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(continued)
Note: Authority cited: Section 3609, Public Resources Code. Reference: Section 3609, Public Resources Code.
s 1721.7. Exceptions.
The supervisor may approve the drilling, redrilling, or production of a well which does not comply with the requirements of a well-spacing plan adopted pursuant to this article or with the set back requirement of section 1721.1 of these regulations if, in the opinion of the supervisor, such drilling, redrilling, or production is necessary to accommodate the use of onshore or offshore central drilling sites; to protect health, safety, welfare, or the environment; to prevent waste; or to otherwise increase the ultimate economic recovery of oil and gas.
Note: Authority cited: Section 3609, Public Resources Code. Reference: Section 3609, Public Resources Code.
s 1721.8. Pooling.
A well-spacing plan adopted by the supervisor shall require that all or certain parcels of land be included in a voluntary or mandatory pooling agreement if necessary to protect correlative rights. The supervisor may provide, in any order adopting a well-spacing plan, for a period not to exceed 60 days from the date of the order during which the affected parties shall be allowed to attempt to pool voluntarily their respective interests. Such period may be extended at the supervisor's discretion upon the written request of the affected parties. Any well-spacing order providing a period for an attempt at voluntary pooling is not a final order of the supervisor until either voluntary pooling has been accomplished and the supervisor notified of it or the supervisor has ordered mandatory pooling upon the failure of the affected parties to reach a pooling agreement voluntarily.
Note: Authority cited: Section 3609, Public Resources Code. Reference: Section 3609, Public Resources Code.
s 1721.9. Surveys.
For the purpose of enforcement of this article, the supervisor may order that a directional survey or drift-only survey of a well be made and filed with the supervisor before the well can be produced. If such a survey shows that the producing interval of a well is less than 75 feet from an outer boundary line or does not conform to the well-spacing plan, then written approval must be obtained from the supervisor before the well can be produced.
Note: Authority cited: Section 3609, Public Resources Code. Reference: Section 3609, Public Resources Code.
s 1722. General.
(a) All operations shall be conducted in accordance with good oilfield practice.
(b) The operator for a facility or group of related facilities shall develop an oil spill contingency plan. Condensate spill plans shall also be developed by the operator for those facilities within gas fields that produce condensate at an average rate of at least one barrel per day or where condensate storage volume exceeds 50 barrels. The plan(s) shall be filed within six months after initial production or acquisition of a facility. A copy of the plan shall be on file in the local office of the operator and subject to the inspection of the supervisor or a representative of the supervisor during regular business hours. If the operator does not have an office in the district, a copy of the plan shall be filed with the division district office. Plans prepared pursuant to Federal Environmental Protection Agency regulations (SPCC Plans) may fulfill the provisions of this subsection if such plans are determined to be adequate by the appropriate division district deputy. If, in the judgment of the supervisor, a plan becomes outdated, the supervisor may require that the plan be updated to ensure that it addresses and applies to current conditions and technology.
(c) For certain critical or high-pressure wells designated by the supervisor, a blowout prevention and control plan, including provisions for the duties, training, supervision, and schedules for testing equipment and performing personnel drills, shall be submitted by the operator to the appropriate division district deputy for approval.
(d) Notices of intention to drill, deepen, redrill, rework, or plug and abandon wells shall be completed on current division forms and submitted, in duplicate, to the appropriate division district office for approval. Such notices shall include all information required on the forms, and such other pertinent data as the supervisor may require. Notices of intention and approvals will be cancelled if the proposed operations have not commenced within one year of receipt of the notice. However, an approval for proposed operations may be extended for one year if the operator submits a supplementary notice prior to the expiration of the one-year period and can show good cause for such an extension. For the purpose of interpretation and enforcement of provisions of this section, operations, when commenced, must be completed in a timely and orderly manner.
(e) A copy of the operator's notice of intention and any subsequent written approval of proposed operations by the division shall be posted at the well site throughout the operations.
(f) Operators shall give the appropriate division district office sufficient advance notice of the time for inspections and tests requiring the presence of division personnel.
(g) Operations approved by the division shall not deviate from the approved program without prior division approval, except in an emergency.
(h) Oil spills shall be promptly reported to the Office of Emergency Services (OES) by calling the toll-free telephone number (800) 852-7550 and by contacting the agencies specified in the operator's oil spill contingency plan.
(i) Blowouts, fires, serious accidents, and significant gas or water leaks resulting from or associated with an oil or gas drilling or producing operation, or related facility, shall be promptly reported to the appropriate division district office.
(j) The use of radioactive materials in wells shall comply with the California Department of Health Services regulations in Title 17, Division 1, Chapter 5, Subchapter 4 of the California Code of Regulations. With the exception of radioactive tracers used in injection surveys, the loss of radioactive materials in a well shall be promptly reported to the Department of Health Services pursuant to Section 30350.3 of the above-referenced regulations and to the appropriate division district office.
