Pipelines and Facilities

When a piece of production facility equipment such as a tank, vessel, or pipeline is determined to be Out-of-Service, the following actions must be completed within six months:

1. All fluids, sludge, hydrocarbons, and solids shall be removed. Production facilities shall be disconnected from any pipelines and other in-service equipment.
2. The facility shall be degassed in accordance with local air district requirements.
3. Clean-out doors or hatches on out-of-service tanks shall be removed and heavy gauge steel mesh grating (less than 1” spacing) shall be secured over the opening to allow for visual inspection and prevent unauthorized access.
4. Tanks and vessels shall be labeled “Out-of-Service” or “OOS.” The label shall be painted in bold letters, at least one (1) foot high and at least five (5) feet off the ground, on the side of the tank or vessel, along with the date it was taken out of service.
5. Valves and fittings shall be removed or secured to prevent unauthorized use.
6. Pipelines associated with Out-of-Service tanks and pressure vessels shall be removed or flushed, filled with an inert fluid (such as nitrogen ), and blinded.

No Out-of-Service production equipment shall be put back In-Service until all repairs are completed and the facility is in compliance with all applicable testing and inspection requirements. Operators shall notify the local district office within 60-days after completing new construction, alteration, or decommissioning of a production facility, or reactivating an Out-of-Service tank.

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. Following the conclusion of operations on the lease, the well site must be restored to as near a natural state as possible. The Lease Restoration Plan (the Plan) shall include the locations of any existing or previously removed sumps, tanks, pipelines, or facility settings, where known.

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 (such as water). Toxic or hazardous materials shall be removed and disposed of in accordance with Department of Toxic Substances Control requirements.

Lease restoration work 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.

There is not a specific format for the Plan. However, it must contain and cover how all the elements discussed here will be removed and how the well site will be restored.​

A sump or pit is an open excavation that collects or stores fluids. There are three types of sumps:

1. Drilling Sump - used with drilling operations
2. Operations Sump - used with well rework or abandonment operations
3. Evaporation Sump - a pit containing fresh or saline water for evaporation

A catch basin is a dry sump constructed to protect against unplanned overflow conditions. While also a type of sump, a catch basin is considered a secondary containment measure because it functions in tandem with primary containment measures.

Location:

1. Sumps for the collection of wastewater or oil are not permitted in natural drainage channels. Contingency catch basins may be permitted, but they shall be evacuated and cleaned after any spill.
2. Unlined evaporation sumps, if they contain harmful waters, shall not be located where they may be in contact with freshwater aquifers.
3. Operators should be aware that sumps must also comply with applicable State Water Resources Board and local air pollution control district requirements in addition to CalGEM requirements.

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 must be enclosed by a chain link fence, and gates must be locked.
2. In non-urban areas, to protect people and livestock and to deter wildlife, an enclosure shall be constructed around sumps with wire fencing.
3. Any evaporation sump which contains oil or a mixture of oil and water shall be covered with screening to restrain entry of wildlife.
4. A sump need not be individually fenced if the property or the production facilities of which the sump is part is enclosed by proper perimeter fencing.

Drilling Sumps: All free fluids must be removed from drilling sumps within 30 days after the date the drill rig is disconnected from the well.

Operations Sumps: All fluids shall be removed from operations sumps within 14 days after the rig removal or from completion of operations, whichever occurs first. ​

A spill contingency plan (SCP) outlines an operator's measures for controlling, containing, and recovering an oil or water release. An approved SCP includes provisions for rapid deployment of containment and recovery equipment; it lists the initial steps the operator will take in the event of a spill, the equipment the operator has on hand to control the spill, phone numbers that the operator will call to inform other agencies of the spill, and details the training that staff working for the operator undergo to prepare for and prevent spills. SCPs include maps showing the location and contents of all tanks and pipelines at a production facility, and the location of structures present to contain spills.

Spills shall be reported immediately to the California Office of Emergency Services (OES) at (800) 852-7550. OES will notify CalGEM's local district office. However, if a spill happens outside regular business hours, operators should notify the local CalGEM district office directly.

