Ala. Admin. Code r. 400-2-4-.09

Current through Register Vol. 43, No. 1, October 31, 2024

Section 400-2-4-.09 - Casing, Cementing, Mud, And Blowout Prevention Program

The design of the integrated casing, cementing, mud, and blowout prevention control program shall be based upon sound engineering principles, and must take into account the depths at which freshwater, hydrocarbon, and other mineral-bearing formations are expected to be penetrated, the formation fracture gradients and pressures expected to be encountered, and other pertinent geologic and engineering data and information about the area.

(1) Well Casing and Cementing.

(a) The operator shall case and cement all wells with a sufficient number of strings in a manner necessary to:

1. prevent release of fluids from any stratum through the wellbore (directly or indirectly) into the waters;

2. prevent communication between separate hydrocarbon-bearing strata (except such strata approved for commingling) and between hydrocarbon and water-bearing strata;

3. prevent contamination of freshwater-bearing strata;

4. support unconsolidated sediments; and

5. otherwise provide a means of controlling formation pressures and fluids.

(b) The operator shall install casing that meets American Petroleum Institute (API) standards. Cement shall meet API standards and shall be mixed with water of adequate quality so as not to degrade the setting properties. Safety factors in casing program design shall be of sufficient magnitude to provide optimum well control while drilling and to assure safe operations for the life of the well.

(c) For the purpose hereof, the several casing strings in order of normal installation are drive or structural casing, conductor casing, surface casing, intermediate casing, and production casing. All wells shall be cased and cemented in accordance with the following requirements, unless a specific exception is granted by the Supervisor following submission by the operator of an affidavit justifying said exception and demonstrating that the proposed exception is in accordance with standard industry practices and safe drilling techniques:

1. Drive or Structural Casing. This casing shall be set by drilling, driving, or jetting to a minimum depth of one hundred (100) feet below the waters floor or to such greater depth required to support unconsolidated deposits and to provide hole stability for initial drilling operations. A calculated cement volume sufficient to fill the annular space back to the waters floor shall be used if the drive or structural casing is set by drilling.

2. Conductor Casing.

(i) This casing shall be set before drilling into shallow formations known to be abnormally pressured or known to contain oil or gas; or upon encountering such formations. This casing shall be set in accordance with conductor and surface casing setting depths in Table 1 below. A conductor string of casing (the first string run other than any structural or drive casing) shall be cemented with a calculated volume of cement sufficient to fill the annular space back to the waters floor. To facilitate casing removal upon well abandonment, cement may be washed out or displaced to a depth not to exceed forty (40) feet below the waters floor, unless otherwise approved by the Supervisor.

(ii) The Supervisor or Board may approve a request to waive the requirement for setting conductor casing at a specific well location provided at least one well has been drilled near the specified well location and the well logs and mud monitoring procedures from the nearby well demonstrate the absence of shallow hydrocarbons and shallow hazards.

3. Surface Casing.

(i) This casing shall be set in accordance with conductor and surface casing setting depths in Table 1 below, and cemented in a manner necessary to protect all freshwater-bearing strata, and provide well control until the next string of casing is set. This casing shall be cemented with a calculated volume of cement sufficient to fill the annular space back to the waters floor.

(ii) Surface casing shall not be used as production casing, unless otherwise approved by the Supervisor.

4. Conductor and Surface Casing Setting Depths.

(i) These casing strings shall be properly cemented in place prior to drilling below the minimum setting depths required in Table 1 below. However, if the operator does not set surface or first intermediate casing below the base of the underground source of drinking water (USDW) containing fluids of less than ten thousand (10,000) milligrams per liter total dissolved solids, the operator may not be allowed to dispose of tank fluids in the well. See Rule 400-2-4-.10(1), relating to Disposal of Tank Fluids.

