(1) All drilling for oil and gas on State oil and gas leases shall be conducted in accordance with the provisions of this Section 2128.

(2) Prior to the commencement of drilling operations on any well, each well drilling proposal shall be approved by the Staff.

(3) Prior to the commencement of drilling operations on any well, the lessee shall obtain all necessary permits and approvals required by all applicable laws and regulations. The lessee shall file copies of those permits and approvals and related documents with the State Lands Commission prior to the commencement of drilling operations. The lessee shall abide by the terms of those permits and approvals, including but not limited to, any required notifications prior to the lessee's commencement of drilling operations.

(1) Well location map; proposed well course; detailed drilling procedures; casing and cementing program; blowout prevention program; drilling mud program; directional survey program; electrical logging, mud logging and sampling programs; and well testing procedures.

(2) Specifications and performance data of drilling rig; critical operations and curtailment plan; oil spill contingency plan, and hydrogen sulfide contingency plan.

(1) All wells shall be cased and cemented in such a manner as to protect all zones that contain oil, gas, or fresh water, so as to provide well control during drilling operations.

(2) The casing setting depths shall be based upon all relevant geological and engineering factors, including the presence of shallow geological anomalies, the presence or absence of hydrocarbons, formation fracture gradients, formation pore pressures, water depth, and zones of lost circulation or of other unusual characteristics. Casing setting depths below the second surface casing shall be justified by calculations of the competency of the preceding casing seat to withstand anticipated mud weights, as well as the pressure generated by simulated well kicks from known or potential gas bearing zones, taking into consideration actual or estimated reservoir pressures, formation fracture gradients, minimum programmed mud weights and anticipated kick volumes.

In situations where formation fracture gradients are not known, a formation leak-off or predetermined equivalent mud weight test shall be conducted to obtain estimated formation fracture gradients for use in the calculations. These tests shall be conducted after drilling a maximum of 50 feet of new hole below the shoe of the second surface casing and intermediate casing strings. Additional tests should be performed as the drilling progresses in order to verify the competency of the formation to withstand anticipated pressures, and to further refine casing setting depths. The results of all the tests shall be recorded on the driller's log and reported to the Staff.

The known and estimated factors and calculations used to determine the casing setting depths, as well as the casing design safety factors and specifications shall be shown in the casing and cementing program required in Section 2128(d)(1).

(3) The lessee shall utilize current technological methods during drilling operations to aid in the prediction of possible abnormal pressured zones in order to minimize the potential for the development of a formation flow or kick.

(4) All casing shall be new pipe or the equivalent and shall be inspected by the lessee in a manner approved by the Staff. The inspection shall be sufficient to detect transverse and longitudinal defects, to determine wall thickness, pipe eccentricity and grade uniformity, and shall include a 100 percent thread check of the exposed threads. Casing inspection reports shall be maintained by the lessee in its district office for a period of five years, and shall be available to the Staff.

(5) Except in cases where casing requirements have been established by field drilling rules or where geological and engineering factors indicate that a different program should be used, the following casing and setting-depth requirements shall be included in all well casing programs. All depths refer to true vertical depth (TVD) below the ocean floor or ground level unless otherwise specified. In order of normal installation the casing strings are identified as conductor, first and second surface, intermediate, and production casing.

(1) The lessee shall utilize appropriate cementing technology and casing equipment in order to achieve adequate cement fillup and bonding on all casing cementing operations.

(2) The conductor (if drilled or jetted) and surface casing strings shall be cemented with sufficient cement to fill the annular space back to the surface or ocean floor. Cement fill shall be verified by the observation of cement returns. The cementing operation may be considered adequate if cement is circulated to the surface or ocean floor within the range of the calculated hole volume. In the event that cement returns are not obtained or cement channeling occurs during cementing of the surface casing strings, the lessee shall run a temperature and/or cement bond survey and/or pressure test the casing shoe to evaluate the adequacy of the cement job. If the casing string is thereby determined to be inadequately cemented, the lessee shall recement the casing string or perform other operations as approved by the Staff to ensure the competency of the cement job.

(3) The intermediate casing string(s) shall be cemented with sufficient cement to fill the annular space a minimum of 200 feet into the preceding larger casing string. The protective and production casing strings shall be cemented in a manner such that cement will cover or isolate zones of unusually high or low pressure and zones containing hydrocarbons. Sufficient cement shall be used to provide annular fillup at least 500 feet above the zones to be covered or isolated or above the casing shoe in cases where zonal coverage is not required. A cement bond survey shall be run following primary cementing of the intermediate, protective, and production casing strings to aid in determining whether each string is cemented in accordance with this Section 2128(f)(3). If a casing string is thereby determined not be adequately cemented, the lessee shall recement the casing string as necessary to achieve annular fillup and isolation of zones. If following a primary cementing operation, it has been determined without the aid of a cement bond survey that remedial cementing is necessary, the running of such survey may be deferred until after recementing. The lessee shall verify the adequacy of the remedial cementing operations by running a cement bond survey or by other methods approved by the staff.