The U.S. Environmental Protection Agency (EPA) requires a Spill Prevention Countermeasure and Control Plan (SPCC) from oil and gas operators as part of its oil spill prevention program. An operator's SPCC may satisfy spill contingency plan requirements if the SPCC has all of the elements required by CalGEM for inclusion in the SCP and is determined by CalGEM to be adequate.

Secondary containment is an engineered impoundment or confinement, such as a wall, berm, or catch basin, designed to capture fluid released from a production facility. A leak or spill may release large amounts of oil, and secondary containment must be capable of containing the equivalent volume of liquids from the single piece of equipment at a production facility with the largest gross capacity within the secondary containment. Containment is intended to confine the liquid and prevent it from entering streams, lakes, the ocean, homes, streets, and more. Secondary containment allows for a quick clean-up after a leak or spill.

All oil and gas facilities that store or process fluids must have secondary containment measures in place. Valves, headers, manifolds, pumps, compressors, wellheads, pipelines, flowlines, and gathering lines are excluded from the secondary containment requirement.

A secondary containment's floor surface area and wall or berm must be capable of confining liquid for a minimum of 72 hours. Materials of construction are chosen by the operator. Soils considered for containment area construction can be verified to be acceptable via permeability testing performed by a soils engineering firm. Also, if soil is used for a berm, the addition of a heavy-duty plastic sheeting or shotcrete can be considered to improve durability.

Any damage to the secondary containment, such as cracks, erosion, or animal borrows shall be repaired immediately. ​

All newly installed, repaired, or modified existing pipelines must be tested prior to starting or re-starting operations. Any pipeline having a leak of reportable quantity must successfully pass pressure testing before returning to service. Additionally, CalGEM-regulated pipelines must be tested on a periodic basis. Active oil or gas pipelines located in high-risk areas, such as environmentally sensitive, urban, and sensitive areas, require biennial testing after reaching the age of 10 years. Acceptable testing methods include pressure testing, ultrasonic, and smart pigging. Approval from CalGEM is required before using a testing method other than pressure testing ​or ultrasonic testing to determine wall thickness. CalGEM recommends operators seek input from CalGEM when planning an ultrasonic test of a pipeline located in a high-risk area ( NTO 2019-09​​​).​ Operators may conduct pipeline leak inspections per Regulations sections 1774.1(a) and (b) without notification to CalGEM, as this activity is not considered testing. Furthermore, pipelines not located within high risk areas must be tested at a minimum per the interval specified by Cal-OSHA. Operators must notify the local CalGEM district office at least two days prior to any required pipeline testing. CalGEM does not require notification of testing for pipelines not located within high risk areas, unless these pipelines are tested following a repair due to a reportable leak.

Optional pressure-test data collection template

Revised Pipeline Management Plan (PMP) requirements became effective on October 1, 2018. PMPs are required for all operators and must be updated to include all pipelines, except those pipelines abandoned per Regulations section 1776. PMPs must be updated within 90 days whenever pipelines are installed or altered, or at request of the Supervisor.

Some larger operators may have existing line lists showing required PMP data. These line lists may meet some pipeline information requirements and can be referenced in the PMP. For operators relying on a line list to meet any PMP requirements, a current electronic copy must be provided to CalGEM.

Operator PMP Template

Title 14 of the California Code of Regulations (Regulations) section 1773.2 contains requirements for Tank Construction and Leak Detection.

Design Specifications

In most tanks and vessels, oil is separated from the water that is commonly produced during the process of extracting oil from oil wells. All new tanks shall be constructed and designed to provide enough space between tanks to allow safe access for maintenance, inspection, testing, and repair. New tanks are those constructed on or after January 29, 2011. Two key components in tank construction are foundation design and leak detection.

Foundation Design

Foundations for new tanks shall be designed to support the tank, maintain the tank level, and drain fluid away from the tank, including fluids that may leak from the tank. It is important that fluids drain away from the tank so that leaks can be identified immediately, before they cause environmental damage.

For new tanks, the sub-base of the foundation shall include an impermeable barrier designed to prevent downward fluid migration and to allow leaks to drain away from the tank. That way, leaks can be detected by either visual inspection or a leak detection sensor.