Table 1. Minimum Required Setting Depth Below Waters Floor in True Vertical Depth (TVD)

Proposed TVD from Minimum Conductor Minimum Surface

Rotary Table (ft) Casing (ft) Casing (ft)

0 - 6,000 0 750

6,001 - 12,000 750 2,000

Greater than 12,000 750 Into Selma Chalk

(ii) The Supervisor may approve exceptions to the requirements of Table 1 above in order to permit the casing to be set in a competent bed, through formations determined desirable to be isolated from the wellbore, or to protect against abnormally pressured formations or other abnormal well conditions. The Supervisor may recommend setting depths for those casing strings prior to encountering abnormally pressured formations or other abnormal well conditions. The operator may request the approval of an alternative casing program provided that the operator certifies or provides an affidavit to attest in writing that the casing design demonstrates that all normal pressure zones will be isolated from abnormal pressure through the setting of an intermediate casing string and is in accordance with accepted industry practices and safe drilling procedures.

5. Intermediate Casing. Intermediate or protective casing shall be set when required by abnormal pressure, mud weights, sediments, and other well conditions. A quantity of cement sufficient to cover and isolate all hydrocarbon zones and to isolate abnormal pressure intervals from normal pressure intervals shall be used. If a liner is used as an intermediate string, the cement shall be tested by a fluid entry or pressure test to determine whether a seal between the liner top and next larger casing string has been achieved. The test shall be recorded in the driller's log. When such liner is used as production casing, it shall be extended to the surface and cemented to avoid surface casing being used as production casing.

6. Production Casing. Production casing shall be set before completing the well for production. It shall be cemented in a manner necessary to cover or isolate all zones which contain hydrocarbons. A calculated volume of cement sufficient to fill the annular space at least five hundred (500) feet above the top of the uppermost hydrocarbon zone shall be used. When a liner is used as production casing, the testing of the seal between the liner top and next larger string shall be conducted as in the case of intermediate liners.

(d) If there are indications of inadequate primary cementing (such as lost returns, cement channeling, or mechanical failure of equipment) of the surface, intermediate, or production casing strings, the operator shall evaluate the adequacy of the cementing operations by pressure testing the casing shoe, running a cement bond log or a cement evaluation tool log, running a temperature survey, or a combination thereof before continuing operations. If the evaluation indicates inadequate cementing, the operator shall re-cement or take other actions as approved by the Supervisor. The operator shall verify the adequacy of the remedial cementing operations as described above.

(e) Pressure Testing. An operator shall give notice to the Supervisor prior to pressure testing.

1. After primary cementing any of the above strings, drilling shall not be resumed until a time lapse of eight (8) hours under pressure for the conductor casing string and twelve (12) hours under pressure for all other strings. Cement is considered under pressure if one or more float valves are employed and are shown to be holding the cement in place or when other means of holding pressure are used.

2. After cementing and prior to drilling the plug, all casing strings, except the drive or structural casing, shall be pressure tested. The conductor casing shall be tested to a minimum pressure of two hundred fifty (250) pounds per square inch (psi). All other casing strings shall be pressure tested to fifty percent (50%) of the specified minimum internal yield strength of the weakest section of the casing string. Test pressure may be limited by hydrostatic pressures based on internal and external mud weights. All pressure tests are to be held for thirty (30) minutes. If during this test period the pressure declines more than ten percent (10%) of the initial test pressure or if any other indications of a leak are found, the casing shall be re-cemented, repaired, or an additional casing string run. The casing shall then be tested again in the same manner as prescribed herein. The above procedures shall be repeated until a satisfactory test is obtained. All casing pressure tests shall be recorded in the driller's log.

3. In the event of prolonged drill-pipe rotation within a casing string run to surface or of extended operations such as milling, fishing, jarring, washing over, working over, or other operations which could damage the casing, such casing string shall be pressure tested, and if required by the Supervisor, evaluated by a logging technique such as a caliper or casing inspection log every thirty (30) days. The evaluation results shall be submitted to the Supervisor with a determination of the integrity of casing for continued service during both drilling and workover operations, and over the producing life of the well. If the integrity of the casing in the well is deteriorated to a potentially unsafe level, remedial operations shall be conducted with a plan approved by the Supervisor prior to continuing operations.