(4) A copy of each temperature and cement bond survey shall be filed immediately with the Staff.

(5) After cementing any of the above casing strings, drilling shall not be commenced until after a time lapse of:

(1) Blowout Preventers.

(2) Closing Unit System. The closing unit system shall incorporate the following general specifications:

(3) Kill and Choke Lines. The blowout preventer stack shall contain a drilling spool or equivalent connections in the blowout preventer body to provide for separate kill and choke lines. Each kill and choke line shall have a master valve located next to the stack followed by a control valve. Both valves shall be full-opening. The master valve shall not be used for normal opening or closing on flowing fluids.

On surface installations, the control valve on the choke line shall be remotely controllable. On subsea installations, the valves on both the kill and choke lines shall be hydraulically operated. One of the valves on each line shall be “fail-safe” in the closed position. The kill and choke lines on the subsea installation shall be connected through the surface choke manifold to permit pumping into the well through either line.

All connections for valves and fittings shall be flanged, welded or clamped. All lines, including flexible lines, valves and flow fittings shall have a working pressure rating at least equal to the rated working pressure of the blowout preventer stack in use.

On surface installations the kill line, valves and fittings shall have a minimum diameter of 2 inch nominal. The choke line, valves, and fittings shall have a minimum diameter of 3 inch nominal. On subsea installations both kill and choke line assemblies shall have a minimum diameter of 3 inch nominal.

(4) Choke Manifold. A choke manifold shall be installed on the drilling rig and be so located that it is readily accessible to drilling personnel.

The choke manifold design shall consider such factors as anticipated formation and surface pressures, method of well control to be employed, surrounding environment, corrosivity, volume, toxicity, and abrasiveness of fluids.

The portion of the manifold subject to well and/or pump pressure shall have a working pressure equal to the rated working pressure of the blowout preventer stack in use. All connections for valves and fittings shall be flanged, welded or clamped.

The choke manifold shall be equipped with a minimum of two adjustable chokes, one of which shall be remotely controlled. These chokes shall be isolated by at least one valve on each side to allow for repairs or replacement. All valves shall be full-opening. There shall be at least one bleed line with a minimum diameter of 3 inch nominal. The lines downstream of the chokes shall have a minimum diameter of 2 inch nominal. All lines shall be securely anchored and connected in such a manner as to permit flow to a mud/gas separator, vent lines, or to production facilities or emergency storage. Two vent lines shall be provided if necessary to accomplish the downwind diversion. The choke manifold shall be equipped with accurate pressure gauges so that all control operations can be properly monitored.

The choke manifold for a subsea installation shall be equipped with duplicate adjustable choke systems to permit control through either the choke or kill line in addition to a remotely controlled adjustable choke, and to provide tie-is for both drilling fluid and high pressure pump systems.

A choke control station shall be provided that includes all monitors necessary to furnish a complete overview of the well control situation.

(5) Fill-up Line. A fill-up line shall be installed on top of the blowout preventer stack on surface installations and on top of the marine riser on subsea installations.

(6) Diverter System. A diverter system shall be installed on the well prior to drilling below the conductor casing for the purpose of directing flowing formation fluids from the well safely away from the rig and personnel.

Low-pressure annular preventers, rotating heads or special diverters may be used for the diversion of well fluids. All such equipment shall be able to pack-off around the kelly, drill string and casing if run through the diverter. There shall be two diverter vent lines to permit diversion of well fluids while minimizing back pressure on the well. All vent lines shall be at least 6 inch nominal diameter unless otherwise justified by engineering analysis. The two vent lines shall be installed in a manner to accomplish downwind diversion. Valves on the vent lines shall be full-opening and so designed that the proper valve automatically opens when the diverter is activated or can be opened by remote control from the driller's control panel. A description and diagram of the diverter system and information justifying the sizing of vent lines shall be included in the blowout prevention program required in Section 2128(d)(1).

(7) Marine Riser. The marine riser system and its component parts that are employed in drilling operations from mobile drilling rigs shall conform to the design, operation, inspection and maintenance specifications set forth in Sections 6B and 11 of the “API Recommended Practices for Blowout Prevention Equipment Systems, API RP 53, First Edition, February 1976, reissued February 1978,” or subsequent revisions thereto that are approved by the Staff.

(8) Auxiliary Equipment.

(1) Pressure Testing of Blowout Prevention Equipment.

(2) Operational Testing of Blowout Prevention Equipment.

(3) Inspection and Maintenance of Blowout Prevention Equipment. All blowout prevention equipment systems shall be inspected and maintained in accordance with the manufacturer's recommended procedures. All systems shall be visually inspected at least once each day. Subsea blowout preventer and riser systems may be inspected by use of divers or television equipment. Any necessary equipment repair or replacement shall be accomplished without delay; however, full consideration shall be given to well safety before starting any work.

(1) The lessee shall provide on-site company supervision (company toolpusher) of drilling operations on a 24-hour basis. At least one member of the drilling crew or the toolpusher shall maintain rig-floor surveillance at all times, unless the well is secured with blowout preventers, bridge plugs, or cement plugs.

