Or. Admin. Code § 632-010-0014

Current through Register Vol. 63, No. 11, November 1, 2024

Section 632-010-0014 - Drilling Practices

(1) Pits for drill cuttings: At every well site, the permittee must provide and use one or more pits, sumps, or above-ground containers of approved design and size for holding the drill cuttings and fluid removed from the well. All pits, sumps, or above-ground containers must be constructed in a way that allows for egress.

(2) Casing and sealing off formations general requirements:

(a) Surface casing:

(A) Surface casing used in all wells must be of suitable size, grade, condition, and wall thickness;

(B) In areas where pressure and formation are unknown, sufficient surface casing must be run to reach a depth below all known potable fresh water levels;

(C) In areas where subsurface conditions have been established by drilling experience, sufficient surface casing must reach a depth 100 feet below all fresh-water levels;

(D) The depths referred to in paragraphs (B) and (C) of this subsection must be at least 25 percent of the proposed next casing point or total depth, unless otherwise approved by the department;

(E) Surface casing and conductor pipe must be cemented. Surface casing must be cemented by the pump and plug or displacement method with sufficient cement to circulate to the surface. The conductor pipe must be cemented to the surface to prevent the migration of fluids to other zones or to the surface; and

(F) Cement must be allowed to set a minimum of 12 hours before drilling the plug.

(b) Other casing requirements: Each fluid-bearing zone above the producing horizon must be cased and sealed off to prevent the migration of formation fluids to other zones. Such casing and sealing off must be completed and tested in a manner and method approved by the department.

(c) A formation leakoff test or a casing shoe integrity test may be required by the department. If required, the results must be provided to the department for review and approval prior to the continuation of drilling operations.

(3) When drilling, a suitably weighted mud-laden fluid must be continuously maintained in the hole, from top to bottom, in accordance with recognized safe practices. The permittee may request permission from the department to use other fluids. The request must be approved in writing by the department prior to use.

(4) Wellhead equipment:

(a) When drilling in areas where high pressures are likely to exist, as determined by the department, all proper and necessary precautions must be taken for keeping the well under control, including, but not limited to, the use of blowout preventers and high-pressure fittings attached to casing strings properly anchored and cemented:

(A) The Blowout Prevention Equipment schematic diagram must indicate the minimum size and pressure rating of all components of the wellhead and blowout preventer assembly;

(B) The department, on a site-specific basis, may require the use of blowout preventers or other methods of controlling shallow coal bed methane wells;

(C) All blowout preventers, choke lines, and choke manifolds must be installed above ground level. Casing heads and optional spools may be installed below ground level provided they are visible and accessible;

(D) Blowout preventer equipment and related casing heads and spools must have a vertical bore no smaller than the inside diameter of the casing to which they are attached;

(E) All ram blowout preventers must be equipped with hydraulic locking devices and manual locking devices with hand wheels extending outside of the rig's substructure;

(F) Blowout prevention equipment installed on the well must have a rated expected formation pressure higher than the working pressure;

(G) In addition to the minimum blowout preventer requirements outlined in this section, wells drilled while using tapered drill strings must use either a variable bore pipe ram preventer or additional ram type blowout preventers to provide a minimum of one set of pipe rams for each size of drill pipe in use, and one set of blind rams.

(b) Unless otherwise approved by the department, the blowout prevention equipment must include a minimum of at least one annular blowout preventer and one double-gate preventer with pipe and blind rams or two single-ram type preventers; one equipped with pipe rams and the other with blind rams. Ram preventers or a drilling spool must have side outlets with a minimum inside diameter of 2 inches on the kill side, and 3 inches on the choke side to accommodate choke and kill lines. Outlets on the casing head may not be used to attach choke or kill lines;

(A) Additional blowout preventer equipment includes, but is not limited to, one upper kelly cock, and one drill pipe safety valve with subs to fit all drill string connections in use;

(B) Choke manifold and related equipment consists of one kill line valve, one check valve, two choke line valves, choke line, two manual adjustable chokes (each with one valve located upstream of the choke), one bleed line valve, and one mud service pressure gauge with a valve upstream of the gauge;

(C) All choke manifold valves, choke and kill line valves, and the choke line must be full bore. Choke line valves, choke line, and bleed line valves must have an inside diameter equal to or greater than the minimum requirement for the blowout preventer or drilling spool outlet;

(D) The choke line must be as straight as possible, and any required turns must be made with flow targets at all bends and on block tees. All connections exposed to well bore pressure must be welded, flanged, or clamped. Choke hoses with flanged connections designed for that purpose will be accepted in lieu of a steel choke line. The choke line must be securely anchored;

(E) The accumulator must have sufficient capacity to operate the blowout preventer equipment as outlined in this section, and have two independently powered pump systems connected to start automatically after a 200 psi drop in accumulator pressure, or one independently powered pump system connected to start automatically after a 200 psi drop in accumulator pressure and an emergency nitrogen back-up system connected to the accumulator manifold. Blowout preventer controls may be located at the accumulator or on the rig floor;

(F) A hydraulically operated accumulator; and

(G) A pit horn.