4. Production casing shall be tested during completion operations to the estimated surface shut in tubing pressure for thirty (30) minutes using a fluid, approved by the Supervisor, with a pressure loss of ten percent (10%) or less. If a failure of the test occurs, remedial operations shall be conducted with a plan approved by the Supervisor prior to continuing operations.

(f) Recording Test Pressures.

1. Proper documentation of pressure tests, including beginning and ending pressures and the duration of each test, shall be recorded in a daily drilling report.

2. Unless witnessed by an agent of the Board, all pressure tests and re-tests shall be documented with a properly calibrated continuous pressure recorder or other pressure-recording device acceptable to the Supervisor. A representative of the operator shall sign the pressure test record(s) following completion of each pressure test.

3. The operator shall maintain all pressure test records at the well site during drilling operations. Such records shall be made available for inspection upon request.

4. The operator shall maintain all pressure test records for a minimum of three (3) years from the date such pressure tests were conducted.

(g) Reporting Test Pressures. The operator shall report pressure tests on Form OGB-7.

(2) Drilling Mud Tanks. All tanks utilized to contain fluids during drilling, completion, and workover of a well shall be constructed and maintained so as to prevent pollution.

(3) Drilling Mud.

(a) The operator shall maintain readily usable quantities of mud sufficient to insure well control. The testing procedures, characteristics, and use of drilling mud and the conduct of related drilling procedures shall be such as are necessary to prevent blowouts.

(b) Mud Control.

1. Before starting out of the hole with drill pipe, the mud shall be circulated and conditioned on or near bottom. When coming out of the hole with drill pipe, the annulus shall be filled with mud before the change in mud level decreases the hydrostatic pressure seventy-five (75) pounds per square inch (psi) or every five (5) stands of drill pipe, whichever gives a lower decrease in hydrostatic pressure. A device for measuring the amount of mud required to fill the hole shall be utilized. The volume of mud required to fill the hole shall be watched, and any time there is an indication of swabbing, or influx of formation fluids, the necessary safety devices and actions shall be employed to control the well. The mud shall be circulated and conditioned on or near bottom, unless well or mud conditions prevent running the drill pipe back to bottom. The mud in the hole shall be circulated or reverse circulated prior to pulling drillstem test tools from the hole.

2. An operable gas separator shall be installed in the mud system prior to commencement of drilling operations. The separator shall be maintained for use throughout the drilling and completion of the well.

(c) Mud Testing Equipment. Mud testing equipment shall be maintained on the drilling facility at all times, and mud tests shall be performed daily, or more frequently as conditions warrant. Suitable mud test records shall be kept and made available to the Supervisor's representative upon request.

(d) Mud System Monitoring Equipment. The following equipment shall be installed and used throughout drilling operations below the conductor casing (unless noted otherwise, such equipment shall have derrick floor indicators):

1. Recording mud pit level indicator to determine mud pit volume gains and losses. This indicator shall include a visual or audio warning device.

2. Mud volume measuring device for accurately determining mud volumes required to fill the hole on trips.

3. Mud return indicator to determine that returns essentially equal the pump discharge rate.

4. Gas-detecting equipment to monitor the drilling mud returns, with indicators located in the mud-logging compartment or the derrick floor. If the indicators are in the mud-logging compartment, there shall be a means of immediate communication with the derrick floor, and the equipment shall be continually manned.

(4) Blowout Prevention Equipment.

(a) The operator shall install, use, and test blowout preventers and related well-control equipment in a manner necessary to prevent blowouts. Drilling shall not be conducted below the conductor string of casing until equipment for circulating drilling fluid to the drilling facility and at least one remotely controlled blowout preventer are installed. Accumulators or accumulators and pumps shall maintain a pressure capacity reserve at all times to provide for repeated operation of hydraulic preventers. Blowout preventers and related well-control equipment shall be pressure-tested when installed, after each string of casing is cemented, and at such other times as prescribed by the Supervisor.