(k) When sufficient geologic and engineering information is available from previous drilling, operators may make application to the supervisor for the establishment of field rules, or the supervisor may establish field rules or change established field rules for any oil or gas pool or zone in a field. Before establishing or changing a field rule, the supervisor shall distribute the proposed rule or change to affected persons and allow at least thirty (30) days for comments from the affected persons. The supervisor shall notify affected persons in writing of the establishment or change of field rules.
Note: Authority cited: Section 3013, Public Resources Code. Reference: Sections 3106, 3203, 3208, 3219, 3222, 3223, 3229 and 3230, Public Resources Code.
s 1722.1. Acquiring Right to Operate a Well.
Every person who acquires the right to operate any well, whether by purchase, transfer, assignment, conveyance, exchange, or otherwise, shall file an indemnity or cash bond, with his or her own name or company as principal, in the appropriate amount to cover obligations covered under the previous operator's bond.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Sections 3204, 3205, 3205.1 and 3205.5, Public Resources Code.
s 1722.1.1. Well and Operator Identification.
(a) Each well location shall have posted in a conspicuous place a clearly visible, legible, permanently affixed sign with the name of the operator, name or number of the lease, and number of the well. These signs shall be maintained on the premises from the time drilling operations cease until the well is plugged and abandoned.
(b) The appropriate division district deputy may approve existing identification methods if they substantially comply with the intent of this section.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Sections 3106, Public Resources Code.
s 1722.2. Casing Program.
Each well shall have casing designed to provide anchorage for blowout prevention equipment and to seal off fluids and segregate them for the protection of all oil, gas, and freshwater zones. All casing strings shall be designed to withstand anticipated collapse, burst, and tension forces with the appropriate design factor provided to obtain a safe operation.
Casing setting depths shall be based upon geological and engineering factors, including but not limited to the presence or absence of hydrocarbons, formation pressures, fracture gradients, lost circulation intervals, and the degree of formation compaction or consolidation. All depths refer to true vertical depth (TVD) below ground level.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Sections 3219 and 3220, Public Resources Code.
s 1722.3. Casing Requirements.
(a) Conductor casing. This casing shall be cemented at or driven to a maximum depth of 100 feet. Exceptions may be granted by the appropriate division district deputy if conditions require deeper casing depth.
(b) Surface casing. Surface casing shall be cemented into or through a competent bed and at a depth that will allow complete well shut-in without fracturing the formation immediately below the casing shoe. As a general guideline, the surface casing for prospect wells shall be cemented at a depth that is at least 10 percent of the proposed total depth, with a minimum of 200 feet and a maximum of 1,500 feet of casing. A second string of surface casing, cemented into or through a competent bed, shall be required in prospect wells if the first string has not been cemented in a competent bed or if unusual drilling hazards exist. In development wells, the surface casing requirement shall be determined on the basis of known field conditions. The appropriate division district deputy may vary these general surface casing requirements, including the adoption of a field rule, consistent with known geological conditions and engineering factors, to provide adequate protection for freshwater zones and blowout control.
(c) Intermediate casing. This casing may be required for protection of oil, gas, and freshwater zones, and to seal off anomalous pressure zones, lost circulation zones, and other drilling hazards.
(d) Production casing. This casing shall be cemented and, when required by the division, tested for fluid shutoff above the zone or zones to be produced. The test may be witnessed by a division inspector. When the production string does not extend to the surface, at least 100 feet of overlap between the production string and next larger casing string shall be required. This overlap shall be cemented and tested by a fluid-entry test to determine whether there is a competent seal between the two casing strings. A pressure test may be allowed only when such test is conducted pursuant to an established field rule. The test may be witnessed by a division inspector.
Note: Authority cited: Section 3013, Public Resources Code. Reference: Sections 3106 and 3220, Public Resources Code.
s 1722.4. Cementing Casing.
Surface casing shall be cemented with sufficient cement to fill the annular space from the shoe to the surface. Intermediate and production casings, if not cemented to the surface, shall be cemented with sufficient cement to fill the annular space to at least 500 feet above oil and gas zones, and anomalous pressure intervals. Sufficient cement shall also be used to fill the annular space to at least 100 feet above the base of the freshwater zone, either by lifting cement around the casing shoe or cementing through perforations or a cementing device placed at or below the base of the freshwater zone. All casing shall be cemented in a manner that ensures proper distribution and bonding of cement in the annular spaces. The appropriate division district deputy may require a cement bond log, temperature survey, or other survey to determine cement fill behind casing. If it is determined that the casing is not cemented adequately by the primary cementing operation, the operator shall recement in such a manner as to comply with the above requirements. If supported by known geologic conditions, an exception to the cement placement requirements of this section may be allowed by the appropriate division district deputy.