Leak Detection

A leak detection system is required for all new tanks and when a tank bottom is replaced. The system must either channel any leak beneath the tank to a location where it can be readily observed from the outside perimeter of the tank, or accurately detect any tank bottom leak by the use of sensors. One means of channeling leaks is installing grooves in a concrete foundation. These grooves allow leaking fluid to flow outward beyond the tank's circumference where it can be seen.

To use sensors for leak detection, probes can be installed under the tank and connected to a monitoring system. These probes are specifically designed to sense hydrocarbons and can be installed to fulfill the leak detection requirement.

Regulations sections 1773.3 and 1773.4 provide requirements for Tank Maintenance and Inspections, and Tank Testing and Minimum Wall Thickness Requirements. Regulations section 1777 addresses monitoring and maintenance requirements applicable to all production facilities. Regulations section 1777.2 addresses operator reporting and notification requirements.

Tank Identification

CalGEM's WellSTAR database and WellFinder GIS program contains a list of tanks and vessels, including the owners and locations of this equipment.

Tanks must be properly marked or have signage that shows:

1. Operator's Tank Identification Number
2. Tank Type (production, stock, water, etc.)
3. Appropriate Materials Hazards Placard or Labels

Monthly Inspections

External visual inspections are required at least once a month on all in-service tanks associated with oil and gas production. Operators shall inspect for the following:[EM1]

1. Leakage at base, seams, associated piping, tank shell plugs, or any other fitting that could leak.
2. The presence of corrosion or shell distortions.[EM2]
3. The general condition of the foundation, including any signs of settling or erosion that may undermine the foundation.[EM3]
4. The condition of paint coatings, insulation systems, and tank grounding system components, if present.
5. Any damage to secondary containment and the general condition of secondary containment systems.
6. The open/closed status of rainwater drain valves.[EM4]

Monthly inspection findings shall be documented either on paper or electronically. The records shall be maintained and easily accessible so that a CalGEM inspector can review them upon request.[EM5]

Wall Thickness Testing

California requires that the walls or sides of in-service metallic tanks be tested for thickness every five (5) years, unless otherwise approved by CalGEM . Operators must notify the local CalGEM district office at least two days prior to conducting required tank testing.

Operators often hire a tank inspection company to perform tank wall thickness testing, using ultrasonic thickness-testing equipment. The tank inspection company visits the production facility to measure the wall thickness in various places. Using the lowest thickness measured from the various readings, an inspector can potentially determine the tank corrosion rate. If the corrosion rate can be determined, inspection time intervals, subject to approval by CalGEM, may be extended, but must still be done at least once every 15 years.

The minimum thickness for a tank shell is 0.06 inch.

Internal Inspection and Bottom Plate Testing

In-service metallic tanks shall be internally inspected and tested to determine bottom plate thickness no less than once every 20 years. A tank is exempt from this requirement if:

1. The tank is not an environmentally sensitive tank, it is not in an urban area, and is not located above subsurface fresh water; or
2. The sub-base of the foundation of the tank has an impermeable barrier designed to prevent downward fluid migration and to allow leaks to drain away from the tank; or
3. The tank has a properly installed, operating, and maintained leak detection system.

Inspectors usually use ultrasonic thickness testing equipment to perform internal inspection and bottom plate thickness testing. For bottom-plate thickness testing, an inspector will take readings at various places. The smallest thickness measured from the various readings determines if the plate is still usable. The minimum bottom plate thickness shall meet the following criteria:

1. 0.10 inch for tank bottom/foundation design with no means of detection and containment of a bottom leak;
2. 0.05 inch for tank bottom/foundation design with adequate leak detection and containment of a bottom leak;
3. 0.05 inch in conjunction with a reinforced tank bottom lining, greater than 0.05 inch thick.

Testing and Inspection for Non-metallic Tanks and Metallic Tanks with Liners

Non-metallic tanks and metallic tanks with liners require inspections and tests according to the manufacturer's specifications or as requested by CalGEM.​