that the cement does not allow fluid movement behind the well bore;
4. (4) the cement and cement additives must be compatible with the carbon dioxide stream and formation fluid and of sufficient quality and quantity to maintain integrity over the design life of the storage facility; in demonstrating this compatibility, 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 underground sources of drinking water are not endangered.

(d) A storage operator shall ensure that the tubing and packer material used in the construction of each Class VI well are compatible with fluid with which the material may be expected to come into contact and must meet or exceed standards developed for such material by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the commission. Accordingly, each storage operator shall inject fluid into a Class VI well through tubing with a packer set at a depth opposite a cemented interval at the location approved by the commission. To allow the commission to determine and specify requirements for tubing and packer, the storage operator shall submit the following information as part of a storage facility permit process under 20 AAC 25.1080:

1. (1) depth of setting;
2. (2) characteristics of the carbon dioxide stream, chemical content, corrosiveness, temperature, and density, and types of formation fluid;
3. (3) maximum proposed injection pressure;
4. (4) maximum proposed annular pressure;
5. (5) proposed injection rate, intermittent or continuous, and volume or mass of the carbon dioxide stream;
6. (6) size of tubing and casing; and
7. (7) tubing tensile, burst, and collapse strengths.