Note: Authority cited: Section 3013, Public Resources Code. Reference: Sections 3106, 3220 and 3222-3224, Public Resources Code.
s 1722.5. Blowout Prevention and Related Well Control Equipment.
Blowout prevention and related well control equipment shall be installed, tested, used, and maintained in a manner necessary to prevent an uncontrolled flow of fluid from a well. Division of Oil, Gas, and Geothermal Resources publication No. MO 7, "Blowout Prevention in California," shall be used by division personnel as a guide in establishing the blowout prevention equipment requirements specified in the division's approval of proposed operations.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Sections 3219 and 3220, Public Resources Code.
s 1722.6. Drilling Fluid Program.
The operational procedures and the properties, use, and testing of drilling fluid shall be such as are necessary to prevent the uncontrolled flow of fluids from any well. Drilling fluid additives in sufficient quantity to ensure well control shall be kept readily available for immediate use at all times. Fluid which does not exert more hydrostatic pressure than the known pressure of the formations exposed to the well bore shall not be used in a drilling operation without prior approval of the supervisor.
(a) Before removal of the drill pipe or tubing from the hole is begun, the drilling fluid shall be conditioned to provide adequate pressure overbalance to control any potential source of fluid entry. Proper overbalance shall be confirmed by checking the annulus to ensure that there is no fluid flow or loss when there is no fluid movement in the drill pipe or tubing. The drilling fluid weight, the weight and volume of any heavy slug or pill, and the fact that the annulus was checked for fluid movement shall be noted on the driller's log. During removal of the drill pipe or tubing from the hole, a hole-filling program shall be followed to maintain a satisfactory pressure overbalance condition.
(b) Tests of the drilling fluid to determine viscosity, water loss, weight, and gel strength shall be performed at least once daily while circulating, and the results of such tests shall be recorded on the driller's log. Equipment for measuring viscosity and fluid weight shall be maintained at the drill site. Exceptions to the test requirements may be granted for special cases, such as shallow development wells in low pressure fields, through the field rule process.
(c) Disposal of drilling fluids shall be done in accordance with Section 1775, Subchapter 2 of these regulations.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Sections 3219 and 3220, Public Resources Code.
s 1722.7. Directional Surveys.
The supervisor may order that a well be directionally surveyed.
Note: Authority cited: Section 3013, Public Resources Code. Reference: Sections 3106 and 3224, Public Resources Code.
s 1723. Plugging and Abandonment -General Requirements.
(a) Cement Plugs. In general, cement plugs will be placed across specified intervals to protect oil and gas zones, to prevent degradation of usable waters, to protect surface conditions, and for public health and safety purposes. Cement may be mixed with or replaced by other substances with adequate physical properties, which substances shall be approved by the supervisor. The application of these mixed materials and other substances to particular wells shall be at the discretion of the district deputy.
(b) Hole Fluid. Mud fluid having the proper weight and consistency to prevent movement of other fluids into the well bore shall be placed across all intervals not plugged with cement, and shall be surface poured into all open annuli.
(c) Plugging by Bailer. Placing of a cement plug by bailer shall not be permitted at a depth greater than 3,000 feet. Water is the only permissible hole fluid in which a cement plug shall be placed by bailer.
(d) Surface Pours. A surface cement-pour shall be permitted in an empty hole with a diameter of not less than 5 inches. Depth limitations shall be determined on an individual well basis by the district deputy.
(e) Blowout Prevention Equipment. Blowout prevention equipment may be required during plugging and abandonment operations. Any blowout prevention equipment and inspection requirements determined necessary by the district deputy shall appear on the approval to plug and abandon issued by the division.
(f) Junk in Hole. Diligent effort shall be made to recover junk when such junk may prevent proper plugging and abandonment either in open hole or inside casing. In the event that junk cannot be removed from the hole and fresh-saltwater contacts or oil or gas zones penetrated below cannot therefore be properly abandoned, cement shall be downsqueezed through or past the junk and a 100-foot cement plug shall be placed on top of the junk. If it is not possible to downsqueeze through the junk, a 100-foot cement plug shall be placed on top of the junk.
(g) Lost Radioactive Tool. In the event that a source containing radioactive material cannot be retrieved from the hole, a 100-foot standard color dyed (red iron oxide or equivalent red cement dye) cement plug shall be placed on top of the radioactive tool, and a whipstock or other approved deflection device shall be placed on top of the cement plug to prevent accidental or intentional mechanical disintegration of the radioactive source. In addition, the operator shall comply with the California Department of Health Services regulations in Section 30346 of Title 17, Division 1, Chapter 5, Subchapter 4, Group 3, Article 7, of the California Code of Regulations.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Sections 3219 and 3228, Public Resources Code.
s 1723.1. Plugging of Oil or Gas Zones.
(a) Plugging in an Open Hole. A cement plug shall be placed to extend from the total depth of the well or from at least 100 feet below the bottom of each oil or gas zone, to at least 100 feet above the top of each oil or gas zone.
