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State
California Regulations
DIVISION 9. DEPARTMENT OF CONSERVATION -DIVISION OF OIL AND GAS (TITLE 14)

database is current through 09/29/06, Register 2006, No. 39

s 14-1724.6. 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 14-1724.7. 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 14-1724.8. 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 14-1724.9. 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 14-1724.10. 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 14-1743. General Requirements.
(a) It is understood that this division's approval of operations is contingent upon the continual fulfillment of all marine and pollution control requirements established by the U. S. Coast Guard and the State of California.
(b) All operations are to be conducted in a proper and workmanlike manner in accordance with good oil field practice.
(c) All installations shall comply with applicable provisions of Safety Orders of the State Division of Industrial Safety, including the Petroleum Safety Orders, the General Industry Safety Orders and the Unfired Pressure Vessel Safety Orders.
(d) An approved oil spill contingency plan that includes provisions for rapid deployment of containment and recovery equipment shall be in effect, and a copy of the plan shall be on file with this division prior to commencing operations.
(e) An approved plan for blowout prevention and control, "kick control plan," including provisions for duties, training, supervision, and schedules for testing equipment and drills, shall be on file with the division prior to commencing operations.
(f) Tubing, casing, or annulus open to an oil or gas zone shall be sealed off or equipped with a device to shut it in at the surface.
(g) A copy of the operator's proposals on division forms and subsequent approval of proposed operations by the division shall be available at the wellsite throughout such operations.
(h) Operators shall give adequate prior notice to the division's office of the district in which a well is located, of the time for inspections, and tests required by the division.
(i) Operations shall not deviate from the approved basic program without prior approval of the division. Additional requirements may be made at that time.
(j) Oil spills or slicks shall be reported to the agencies as specified in the California Oil Spill Disaster Contingency Plan and in the National Oil Hazardous Substances Pollution Contingency Plan.
(k) Blowouts, fires, hazardous gas leaks, disasters, major accidents, or similar incidents on or emanating from an oil or gas drilling, producing, or treating facility shall be reported to the division immediately.


Note: Authority cited: Section 3106, Public Resources Code. Reference: Section 3203, Public Resources Code.




s 14-1760. Definitions.
The following definitions are applicable to this subchapter:
(a) "Catch basin" means a dry sump which is constructed to protect against unplanned overflow conditions.
(b) "Designated waterways" means any named perennial or ephemeral waterways or any perennial waterways shown as solid blue lines on United States Geological Survey topographic maps and any ephemeral waterways that the supervisor determines to have a direct impact on perennial waterways.
(c) "Evaporation sump" means a sump containing fresh or saline water which can properly be used to store such waters for evaporation.
(d) "Environmentally sensitive pipeline" means any of the following:
(1) A pipeline located within 300 feet of any public recreational area, or a building intended for human occupancy that is not necessary to the operation of the production operation, such as residences, schools, hospitals, and businesses.
(2) A pipeline located within 200 feet of any officially recognized wildlife preserve or environmentally sensitive habitat that is designated on a United States Geological Survey topographic map, designated waterways, or other surface waters such as lakes, reservoirs, rivers, canals, creeks, or other water bodies that contain water throughout the year.
(3) A pipeline located within the coastal zone as defined in Section 30103(b) of the Public Resources Code.
(4) Any pipeline for which the supervisor determines there may be a significant potential threat to life, health, property, or natural resources in the event of a leak, or that has a history of chronic leaks.
(e) "Field" means the general surface area that is underlain or reasonably appears to be underlain by an underground accumulation of crude oil or natural gas, or both. The surface area is delineated by the administrative boundaries shown on maps maintained by the Supervisor.
(f) "Gathering line" means a pipeline (independent of size) that transports liquid hydrocarbons between any of the following: multiple wells, a testing facility, a treating and production facility, a storage facility, or a custody transfer facility.
(g) "Operations sump" means a sump used in conjunction with a drilling or workover rig during the period of time a well is being drilled or reworked.
(h) "Pipeline" means a tube, usually cylindrical, with a cross sectional area greater than 0.8 square inches (1 inch nominal diameter), through which crude oil, liquid hydrocarbons, combustible gases, and/or produced water flows from one point to another within the administrative boundaries of an oil or gas field. Pipelines under the State Fire Marshal jurisdiction, as specified by the Elder Pipeline Safety Act of 1981 (commencing with s 51010 of the Government Code, and the regulations promulgated thereunder) are exempt from this definition.
(i) "Sump" means an open pit or excavation serving as a receptacle for collecting and/or storing fluids such as mud, hydrocarbons, or waste waters attendant to oil or gas field drilling or producing operations.
(j) "Urban area" means a cohesive area of at least twenty-five business establishments, residences, or combination thereof, the perimeter of which is 300 feet beyond the outer limits of the outermost structures.
(k) "Urban pipeline" means that portion of any pipeline within an urban area as defined in this section.
(l) "Waste water" means produced water that after being separated from the produced oil may be of such quality that discharge requirements need to be set by a California Regional Water Quality Control Board.