(b) The working pressure of the annular preventer need not exceed five thousand (5,000) pounds per square inch (psi), unless a higher working pressure is required by the Supervisor. When the anticipated surface pressure exceeds the rated working pressure of the annular preventer, the operator shall include in the application for a drilling permit a well control procedure which indicates how the annular preventer will be utilized and the pressure limitations that will be applied during each mode of pressure control.

(c) Blowout prevention equipment shall be installed, used, and tested in accordance with the following requirements:

1. Conductor Casing. Before drilling below this string, at least one remotely controlled annular-type blowout preventer and equipment for circulating the drilling fluid to the drilling facility shall be installed. To avoid formation fracturing from complete shut-in of the well, a large diameter pipe with control valves shall be installed on the conductor casing below the blowout preventer so as to permit the diversion of hydrocarbons and other fluids; except that, when the blowout preventer assembly is on the waters floor, the choke and kill lines shall be equipped to permit the diversion of hydrocarbons and other fluids.

2. Surface and Intermediate Casings. Before drilling below these casing strings, the blowout prevention equipment shall include a minimum of four (4) remotely controlled, hydraulically operated, blowout preventers with a working pressure which equals or exceeds the maximum anticipated surface pressure, including two equipped with pipe rams, one with blind rams, and one annular-type; a drilling spool with side outlets, if side outlets are not provided in the blowout preventer body; a choke manifold; a kill line; and a fill-up line.

3. Auxiliary Equipment. The following auxiliary equipment shall be provided and maintained in operable condition at all times:

(i) A kelly cock shall be installed below the swivel, and an essentially full-opening valve of such design that it can be run through blowout preventers shall be installed at the bottom of the kelly. A wrench to fit each valve shall be stored in a conspicuous location readily accessible to the drilling crew.

(ii) An inside blowout preventer and an essentially full-opening drill string safety valve in the open position shall be maintained on the derrick floor at all times while drilling operations are being conducted. These valves shall be maintained on the derrick floor to fit all connections that are in the drill string.

(iii) A safety valve shall be available on the derrick floor assembled with the proper connection to fit the casing string that is being run in the hole at the time.

4. Testing Frequency. Ram-type and annular-type blowout preventers and related control equipment shall be tested when installed; before drilling out after each casing string has been set; except for blind and blind shear rams, at least once each week, but not exceeding seven (7) days between tests; and following repairs that required disconnecting a pressure seal in the assembly. A period of more than seven (7) days between blowout preventer tests may be allowed, with the Supervisor's approval when well operations prevent testing, provided the tests will be conducted as soon as possible before normal operations resume and the reason for postponing testing is entered in the driller's log, or when written justification has been submitted to and approved by the Supervisor justifying an extension between blowout preventer pressure tests. Auxiliary well control equipment such as choke manifold valves, kelly cocks, drill string safety valves, and inside blowout preventers shall also be pressure tested weekly. Casing safety valves shall be actuated prior to running casing. All blowout preventer tests shall be recorded in the driller's log. Testing shall be at staggered intervals to allow each drilling crew an opportunity to operate the equipment.

5. Testing Limits. Ram-type and related control equipment shall be tested at the anticipated surface pressure or at seventy percent (70%) of the minimum internal yield pressure of the casing, whichever is lesser. The annular-type preventer shall be tested initially at seventy percent (70%) of its rated working pressure, at seventy percent (70%) of the minimum internal yield pressure of the casing, or at the anticipated surface pressure, whichever is less. Subsequent tests of the annular-type preventer may be at lesser pressures.

6. Blowout Preventer Drills. All drilling personnel shall be trained in blowout preventer drills and be familiar with the equipment before starting work on the well. A blowout preventer drill shall be conducted for each drilling crew to insure that crews are properly trained to carry out emergency duties. A blowout preventer drill may be required by the Supervisor at any time during the drilling operations after notifying and consulting with the operator. All blowout preventer crew drills shall be recorded in the driller's log.

Author: State Oil and Gas Board

Ala. Admin. Code r. 400-2-4-.09

New Rule: Filed April 11, 2000; effective May 16, 2000.

Statutory Authority:Code of Ala. 1975, §§ 9-17-1, etseq.