(b) Plugging in a Cased Hole. All perforations shall be plugged with cement, and the plug shall extend at least 100 feet above the top of a landed liner, the uppermost perforations, the casing cementing point, the water shut-off holes, or the oil or gas zone, whichever is highest.
(c) Special Requirements. Special requirements may be made for particular types of hydrocarbon zones, such as:
(1) Fractured shale or schist;
(2) Massive sand intervals, particularly those with good vertical permeability;
(3) Any depleted productive interval more than 100 feet thick; or
(4) Multiple zones completed in a well.
As a minimum for an open-hole plugging and abandonment, the special requirement shall include a cement plug extending from at least 100 feet below the top of the oil or gas zone to at least 100 feet above the top of the zone.
As a minimum for a cased-hole plugging and abandonment, the special requirement shall include a cement plug extending from at least 25 feet below the top of the uppermost perforated interval to at least 100 feet above the top of the perforations, the top of the landed liner, the casing cementing point, the water shutoff holes, or the zone, whichever is highest.
(d) Bridge Plug. In a multiple zone completion, a single bridge plug above the lowermost zone may be allowed in lieu of cement through that zone if the zone is isolated from the upper zones by cement behind the casing. Subsequent bridge plugs are not allowed unless separated by cement plugs meeting the requirements of Section 1723.1(b). Temporary bridge plugs must be removed and replaced with cement plugs prior to shallower zone completions or well abandonment.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Section 3228, Public Resources Code.
s 1723.2. Plugging for Freshwater Protection.
(a) Plugging in Open Hole.
(1) A minimum 200-foot cement plug shall be placed across all fresh-saltwater interfaces.
(2) An interface plug may be placed wholly within a thick shale if such shale separates the freshwater sands from the brackish or saltwater sands.
(b) Plugging in a Cased Hole.
(1) If there is cement behind the casing across the fresh-saltwater interface, a 100-foot cement plug shall be placed inside the casing across the interface.
(2) If the top of the cement behind the casing is below the top of the highest saltwater sands, squeeze-cementing shall be required through perforations to protect the freshwater deposits. In addition, a 100-foot cement plug shall be placed inside the casing across the fresh-saltwater interface.
(3) Notwithstanding other provisions of this section, the district deputy may require or allow a cavity shot immediately below the base of the freshwater sands. In such cases, the hole shall be cleaned out to the estimated bottom of the cavity and a 100-foot cement plug shall be placed in the casing from the cleanout point.
(c) Special Plugging Requirements. Where geologic or groundwater conditions dictate, special plugging procedures may be specified to prevent contamination of usable waters by downward percolation of poor quality surface waters, separate water zones of varying quality, and isolate dry sands that are in hydraulic continuity with groundwater aquifers.
Note: Authority cited: Section 3013, Public Resources Code. Reference: Sections 3106 and 3228, Public Resources Code.
s 1723.3. Plugging at a Casing Shoe.
If the hole is open below a shoe, a cement plug shall extend from at least 50 feet below to at least 50 feet above the shoe. If the hole cannot be cleaned out to 50 feet below the shoe, a 100-foot cement plug shall be placed as deep as possible.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Sections 3106 and 3228, Public Resources Code.
s 1723.4. Plugging at the Casing Stub.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Sections 3106 and 3228, Public Resources Code.
s 1723.5. Surface Plugging.
The hole and all annuli shall be plugged at the surface with at least a 25-foot cement plug. The district deputy may require that inner strings of uncemented casing be removed to at least the base of the surface plug prior to placement of the plug.
All well casing shall be cut off at least 5 feet but no more than 10 feet below the surface of the ground. The district deputy may approve a different cut-off depth, as conditions warrant, including but not limited to excavation or grading operations for construction purposes. As defined in Section 1760(j), a steel plate at least as thick as the outer well casing shall be welded around the circumference of the casing at the top of the casing, after division approval of the surface plug. The steel plate shall show the well's identification, indicated by the last five digits of the API well number.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Section 3106, Public Resources Code.
s 1723.6. Recovery of Casing.
(a) Approval to recover all casing possible will be given in the plugging and abandonment of wells where subsurface plugging can be done to the satisfaction of the district deputy.
(b) The hole shall be full of fluid prior to the detonation of any explosives in the hole. Such explosives shall be utilized only by a licensed handler with the required permits.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Sections 3106 and 3228, Public Resources Code.
s 1723.7. Inspection of Plugging and Abandonment Operations.
Plugging and abandonment operations that require witnessing by the division shall be witnessed and approved by a division employee. When discretion is indicated by these regulations, the district deputy shall determine which operations are to be witnessed.
(a) Blowout prevention equipment -may inspect and witness testing of equipment and installation.
(b) Oil and gas zone plug -may witness placing and shall witness location and hardness.
