Pipelines and Facilities

Design Specifications

In most tanks and vessels, oil is separated from the water that is commonly produced with the oil during the extraction process 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. 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.

The sub-base of the tank foundation shall include an impermeable barrier designed to prevent downward fluid migration. A concrete foundation fulfills this requirement and is the preferred foundation type. The foundation sub-base must also have a means to detect tank leaks.

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 through the use of sensors. One means of channeling leaks is installing grooves in a concrete foundation. The grooves allow for any fluid leak to pass along the grooves and channel outside the tank’s circumference.

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

Tank Identification

The owner of tanks and vessels and their locations can be found on CalGEM's GIS Maps program.

Tanks must be properly identified with:

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

Monthly Inspections

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:

1. Leakage at base, seams, associated piping, tank shell plugs, or any other fitting that could leak
2. Presence of corrosion or shell distortions
3. General condition of the foundation, including any signs of settling or erosion that may undermine the foundation
4. Condition of paint coatings, insulation systems, and tank grounding system components, if present

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.

Wall Thickness Testing

California requires that the walls or sides of in-service tanks be tested for thickness every five (5) years, unless otherwise approved by the CalGEM State Supervisor of Oil and Gas. Operators must notify CalGEM two days or more prior to conducting required tank testing.

Tank wall thickness testing is usually performed by a reputable tank inspection company using ultrasonic thickness-testing equipment. The inspection company goes to the site to measure the wall thickness in various places. Using the smallest thickness measured from the various readings, the inspector can potentially determine the tank corrosion rate. If the corrosion rate can be determined, inspection time intervals, subject to approval by the CalGEM State Supervisor of Oil and Gas, 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 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.

The internal inspection and bottom plate thickness testing is also usually conducted using ultrasonic thickness testing equipment by a reputable tank inspection company. For the bottom plate thickness testing, the 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.

A gas pipeline leak at an oil production facility in Arvin, California in 2014 forced the evacuation of eight neighborhood homes for more than eight months. During the investigation of the leak, inspectors determined that some gas pipelines were not inspected and tested. In response to this incident, Governor Brown signed AB 1420 into law on October 8, 2015, which required CalGEM to evaluate, and update its requirements for gas pipelines in sensitive areas, and CalGEM has updated its regulations to add new testing and inspection requirements for those pipelines.

Those new rules took effect on October 1, 2018. A high-risk area, called a “sensitive area,” was defined specifically for all active gas production pipelines located within 300 feet of residences, businesses, schools, and hospitals. Active gas pipelines that are more than 10 years old and are located within sensitive areas must be:

1. Inspected for leaks and defects yearly, and
2. Tested every two years (see diagram)

September 2018 AB 1420 Compliance Workshop presentation

Operator Guidance for AB 1420 Compliance

Also, operator pipeline management plans (PMPs) must be updated by October 1, 2019 to include maps and safety protocols for all covered pipelines.

Per AB 1420, operators had a January 2018 deadline to submit maps to CalGEM showing active gas pipelines routed through sensitive areas. Additional regulations (referred to as AB 1420 Part B in rulemaking and workshops) are in development that will require submission of a GIS location map of all active gas pipelines located in sensitive areas. Public workshops have been scheduled for June 19 and 20, 2019. Public Workshop Notice

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 inspection per regulation 1774.1(a) and (b) without notification to CalGEM as this activity is not testing. Furthermore, pipelines not located within high-risk areas are to 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 test notification 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

Operator PMP minimum requirements were revised and became effective on October 1, 2018. PMPs are required and must be current to include all pipelines, except those pipelines abandoned per 14CCR§1776. P​MPs 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

A spill contingency plans (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 and prevent spills. SCP’s include maps showing the location and contents of all tanks and of all 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 to be adequate by the appropriate CalGEM district deputy.

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 contain 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. This secondary containment is intended to confine the liquid and prevent it from entering into 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.

Secondary containment shall be capable of confining liquid for a minimum of 72 hours. Secondary containment walls can be constructed of concrete or construction blocks that are cemented together.

Earthen berms are effective if they are compacted sufficiently so that they will continue to hold fluid for an extended period of time. Covering a berm with heavy duty plastic sheeting or shotcrete is another way to fortify it. Any damage to the secondary containment, such as cracks in the walls, shall be repaired immediately .

The secondary containment’s surface area must be capable of containing fluids. Concrete is often the most effective material, but soil or gravel can be successful if compacted sufficiently to retain fluids. A soils engineering firm can run an analysis in a containment area to test the soil’s compaction. The soil must be sufficiently compacted to retain fluids for a minimum of 72 hours, in order to comply with regulations.

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 waste water 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.

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.

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.

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, where known:

• Sumps
• Tanks
• Pipelines
• Facility Settings

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.