La. Admin. Code tit. 43 § XVII-617

Current through Register Vol. 50, No. 11, November 20, 2024

Section XVII-617 - Well Construction and Completion

A. Injection Well Construction Requirements

1. General. All phases of Class VI well construction shall be supervised by a person knowledgeable and experienced in practical drilling engineering and is familiar with the special conditions and requirements of injection well construction. All materials and equipment used in the construction of the well and related appurtenances shall be designed and manufactured to exceed the operating requirements of the specific project, including flow induced vibrations. The owner or operator must ensure that all wells are constructed and completed to:

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

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

c. allow for continuous monitoring of the annulus space between the injection tubing and long string casing.

2. Casing and Cementing of Class VI Wells

a. Casing and cement or other materials used in the construction of each Class VI well must have sufficient structural strength and be designed for the life of the geologic sequestration project. All well materials must be compatible with fluids that 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 commissioner. The casing and cementing program must be designed to prevent the movement of fluids into or between USDWs. In order to allow the commissioner to evaluate casing and cementing requirements, the owner or operator must provide the following information:

i. depth to the injection zone(s);

ii. injection pressure, external pressure, internal pressure, and axial loading;

iii. hole size;

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

v. corrosiveness of the carbon dioxide stream and formation fluids;

vi. down-hole temperatures;

vii. lithology of injection and confining zone(s);

viii. type or grade of cement and cement additives including slurry weight (lb/gal) and yield (cu. ft./sack); and

ix. quantity, chemical composition, and temperature of the carbon dioxide stream.

b. The surface casing of any Class VI well must extend into a confining bed-such as a shale-below the base of the deepest formation containing a USDW. The casing shall be cemented with a sufficient volume of cement to circulate cement from the casing shoe to the surface. The commissioner will not grant an exception or variance to the surface casing setting depth.

c. At least one long string casing, using a sufficient number of centralizers, shall be utilized in the well. If the casing is to be perforated for injection, then the approved casing shall extend through the base of the injection zone. If an approved alternate construction method is used, such as the setting of a screen, the casing shall be set to the top of the injection interval. Regardless of the construction method utilized, the casings shall be cemented by circulating cement from the casing shoe to the surface in one or more stages.

d. Circulation of cement may be accomplished by staging. Circulated to the surface shall mean that actual cement returns to the surface were observed during the primary cementing operation. A copy of the cementing companys job summary or cementing tickets indicating returns to the surface shall be submitted as part of the pre-operating requirements.

i. The commissioner may approve an alternative method of cementing in cases where the cement cannot be circulated to the surface. If cement returns are lost during cementing, the owner or operator shall have the burden of showing-using wireline logs-that sufficient cement isolation is present to prevent the movement of fluid behind the well casing.

ii. Remedial cementing shall be done before proceeding with further well construction, completion, or conversion if adequate cement isolation of the USDW or the injection zone within the casing-formation annulus cannot be demonstrated.

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.

3. Casing and Casing Seat Tests. The owner or operator shall monitor and record the tests using a surface readout pressure gauge and a chart or a digital recorder. All instruments shall be calibrated properly and in good working order. If there is a failure of the required tests, the owner or operator shall take necessary corrective action to obtain a passing test.

a. Casing. After cementing each casing, but before drilling out the respective casing shoe, all casings shall be hydrostatically pressure tested to verify casing integrity and the absence of leaks. For surface casing, the stabilized test pressure applied at the surface shall be a minimum of 500 pounds per square inch gauge (PSIG). The stabilized test pressure applied at the surface for all other casings shall be a minimum of 1,000 PSIG. All casing test pressures shall be maintained for one hour after stabilization. Allowable pressure loss is limited to five percent of the test pressure over the stabilized test duration.

i. Casing test pressures shall never exceed the rated burst or collapse pressures of the respective casings.

b. Casing Seat. The casing seat and cement of any intermediate and injection casings shall be hydrostatically pressure tested after drilling out the casing shoe. At least 10 feet of formation below the respective casing shoes shall be drilled before the test. The test pressure applied at the surface shall be a minimum of 1,000 PSIG. The test pressure shall be maintained for one hour after pressure stabilization. Allowable pressure loss is limited to five percent of the test pressure over the stabilized test duration.

i. Casing seat test pressures shall never exceed the known or calculated fracture gradient of the appropriate subsurface formation.

4. Tubing and Packer

a. Tubing and packer materials used in the construction of each Class VI well must be compatible with fluids that 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 commissioner.

b. Injection into a Class VI well must be through tubing with a packer set at a depth opposite an interval of cemented casing at a location approved by the commissioner.

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

i. depth of setting;

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

iii. maximum proposed injection pressure;

iv. maximum proposed annular pressure;

v. proposed injection rate (intermittent or continuous) and volume and/or mass of the carbon dioxide stream;

vi. size of tubing and casing; and

vii. tubing tensile, burst, and collapse strengths.

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

1. During the drilling and construction of a Class VI well, appropriate logs, surveys and tests must be run to determine or verify the depth, thickness, porosity, permeability, and lithology of, and the salinity of formation fluids in all relevant geologic formations to ensure conformance with the injection well construction requirements of §617 and to establish accurate baseline data against which future measurements may be compared. The well operator must submit to the commissioner 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:

a. deviation checks during drilling of all boreholes 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;

b. before and upon installation of the surface casing:

i. resistivity, gamma-ray, spontaneous potential, and caliper logs before the casing is installed; and

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

c. before and upon installation of intermediate and long string casing:

i. resistivity, gamma-ray, spontaneous potential, porosity, caliper, fracture finder logs, and any other logs the commissioner requires for the given geology before the casing is installed; and

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

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

i. a pressure test with liquid or gas;

ii. a tracer-type survey to detect fluid movement behind casing such as a radioactive tracer or oxygen-activation logging, or similar tool;

iii. a temperature or noise log;

iv. a casing inspection log.

e. any alternative methods that provide equivalent or better information and that are required by and approved by the commissioner.

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 commissioner a detailed report prepared by a log analyst that includes: well log analyses (including well logs), core analyses, and formation fluid sample information. The commissioner 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 commissioner may require the owner or operator to core other formations in the borehole.

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

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

a. fracture pressure;

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

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

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

a. a pressure fall-off test; and,

b. a pump test; or

c. injectivity tests.

6. The owner or operator must notify the Office of Conservation at least 72 hours before conducting any wireline logs, well tests, or reservoir tests.

La. Admin. Code tit. 43, § XVII-617

Promulgated by the Department of Natural Resources, Office of Conservation, LR 4770 (1/1/2021).

AUTHORITY NOTE: Promulgated in accordance with R.S. 30:4 et seq., 30:22 et seq., and 30:1101 et seq.