(c) Mudding of hole -may witness mudding operations and determine that specified physical characteristics of mud fluid are met.
(d) Freshwater protection:
(1) Plug in open hole -may witness placing and shall witness location and hardness. Plug in cased hole -shall witness placing or location and hardness.
(2) Cementing through perforations -may witness perforating and shall witness cementing operation.
(3) Cavity shot -may witness shooting and shall witness placing or location and hardness of required plug.
(e) Casing shoe plug -shall witness placing or location and hardness.
(f) Casing stub plug -may witness placing or location and hardness.
(g) Surface plug -may witness emplacement and shall witness or verify location.
(h) Environmental inspection (after completion of plugging operations) -shall determine that division environmental regulations (California Code of Regulations, Title 14, Subchapter 2) have been adhered to.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Section 3228, Public Resources Code.
s 1723.8. Special Requirements.
The supervisor, in special cases, may set forth other plugging and abandonment requirements or may establish field rules for the plugging and abandonment of wells. Such cases include, but are not limited to:
(a) The plugging of a high-pressure saltwater zone.
(b) Perforating and squeeze-cementing previously uncemented casing within and above a hydrocarbon zone.
(c) The plugging of particular zones or specifying cleanout intervals within a wellbore.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Section 3106, Public Resources Code.
s 1723.9. Testing of Idle Wells.
Any well that has not produced oil or natural gas or been used for fluid injection for a continuous six-month period during any consecutive five-year period, prior to or after the adoption of this regulation, must have either the fluid level determined using acoustical, mechanical, or other reliable methods, or other diagnostic tests as approved by the supervisor. Additional well tests or remedial operations may be required if the fluid level is located above or adjacent to freshwater or potential drinking water zones, or as specified by the appropriate division district deputy. Subsequent testing periods shall be based on the fluid level in the well, the well's location in relation to freshwater zones, mitigation measures taken by the operator to prevent fluid migration, or other factors determined by the appropriate division district deputy, upon a showing of good cause. The appropriate district office shall be notified before tests are made, as a Division inspector may witness the operations.
Note: Authority cited: Section 3013, Public Resources Code. Reference: Section 3106, Public Resources Code.
s 1724. Required Well Records.
The operator of any well drilled, redrilled, deepened, or reworked shall keep, or cause to be kept, an accurate record of each operation on each well including, but not limited to, the following, when applicable:
(a) Log and history showing chronologically the following data:
(1) Character and depth of all formations, water-bearing strata, oil- and gas-bearing zones, lost circulation zones, and abnormal pressure zones encountered.
(2) Casing size, weight, grade, type, condition (new or used), top, bottom, and perforations; and any equipment attached to the casing.
(3) Tubing size and depth, type and location of packers, safety devices, and other tubing equipment.
(4) Casing pressure tests and pressure tests of the casing-tubing annulus, including date, duration, pressure, and percent bleed-off.
(5) Hole sizes.
(6) Cementing and plugging operations, including date, depth, slurry volume and composition, fluid displacement, pressures, calculated or actual fill, and downhole equipment.
(7) Drill-stem, leak-off, or other formation tests, including date, duration, depth, pressures, and recovery (volume and description).
(8) BOPE installation, inspections, and pressure tests.
(9) Water shutoff and lap tests of casing, including date, duration, depth, and results.
(10) Sidetracked casing, tools or other material, collapsed or bad casing, holes in casing, and stuck drill pipe, tubing, or other junk in casing or open hole.
(11) Depth and type of all electrical, physical, or chemical logs, tests, or surveys made.
(12) Production or injection method and equipment.
(b) Core record showing the depth, character, and fluid content, so far as determined, of all cores, including sidewall samples.
(c) Such other information as the supervisor may require for the performance of his or her statutory duties.
Note: Authority cited: Sections 3013 and 3107, Public Resources Code. Reference: Sections 3106, 3107, 3203, 3210 and 3214, Public Resources Code.
s 1724.1. Records to Be Filed with the Division.
Two true and reproducible copies of the well summary, core record, and history, and all electrical, physical and chemical logs, tests and surveys run, including mud logs shall be filed with the division within 60 days after the completion, plugging and abandonment, or suspension of operations of a well. Dipmeter surveys shall be submitted in a form indicating the computed direction and amount of dip.
Note: Authority cited: Sections 3013, 3106 and 3107, Public Resources Code. Reference: Sections 3107, 3215 and 3216, Public Resources Code.
s 1724.2. Maintenance of Production Facilities, Safety Systems, and Equipment.
All surface equipment, including but not limited to production safety systems, wellheads, separators, pumps, manifolds, valves, and pipelines, used for the production of oil, gas, and waste water shall be maintained in good condition at all times to safeguard life, health, property, and natural resources. Safety systems and equipment associated with consolidated production facilities in urban areas may be inspected and tested at six-month intervals.