Note: Authority cited: Sections 3013 and 3782, Public Resources Code. Reference: Sections 3106 and 3782, Public Resources Code.




s 14-1770. Oilfield Sumps.
(a) Location. Sumps for the collection of waste water or oil shall not be permitted in natural drainage channels. Contingency catch basins may be permitted, but they shall be evacuated and cleaned after any spill. Unlined evaporation sumps, if they contain harmful waters, shall not be located where they may be in communication with freshwater-bearing aquifers.
(b) Construction. Sumps shall be designed, constructed, and maintained so as to not be a hazard to people, livestock, or wildlife including birdlife.
(1) To protect people, sumps in urban areas shall be enclosed in accordance with Section 1778(a) or (e) and (c).

(2) In non-urban areas, to protect people and livestock and to deter wildlife, an enclosure shall be conrtructed around sumps in accordance with Section 1778 (b) or (e).
(3) Any sump, except an operations sump, which contains oil or a mixture of oil and water shall be covered with screening to restain entry of wildlife in accordance with Section 1778(d).
(4) A sump need not be individually fenced if the property or the production faclilities of which the sump is a part is enclosed by proper perimeter fencing.


Note: Authority cited: Sections 3013, 3106 and 3782, Public Resources Code. Reference: Sections 3106 and 3783, Public Resources Code.




s 14-1771. Channels.
Open unlined channels and ditches shall not be used to transport waste water which is harmful to underlying freshwater deposits. Oil or water containing oil shall not be transported in open unlined channels or ditches unless provisions are made so that they are not a hazard as determined by the supervisor.


Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Section 3106, Public Resources Code.




s 14-1773. Tank Settings.
Tank settings in areas where damage to life, health, property, or natural resources might occur as a result of leakage, shall have a method for control of the spilled fluid and detection of tank-bottom leaks. This may be accomplished by employing a combination of the following containment and detection methods:
(a) For containment:
(1) A drainage system for safe fluid containment.
(2) Diversion walls to direct fluids to a preferred collection point.

(3) Dikes or fire walls capable of containing the volume of the largest tank. Tank settings in urban areas shall have dikes.
(b) For leak detection:
(1) A tank installation that allows the exterior surface, including the bottom of the tank and connection piping, to be monitored by direct viewing.
(2) A tank foundation of concrete or gravel.
(3) A tank bottom leak detection system.


Note: Authority cited: Section 3013, Public Resources Code. Reference: Section 3106, Public Resources Code.




s 14-1774. Oilfield Facilities and Equipment Maintenance.
(a) Well cellars shall be covered and kept drained. Grating or flooring shall be installed and maintained in good condition so as to exclude people and animals. Cellars should be protected from as much runoff water as practical.
(b) Production facilities, including but not limited to, tanks, pipelines, flowlines, wellheads, and separators shall be maintained in a manner to prevent leakage.
(c) Other production facilities and equipment, including but not limited to pumping units, compressors, tanks, and skimming devices, shall be installed and maintained properly for the protection of people, wildlife, and domestic animals.
(d) All equipment and facilities in urban areas shall be enclosed individually or with perimeter fencing in accordance with the provisions of Section 1778 (a) and (e) where it is necessary to protect life and property. Enclosures in nonurban areas shall be constructed in accordance with Section 1778 (a) or (b) where necessary to protect life and property.
(e) Pipelines shall be designed, constructed, tested, operated, and maintained in accordance with good oil field practice and applicable standards, such as the American Petroleum Institute (API) (API Rec. Prac. 1110, 3rd Ed., Dec. 1991, and API Spec. effective 1990) or American Society for Testing and Materials (ASTM) (ASTM Designation Stand. Spec., 1991), Code of Federal Regulations 49, Part 192, or other applicable standards for the transportation of oil, gas, produced water, and other fluids.
Good oilfield practice includes, but is not limited to:
(1) Utilization of preventative methods such as cathodic protection and corrosion inhibitors, as appropriate, to minimize external and internal corrosion.