(c) Minimum requirements for blowout preventer equipment testing:

(A) All blowout preventers and related equipment that may be exposed to well pressure must be tested first to a low pressure and then to a high pressure;

(i) A stable low of 200-300 psi must be maintained for at least 30 minutes prior to initiating the high-pressure test;

(ii) The high-pressure test must be to the rated working pressure of the ram type blowout preventer equipment and related equipment, or to the rated working pressure of the wellhead on which the stack is installed, whichever is lower. A stable high-pressure test must be maintained for 30 minutes;

(iii) Annular blowout preventer must be high-pressure tested to 50 percent of the rated working pressure and maintain a stable pressure for 30 minutes; and

(iv) Manual adjustable chokes not designed for complete shutoff must be pressure tested only to the extent of determining the integrity of the internal seating components to maintain back pressure. Hydraulic chokes designed for complete shutoff must be pressure tested to 50 percent of the rated working pressure.

(B) All casing below the conductor pipe must be pressure tested to 0.22 psi per foot or 1,500 psi, whichever is greater, but not to exceed 70 percent of the minimum internal yield strength of the casing. A stable pressure must be maintained for 30 minutes. Higher pressures, using a test plug in the casing head, may be required by the department on a case-by-case basis;

(C) During blowout preventer pressure testing the casing must be isolated with a test plug set in the wellhead, and the appropriate valve must be opened below the test plug to detect any leakage that may occur due to failure of the test plug;

(D) The choke and kill line valves, choke manifold valves, upper and lower kelly cocks, drill pipe safety valves, and inside blowout preventer must be tested with pressure applied from the wellbore side. All valves, including check valves, located downstream of the valve being pressure tested, will be in the open position;

(E) Manually operated valves and chokes on the blowout preventer stack, choke and kill lines, or choke manifold must be equipped with a handle provided by the manufacturer, or a functionally equivalent fabricated handle, and be lubricated and maintained to permit operation of the valves without the use of additional wrenches or levers;

(F) All operational components of the blowout preventer equipment must be function tested at least once a week to verify the components' intended operations;

(G) The blowout prevention equipment must be pressure tested when installed, prior to drilling out casing shoes, and following repairs or reassembly of the preventers that require disconnecting a pressure seal in the assembly;

(H) During drilling operations, blowout prevention equipment must be actuated to test proper functioning once each trip, or once each week, whichever is more frequent;

(I) All flange bolts must be inspected at least weekly and retightened as necessary during drilling operations;

(J) The auxiliary control systems must be maintained in working order and be inspected daily to check the mechanical condition and effectiveness and to ensure personnel at the site are familiar with their operation;

(K) A blowout prevention practice drill must be conducted weekly for each drilling crew, and be recorded on the driller's log;

(L) The results of all blowout preventer equipment pressure tests and function tests must be recorded on the tour sheet and include the type of test, testing sequence, low and high pressures, duration of each test, and results of each test;

(M) All blowout preventer equipment test results submitted to the department must have a signed certification stating that the testing procedures of the blowout preventer equipment and the passing results are accurate and comply with OAR 632-010-0014;

(N) The department may require any blowout preventer equipment test to be conducted or witnessed by an independent third party that will report all test results to the department for review and approval prior to commencement of drilling operations;

(O) All tool pushers, drilling superintendents, and permittees' representatives (when the permittee is in control of the drilling) are required to have completed an API, IADC, or similar governing body sanction well control certification program and furnish the certification of satisfactory of completion to the department prior to the start of any drilling operations. The certification must be renewed every two years.

(5) Inclination Surveys:

(a) Unless exempted by the department, for all wells where production will be from a depth greater than 1500 feet, inclination surveys to determine the angle of the hole from the vertical must be performed before completion.

(b) The department may, for good cause, require a permittee to perform a directional survey to determine the location of the borehole at various intervals.

Or. Admin. Code § 632-010-0014

GMI 1, f. 1-27-54; GMI 1-1979, f. & ef. 1-25-79; GMI 1-1982, f. & ef. 6-25-82; GMI 4-1985, f. & ef. 11-20-85; GMI 6-1990, f. & cert. ef. 12-5-90; GMI 2-1995, f. & cert. ef. 3-10-95; DGMI 1-2013, f. & cert. ef. 3-21-13

Stat. Auth.: ORS 520

Stats. Implemented: ORS 520.095