Note: Authority cited: Section 3013, Public Resources Code. Reference: Sections 3106, 3219, 3220 and 3222-3224, Public Resources Code.
s 1724.3. Well Safety Devices for Critical Wells.
Certain wells designated by the supervisor, that meet the definition of "critical" pursuant to Section 1720(a) and have sufficient pressure to allow fluid-flow to the surface, shall have safety devices as specified by the supervisor, installed and maintained in operating condition. A description of such safety devices follows:
(a) Surface safety devices.
(1) Fail-close, well shut-in or shut-down devices. Wellhead assemblies shall be equipped with an automatic fail-close valve.
(2) High-low pressure sensors in all flowlines, set to actuate shut in or shut down of the well(s) in the event of abnormal pressures in the flowlines.
(3) Check valves in all headers, except for gas storage wells, to prevent backflow in the event of flowline failure. All flowlines and valves shall be capable of withstanding shut-in wellhead pressure, unless protected by a relief valve with connections to bypass the header.
(4) Fire detection devices, such as fusible plugs, at strategic points in pneumatic, hydraulic, and other shut-in control lines in fire hazard areas.
(5) Remote, manually operated, quick operating shut-in controls at strategic points.
(b) Subsurface safety devices.
(1) A surface-controlled, subsurface tubing safety valve installed at a depth of 50 feet or more below the ground level. For shut-in wells capable of flowing, a tubing plug may be installed in lieu of a subsurface tubing safety valve. Subsurface safety devices shall be installed, adjusted, and maintained to ensure reliable operation. If for any reason a subsurface safety device is removed from a well, a replacement subsurface safety device or tubing plug shall be promptly installed. Any well in which a subsurface safety device or tubing plug is installed shall have the tubing-casing annulus sealed at or below the valve- or plug-setting depth. A bypass-type packer that will seal the annulus on manual or automatic operation of the tubing subsurface safety device will meet this requirement.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Sections 3106 and 3219, Public Resources Code.
s 1724.4. Testing and Inspection of Safety Devices.
(a) All installed well safety devices, required pursuant to Section 1724.3 of this article, shall be tested at least every six (6) months, as follows:
(1) Flow line pressure sensors shall be tested for proper pressure settings.
(2) Automatic wellhead safety valves shall be tested for reliable operation and holding pressure.
(3) Subsurface safety devices shall be tested for reliable operation.
(4) Tubing plugs or packers shall be tested for holding pressure .
(b) The appropriate division district office shall be notified before such tests are made, as these tests may be witnessed by a division inspector. Test failures not immediately repaired or corrected and not witnessed by a division inspector shall be reported to the division within 24 hours.
(c) The supervisor may establish a special testing schedule for safety devices other than that specified in this section, based upon equipment performance or special conditions.
(d) The operator shall maintain records, available to division personnel during business hours, showing the present status and history of each well safety device installed, including dates, details and results of inspections, tests, repairs, reinstallations, and replacements.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Sections 3106 and 3219, Public Resources Code.
s 1724.5. Surface Disposal of Waste Water.
Note: Authority cited: Sections 3106 and 3107, Public Resources Code. Reference: Sections 3106, 3107, 3203, 3210-3215, 3219, 3220 and 3222-3224, Public Resources Code.
s 1724.6. Approval of Underground Injection and Disposal Projects.
Approval must be obtained from this division before any subsurface injection or disposal project can begin. This includes all EPA Class II wells and air- and gas-injection wells. The operator requesting approval for such a project must provide the appropriate division district deputy with any data that, in the judgment of the supervisor, are pertinent and necessary for the proper evaluation of the proposed project.
Note: Authority cited: Section 3106, Public Resources Code. Reference: Section 3106, Public Resources Code.
s 1724.7. Project Data Requirements.
(Note: See Section 1724.8 for special requirements for cyclic steam projects, and Section 1724.9 or supplementary requirements for gas storage projects.)
The data required to be filed with the district deputy include the following, where applicable:
(a) An engineering study, including but not limited to:
(1) Statement of primary purpose of the project.
(2) Reservoir characteristics of each injection zone, such as porosity, permeability, average thickness, areal extent, fracture gradient, original and present temperature and pressure, and original and residual oil, gas, and water saturations.
(3) Reservoir fluid data for each injection zone, such as oil gravity and viscosity, water quality, and specific gravity of gas.
(4) Casing diagrams, including cement plugs, and actual or calculated cement fill behind casing, of all idle, plugged and abandoned, or deeper-zone producing wells within the area affected by the project, and evidence that plugged and abandoned wells in the area will not have an adverse effect on the project or cause damage to life, health, property, or natural resources.
(5) The planned well-drilling and plugging and abandonment program to complete the project, including a flood-pattern map showing all injection, production, and plugged and abandoned wells, and unit boundaries.
(b) A geologic study, including but not limited to:
(1) Structural contour map drawn on a geologic marker at or near the top of each injection zone in the project area.