(2) Employment, where practical, of equipment such as low-pressure alarms and safety shut-down devices to minimize spill volume in the event of a leak.
(3) Evaluating the applicability of locating any new pipelines or parts of a pipeline system that are being relocated or replaced above ground.
The use of pipe clamps or screw-in plugs are not considered good oilfield practice for permanent repair of pipeline leaks.
(f) All aboveground pipelines shall be inspected visually for leaks and corrosion at least once a year.
(g) The supervisor may order such tests or inspections deemed necessary to establish the reliability of any pipeline system. Repair, replacement, or cathodic protection may be required.
(h) Maps of all pipelines should be maintained and updated whenever pipelines are installed or removed.
(i) On or before January 1, 1999, all operators of environmentally sensitive pipelines shall prepare a pipeline management plan for all environmentally sensitive pipelines. The plan shall be submitted to the supervisor for approval and review every five years after the approval date. These plans shall be updated whenever pipelines are installed, altered, the plan becomes obsolete, or at the request of the supervisor. Pipelines that have been abandoned to the standards specified in Section 1776(f) are exempt from this requirement.
The pipeline management plan shall include the following:
(1) A map showing all active and inactive environmentally sensitive pipelines, including line sizes and any buried line segments. If the location of a buried pipeline is unknown, the most probable location shall be shown.
(2) A listing of available information on each pipeline including, but not limited to: pipeline type, grade, age of pipeline, design and operating pressures, and any available leak, repair, inspection and testing history.
(3) A listing of any safety shutdown devices, corrosion prevention, or corrosion monitoring techniques utilized.
(4) A description of the testing method and schedule for any pipelines indicated in (j) or (k).
(j) After a pipeline management plan is approved, a mechanical integrity test shall be performed on all active environmentally sensitive pipelines that are gathering lines, and all urban pipelines over 4 inches in diameter, every two years. Pipelines less than ten (10) years old are exempt from the two year testing requirement. These tests shall be performed to ensure the pipeline does not present a threat to public health, safety, or the environment by using at least one of the following methods:
(1) Nondestructive testing using ultrasonic or other techniques approved by the supervisor, to determine wall thickness.
(2) Hydrostatic testing using the guidelines recommended in Publication API RP 1110 (3d Ed., Dec. 1991), Testing of Liquid Petroleum Pipelines, or the method approved by the State Fire Marshal, Pipeline Safety and Enforcement Division.
(3) Internal inspection devices such as a smart pig, as approved by the supervisor.
(4) Or any other method of ensuring the integrity of a pipeline that is approved by the supervisor.
Copies of test results shall be maintained in a local office of the operator for six years and made available to the Division, upon request. The operator shall repair and retest or remove from service any pipeline that fails the mechanical integrity test. The Division shall be promptly notified in writing by the operator of any pipeline taken out of service due to a test failure.
(k) A county board of supervisors, a city council, or another state agency may petition the supervisor to include other pipelines within their jurisdiction as environmentally sensitive. The request must be in writing and based on findings of a competent, professional evaluation that shows there is a probability of significant public danger or environmental damage if a leak were to occur.
1. Within 30 days of receipt of a petition, the supervisor shall notify any affected operator.
2. Within 60 days of notification to the operators, the supervisor shall schedule a hearing with the petitioner and operators to allow all parties to be heard.

3. Within 30 days of the conclusion of the hearing, the supervisor shall make a determination as to whether the areas or pipelines should be considered environmentally sensitive.
(l) Additions and Exemptions
1. The Supervisor may establish additional requirements to Section 1774(i) and (j) to ensure life, health, property, and natural resources are protected adequately.
2. The Supervisor may establish exemptions to the requirements in Section 1774(i) and (j) that will not result in a significant threat to life, health, property, or natural resources.
3. An operator may petition the supervisor to establish an exemption or addition for any environmentally sensitive pipeline. An operator's petition to exempt a requirement must clearly establish that eliminating the requirement will not impose a significant potential threat to life, health, property, or natural resources.


Note: Authority cited: Section 3013, Public Resources Code. Reference: Section 3106, Public Resources Code.




s 14-1775. Oilfield Wastes and Refuse.
(a) Oilfield wastes, including but not limited to oil, water, chemicals, mud, and cement, shall be disposed of in such a manner as not to cause damage to life, health, property, freshwater aquifers or surface waters, or natural resources, or be a menace to public safety. Disposal sites for oilfield wastes shall also conform to State Water Resources Control Board and appropriate California Regional Water Quality Control Board regulations.
(b) Dumping harmful chemicals where subsequent meteoric waters might wash significant quantities into freshwaters shall be prohibited. Drilling mud shall not be permanently disposed of into open pits. Cement slurry or dry cement shall not be disposed of on the surface.
(c) Unused equipment and scrap attendant to oilfield operations shall be removed from a production or injection operations area and/or stored in such a manner as to not cause damage to life, health, or property, or become a public nuisance or a menace to public safety. Trash and other waste materials attendant to oilfield operations shall be removed and disposed of properly.