(2) Except as provided below in Section 2128(k)(3), the lessee and drilling contractor personnel engaged in drilling operations on State oil and gas leases located on State tide and submerged lands shall be trained and qualified in well-control equipment, operations and techniques in accordance with the provisions of the USGS Outer Continental Shelf Standard “Training and Qualifications of Personnel in Well-Control Equipment and Techniques for Drilling on Offshore Locations,” No. T 1 (GSS-OCS-T1), First Edition, December 1977, and subsequent revisions thereto that are approved by the Staff. Written certification shall be filed with the Staff on compliance with this provision before commencing drilling operations.

(3) Additional requirements to be included in subsection 3.6 of document GSS-OCS-T1 aforesaid are:

(1) When drilling operations are planned which will penetrate reservoirs known or expected to contain hydrogen sulfide (H₂S), or in those areas where the presence of H₂S is unknown, or upon encountering H₂S, the preventive measures and the operating practices set forth in U.S.G.S. Outer Continental Shelf Standard, “Safety Requirements for Drilling Operations in a Hydrogen Sulfide Environment,” No. 1 (GSS-OCS-1) Second Edition, June 1979, or subsequent revisions thereto that are approved by the Staff, shall be followed.

(2) The lessee shall submit to the Staff for its approval, a hydrogen sulfide contingency plan for each well proposal as required in Section 2128(d)(2).

(1) Mud Control

(2) Mud Quantities.

(3) Mud-Testing Equipment.

(1) The volume of mud required to fill the hole shall be carefully observed, and if at any time there is an indication of swabbing or influx of formation fluids, the necessary safety device(s) shall be installed on the drill pipe. The drill pipe shall be run to bottom and the mud properly conditioned to stabilize the well. The mud shall not be circulated and conditioned except on or near bottom, unless well conditions prevent the running of pipe to bottom.

(2) The lessee shall post at the driller's station, for each casing string, the maximum pressure that is allowed to build up against the blowout preventers before controlling the pressure by bleeding through the choke.

(3) The rate of pulling or running drill pipe shall be controlled to ensure that the hole is not being swabbed or that formations exposed to the well bore will not be broken down. Special precautions shall be observed to prevent swabbing when full-hole tools are employed.

(4) All formation fluid that is produced during drlllstem testing shall be directed to the producing or test facilities, and that remaining in the drill string after drillstem testing shall be reverse-circulated from the drill pipe. The mud shall be adequately conditioned prior to pulling the drillstem test tools.

(1) A well shall not be redrilled or deepened unless it is determined that the casing exposed in the well will provide adequate strength for the proposed drilling and for subsequent production operations. Where well conditions permit, a casing inspection survey, indicating remaining wall thickness and internal diameter, shall be run to determine the condition of the casing and whether or not it is of adequate strength.

(2) If it is not possible to run a casing inspection survey, the casing shall be pressure tested to at 70% of minimum internal yield pressure or 1.25 times the anticipated surface pressure that it might be subjected to either during the drilling operations or subsequent production operations (including injection), or to the amount stipulated in Section 2128(g), whichever is greater.

(3) If the casing inspection survey indicates that the casing strength is adequate, then the casing also shall be pressure tested as stipulated above in Section 2128(p)(2).

(4) In the event it is determined that the condition of the casing is inadequate, drilling shall not be initiated until corrective measures approved by the Staff are taken by the lessee. This shall include testing of the casing to the maximum pressure stipulated above in Section 2128(p)(2).

(5) A copy of the casing inspection survey shall be filed immediately with the Staff.

(6) Prior to redrilling or deepening a well the lessee shall demonstrate to the Staff that the casing is adequately cemented above the point of new drilling. In the event it is thereby determined that the casing is not adequately cemented, the lessee shall properly recement the casing. The lessee shall verify the adequacy of the remedial cementing operations by running a cement bond survey or by other methods approved by the Staff.

(7) Prior to redrilling a well, all oil, gas and water zones exposed in the well below the kickoff depth shall be properly abandoned in accordance with the plugging and abandonment regulations in Section 2128(q).

(8) If a well is to be redrilled or deepened to a zone(s) having a pressure significantly higher or lower than that of the shallower producing zone(s), which drilling might cause lost circulation and thereby endanger the well, the shallower producing zones shall be squeeze cemented or cased and cemented, prior to penetrating the lower zone(s).

(1) Permanent Abandonment.

(2) Temporary Abandonment

(1) The lessee shall keep a careful and accurate log, core record, and history of the drilling of each well.

(2) The lessee shall provide field copies of electric logs and other surveys as necessary for the Staff to expeditiously approve subsequent well operations.

(3) Within 60 days following the completion, abandonment, or the suspension of operations of any well, the lessee shall file with the Staff copies of all logs, including electric logs, surveys, drilling records, well histories, core records and related information as measured and recorded for the wells drilled by the lessee into the leased lands.