(2) Isopachous map of each injection zone or subzone in the project area.
(3) At least one geologic cross section through at least one injection well in the project area.
(4) Representative electric log to a depth below the deepest producing zone (if not already shown on the cross section), identifying all geologic units, formations, freshwater aquifers, and oil or gas zones.
(c) An injection plan, including but not limited to:
(1) A map showing injection facilities.
(2) Maximum anticipated surface injection pressure (pump pressure) and daily rate of injection, by well.
(3) Monitoring system or method to be utilized to ensure that no damage is occurring and that the injection fluid is confined to the intended zone or zones of injection.
(4) Method of injection.
(5) List of proposed cathodic protection measures for plant, lines, and wells, if such measures are warranted.
(6) Treatment of water to be injected.
(7) Source and analysis of the injection liquid.
(8) Location and depth of each water-source well that will be used in conjunction with the project.
(d) Copies of letters of notification sent to offset operators.
(e) Other data as required for large, unusual, or hazardous projects, for unusual or complex structures, or for critical wells. Examples of such data are: isogor maps, water-oil ratio maps, isobar maps, equipment diagrams, and safety programs.
(f) All maps, diagrams and exhibits required in Section 1724.7(a) through (e) shall be clearly labeled as to scale and purpose and shall clearly identify wells, boundaries, zones, contacts, and other relevant data.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Section 3106, Public Resources Code.
s 1724.8. Data Required for Cyclic Steam Injection Project Approval.
The data required by the division prior to approval of a cyclic steam (steam soak) project include, but are not limited to, the following:
(a) A letter from the operator notifying the division of the intention to conduct cyclic steam injection operations on a specific lease, in a specific reservoir, or in a particular well.
(b) If cyclic steam injection is to be in wells adjacent to a lease boundary, a copy of a letter notifying each offset operator of the proposed project.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Section 3106, Public Resources Code.
s 1724.9. Gas Storage Projects.
The data required by the division prior to approval of a gas storage project include all applicable items listed in Section 1724.7(a) through (e), and the following, where applicable:
(a) Characteristics of the cap rock, such as areal extent, average thickness, and threshold pressure.
(b) Oil and gas reserves of storage zones prior to start of injection, including calculations.
(c) List of proposed surface and subsurface safety devices, tests, and precautions to be taken to ensure safety of the project.
(d) Proposed waste water disposal method.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Section 3106, Public Resources Code.
s 1724.10. Filing, Notification, Operating, and Testing Requirements for Underground Injection Projects.
(a) The appropriate division district deputy shall be notified of any anticipated changes in a project resulting in alteration of conditions originally approved, such as: increase in size, change of injection interval, or increase in injection pressure. Such changes shall not be carried out without division approval.
(b) Notices of intention to drill, redrill, deepen, or rework, on current division forms, shall be completed and submitted to the division for approval whenever a new well is to be drilled for use as an injection well and whenever an existing well is converted to an injection well, even if no work is required on the well.
(c) An injection report on a current division form or in a computerized format acceptable to the division shall be filed with the division on or before the 30th day of each month, for the preceding month.
(d) A chemical analysis of the liquid being injected shall be made and filed with the division whenever the source of injection liquid is changed, or as requested by the supervisor.
(e) An accurate, operating pressure gauge or pressure recording device shall be available at all times, and all injection wells shall be equipped for installation and operation of such gauge or device. A gauge or device used for injection-pressure testing, which is permanently affixed to the well or any part of the injection system, shall be calibrated at least every six months. Portable gauges shall be calibrated at least every two months. Evidence of such calibration shall be available to the division upon request.
(f) All injection piping, valves, and facilities shall meet or exceed design standards for the maximum anticipated injection pressure, and shall be maintained in a safe and leak-free condition.
(g) All injection wells, except steam, air, and pipeline-quality gas injection wells, shall be equipped with tubing and packer set immediately above the approved zone of injection within one year after the effective date of this act. New or recompleted injection wells shall be equipped with tubing and packer upon completion or recompletion. Exceptions may be made when there is:
(1) No evidence of freshwater-bearing strata.
(2) More than one string of casing cemented below the base of fresh water.
(3) Other justification, as determined by the district deputy, based on documented evidence that freshwater and oil zones can be protected without the use of tubing and packer.
(h) Data shall be maintained to show performance of the project and to establish that no damage to life, health, property, or natural resources is occurring by reason of the project. Injection shall be stopped if there is evidence of such damage, or loss of hydrocarbons, or upon written notice from the division. Project data shall be available for periodic inspection by division personnel.
(i) To determine the maximum allowable surface injection pressure, a step-rate test shall be conducted prior to sustained liquid injection. Test pressure shall be from hydrostatic to the pressure required to fracture the injection zone or the proposed injection pressure, whichever occurs first. Maximum allowable surface injection pressure shall be less than the fracture pressure. The appropriate district office shall be notified prior to conducting the test so that it may be witnessed by a division inspector. The district deputy may waive or modify the requirement for a step-rate test if he or she determines that surface injection pressure for a particular well will be maintained considerably below the estimated pressure required to fracture the zone of injection.