Note: Authority cited: Section 3013, Public Resources Code. Reference: Section 3106, Public Resources Code.




s 14-1776. Well Site and Lease Restoration.
(a) In conjunction with well plugging and abandonment operations, any auxiliary holes, such as rat holes, shall be filled with earth and compacted properly; all construction materials, cellars, production pads, and piers shall be removed and the resulting excavations filled with earth and compacted properly to prevent settling; well locations shall be graded and cleared of equipment, trash, or other waste materials, and returned to as near a natural state as practicable. Well site restoration must be completed within 60 days following plugging and abandonment of the well.
(b) Sumps shall be closed in accordance with Regional Water Quality Control Board and Department of Toxic Substances Control requirements.
(c) Unstable slope conditions created during site preparation shall be mitigated in such a manner as to prevent slope collapse.
(d) Access roads to well locations generally will not be covered by these regulations; however, any condition that creates a hazard to public safety or property or causes interference with natural drainage will not be acceptable.
(e) Prior to the plugging and abandonment of the last well or group of wells on a lease, the operator shall submit a plan and schedule for completing lease restoration. The lease-restoration plan shall also include the locations of any existing or previously removed, where known, sumps, tanks, pipelines, and facility settings. Lease restoration must begin within three (3) months and be completed within one year after the plugging and abandonment of the last well(s) on the lease. However, the supervisor may require or approve a different deadline for lease restoration.
(f) Lease restoration shall include the removal of all tanks, above-ground pipelines, debris, and other facilities and equipment. Remaining buried pipelines shall be purged of oil and filled with an inert fluid. Toxic or hazardous materials shall be removed and disposed of in accordance with Department of Toxic Substances Control requirements.
(g) Upon written request of the operator or property owner, exceptions to this section may be made provided the condition does not create a public nuisance or a hazard to public safety. Exceptions may also be granted by the supervisor when these requirements conflict with local or federal regulations. If a written request for an exception is received from the operator, consent to the exception from the property owner may be required before it is approved by the supervisor.


Note: Authority cited: Section 3013, Public Resources Code. Reference: Sections 3106 and 3208, Public Resources Code.




s 14-1778. Enclosure Specifications.
(a) Chain link fences. All chain link fences shall be constructed to meet the following specifications:
(1) Fences shall be not less than 5 feet high and mounted on 1 1/4" diameter steel posts with at least three strands of barbed wire mounted at a 45-degree angle from the top of the fence.
(2) The fence shall be constructed of chain link or other industrial-type fencing of not less than 11-gauge wire and of not greater than 2-inch nominal mesh.

(3) Supporting posts shall be securely anchored to the surface, spaced no more than 14 feet apart. Provisions for removable posts may be approved provided that the anchoring device is an integral part of the fence.
(4) Tension wires of at least No. 9 gauge coil spring wire, or equivalent, shall be stretched at the top and bottom of the fence fabric and shall be fastened to the fabric at 24-inch intervals. There shall be no aperture below the fence large enough to permit any child to crawl under.
(b) Wire fences. All wire fences shall be constructed to meet the following specifications:
(1) There shall be either: (1) four strands of barbed wire spaced 12 inches between strands and maintained with sufficient tension to preclude sagging; or (2) commercial livestock wire netting with a minimum height of 4 feet and sufficient tension.
(2) Posts may be of any material of sufficient strength and rigidity to support the wire and restrain people or livestock from pushing them over. Posts shall be set no more than 10 feet apart and buried at least 12 inches into the ground.
(c) Gates. Gates shall be of a structure substantially the same as the required fences and shall be kept secured when not attended by an adult.
(d) Screening. All screening to cover sumps shall meet the following specifications:
(1) Be not greater than 2-inch nominal mesh.
(2) Be of sufficient strength to restrain entry of wildlife.
(3) Be supported in such a manner so as to prevent contact with the sump fluid.
(e) Other Types of Materials. Any material that can be used effectively to restrict access may be substituted for the materials indicated in (a), (b), (c), and (d), if approved by the supervisor.


Note: Authority cited: Sections 3013, 3106 and 3782, Public Resources Code. Reference: Sections 3106 and 3781, Public Resources Code.






s 14-1779. Special Requirements.
The supervisor in individual cases may set forth other requirements where justified or called for.


Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Sections 3106, 3226 and 3787, Public Resources Code.