(j) A mechanical integrity test (MIT) must be performed on all injection wells to ensure the injected fluid is confined to the approved zone or zones. An MIT shall consist of a two-part demonstration as provided in subsections (j)(1) and (2).
(1) Prior to commencing injection operations, each injection well must pass a pressure test of the casing-tubing annulus to determine the absence of leaks. Thereafter, the annulus of each well must be tested at least once every five years; prior to recommencing injection operations following the repositioning or replacement of downhole equipment; or whenever requested by the appropriate division district deputy.
(2) When required by subsection (j) above, injection wells shall pass a second demonstration of mechanical integrity. The second test of a two-part MIT shall demonstrate that there is no fluid migration behind the casing, tubing, or packer.
(3) The second part of the MIT must be performed within three (3) months after injection has commenced. Thereafter, water-disposal wells shall be tested at least once each year; waterflood wells shall be tested at least once every two years; and steamflood wells shall be tested at least once every five years. Such testing for mechanical integrity shall also be performed following any significant anomalous rate or pressure change, or whenever requested by the appropriate division district deputy. The MIT schedule may be modified by the district deputy if supported by evidence documenting good cause.
(4) The appropriate district office shall be notified before such tests/surveys are made, as a division inspector may witness the operations. Copies of surveys and test results shall be submitted to the division within 60 days.
(k) Additional requirements or modifications of the above requirements may be necessary to fit specific circumstances and types of projects. Examples of such additional requirements or modifications are:
(1) Injectivity tests.
(2) Graphs of time vs. oil, water, and gas production rates, maintained for each pool in the project and available for periodic inspection by division personnel.
(3) Graphs of time vs. tubing pressure, casing pressure, and injection rate maintained for each injection well and available for periodic inspection by division personnel.
(4) List of all observation wells used to monitor the project, indicating what parameter each well is monitoring (i.e., pressure, temperature, etc.), submitted to the division annually.
(5) List of all injection-withdrawal wells in a gas storage project, showing casing-integrity test methods and dates, the types of safety valves used, submitted to the division annually.
(6) Isobaric maps of the injection zone, submitted to the division annually.
(7) Notification of any change in waste disposal methods.
Note: Authority cited: Section 3013, Public Resources Code. Reference: Section 3106, Public Resources Code.
s 1740. Purpose.
It is the purpose of this subchapter to set forth the rules and regulations governing the drilling, redrilling, production, maintenance, and plugging and abandonment of offshore oil and gas wells in accordance with the provisions of Division 3 of the Public Resources Code.
Note: Authority cited: Sections 3000-3013 and 3106, Public Resources Code. Reference: Sections 3203-3220 and 3227-3237, Public Resources Code.
s 1740.1. Policy.
Section 3106 of Division 3 of the Public Resources Code will be administered with the objective of furthering declared legislative policy; namely, that the supervisor shall supervise drilling, operation, maintenance, and plugging and abandonment of wells to prevent as far as possible, damage to life, health, property, and natural resources, damage to underground oil and gas deposits from infiltrating water and other causes, loss of oil, gas, or reservoir energy and damage to underground and surface waters suitable for irrigation or domestic purposes by the infiltration of, or the addition of detrimental substances by reason of the drilling, operation, maintenance, or plugging and abandonment of wells.
s 1740.2. Scope of Regulations.
They shall apply to any and all oil or gas well operations conducted from locations within the offshore territorial boundaries and inland bays of the State of California, and where in conflict, the existing regulations shall supersede any and all previous rules, regulations, and requirements pertaining to the operations previously stated.
s 1740.3. Revision of Regulations.
The supervisor at appropriate intervals, or as the need arises, may review and issue special regulations or change present regulations, and such special regulations or changes shall prevail against general regulations if in conflict therewith. Public hearings on such special issues or changes will be held if required.
s 1740.4. Incorporation by Reference.
Any documents or part therein incorporated by reference herein are a part of this regulation as though set out in full.
s 1740.5. Approval.
Written approval of the supervisor is required prior to commencing drilling, reworking, injection, plugging, or abandonment operations. Temporary approval to commence such operations, however, may be granted by the supervisor or his or her representative when such operations are necessary to avert a threat to life, health, property, or natural resources, or when approved operations are in progress and newly discovered well condition are such that immediate corrective or abandonment operations are desirable. Such temporary approval shall be granted only after the operator has provided the division with all information pertaining to the condition of the well, including but not limited to, geological, mechanical, and the results of tests and surveys. Notwithstanding any such temporary approval, the operator shall immediately file a written notice of intention to carry out a program temporarily approved. (continued)