Facility Piping What is it and what do I need to know about it? Office of the State Fire Marshal Pipeline Safety Division Bob Gorham, Division Chief Spring

Facility PipingWhat is it and what do I need to know about it?

Office of the State Fire Marshal

Pipeline Safety Division

Bob Gorham, Division Chief

Spring 2014

• Reportable Spills from Facilities and Pipelines

• DOT Definitions Relating To Pipeline Facilities

• Memorandum of Agreement with Division of Oil Gas and Geothermal Resources (DOGGR)

• Memorandum of Understanding with State Lands Marine Terminal Division(SLC)

• PHMSA Interpretation Letter• Inspection and Testing Requirements at

Facilities

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Discussion Topics

California Hazardous Liquid Pipeline20 year Leak Trend

Source: USDOT-PHMSA 7000-1 accident reports

PHMSA defines Significant Incidents as those incidents reported by pipeline operators when any of the following specifically defined consequences occur: • fatality or injury requiring in-patient hospitalization • $50,000 or more in total costs, measured in 1984 dollars • highly volatile liquid releases of 5 barrels or more or other liquid releases of 50 barrels or more • liquid releases resulting in an unintentional fire or explosion

Reportable Spills 2010 -2014

32 spills from pipelines• Barrels Spilled: 1,624• Property Damage:

$12,580,000

• Only 1 spill from Kern Co.

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47 spills from facilities• Barrels Spilled: 1,952• Property Damage:

$9,105,400 • 16 or 1/3 of facility leaks

from Kern Co.

Spills Definitions DOGGR SLC Interpretation Requirements Questions

• 24 Pump or equipment failure• 17 corrosion

10 internal 7 external

• 3 incorrect operation• 2 external force damage

Spills Definitions DOGGR SLC Interpretation Requirements Questions

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Facility Leak Causes

Facility F ACILITY PIPING

DOGGR SLC Interpretation Requirements QuestionsDefinitionsSpills

Scraper Trap

Breakout Tank

StorageTank

Pumps

Pipeline or pipeline system means all parts of a pipeline facility through which a hazardous liquid or carbon dioxide moves in transportation, including, but not limited to, line pipe, valves and other appurtenances connected to line pipe, pumping units, fabricated assemblies associated with pumping units, metering and delivery stations and fabricated assemblies therein, and breakout tanks. • This means, wherever the hazardous liquid flows, it will be considered part of the

pipeline. There are different requirements for each piece of the pipeline. These requirements include design, installation, operation and maintenance discussed in Part 195.

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CFR 49 Part 195 Definitions


Pipeline facility means new and existing pipe, rights-of-way, and any

equipment, facility, or building used in the transportation of hazardous

liquids or carbon dioxide

• This definition encompasses the pipeline itself as well as the all the equipment, buildings, and all

locations where the pipeline is installed.

• The equipment can include fire-fighting facilities, telemetering equipment and signs for the

pipeline.

• The physical location or real estate of the pipeline right-of-way are also part of the pipeline facility.

• Several parts of the pipeline may be protected by buildings along the ROW making them part of the

pipeline facility. These include buildings for pumping stations, meter facilities, valves, and other

instrumentation.

• These buildings may be occupied or not.

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Title 49 Code of Federal Regulations Part 195 Definitions

Breakout tank means a tank used to (a) relieve surges in a hazardous liquid pipeline system or (b) receive and store hazardous liquid transported by a pipeline for reinjection and continued transportation by pipeline.

• Breakout tanks are normally next to mainline junction stations; most products pass through them enroute to shipper's tanks or for continued transport on the system.

• When the pipeline operator and the storage or breakout tank operator remain the same, the change in jurisdiction occurs at the first and last pressure influencing device, meter, valve, or isolation flange, at or inside the facility property. When the pipeline operator and the storage or breakout tank operator are not the same, the change in jurisdiction occurs at the change in operational responsibility or at the first and last pressure influencing device, valve, or isolation flange, at or inside the facility property.

• In either case, the location of the property line should not solely be used to determine jurisdiction when operational activities (loading/offloading) extend beyond the property line.

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In-plant piping systems means piping that is located on the grounds of a plant and used to transfer hazardous liquid or carbon dioxide between plant facilities or between plant facilities and a pipeline or other mode of transportation, not including any device and associated piping that are necessary to control pressure in the pipeline under §195.406(b).

• For example, if a non-jurisdictional facility has a pump, control valve, relief valve, or valve used to shutdown flow into a jurisdictional pipeline, then those components are DOT jurisdictional even though they are located in a non-jurisdictional facility.

• These typically would be found at the refineries, marine terminals, marketing terminals and production leases.

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• Pursuant to Chapter 1 of Division 3 of the California Public Resources Code, DOGGR regulates tanks and pipelines that are associated integrally with oil and gas production within the administrative boundaries of oil fields. Excluded from DOGGR regulatory authority are pipelines and tanks under the jurisdiction of CAL FIRE – OSFM. Under this MOA, DOGGR will be responsible for all tanks and pipelines from the wellhead to the point of custody transfer. The point of custody transfer includes, but is not limited to, the truck loading dock or the lease automatic custody transfer (LACT) unit.

• Pursuant to Chapter 5.5 of the California Government Code, the CAL FIRE – OSFM’s Pipeline Safety Division regulates all intrastate pipelines used for the transportation of hazardous liquid substances. Additionally, under Chapter 6.67 of the California Health and Safety Code, the CAL FIRE – OSFM’s Fire Engineering Division regulates all tank facilities with 1,320 gallons or more of petroleum, while the Unified Program Agencies inspect these tank facilities for compliance with the Aboveground Petroleum Storage Act. For the purposes of this MOA, the CAL FIRE – OSFM jurisdiction will begin at the point of custody transfer. Thus, once the product in an aboveground storage tank goes through the LACT or the product in the tank is for retail or sales, the tank is subject to CAL FIRE – OSFM jurisdiction.

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MOA with DOGGR Division of Oil, Gas & Geothermal Resources

SLC Interpretation Requirements QuestionsSpills DOGGRDefinitions

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DOGGR Interpretation Requirements QuestionsSpills SLCDefinitions

Subject: California State Fire Marshal/California State lands Commission Cooperative Agreement

The California State Fire Marshal (CSFM) and the California State Lands Commission (SLC) entered into a Memorandum of Understanding (MOU) on March 16, 1994, to set forth guidelines for coordination and cooperation in carrying out the mandates of the laws and regulations designed to protect the public and environment with regard to marine terminals and associated pipelines.

In support of the MOU, the two agencies conducted a joint assessment of California's marine terminals to define existing pipelines, reduce uncertainty over regulatory jurisdiction, and eliminate any possible jurisdictional overlap. These assessments do not alter the terms and conditions of marine terminal leases with the State of California.

US DOT-PHMSA vs

Certified Unified Program Agency (CUPA)Determination of jurisdiction

In 2009, WestPac Pipelines asked USDOT- PHMSA for a determination of jurisdiction for an underground jet fuel filter sump tank at a facility serving the San Diego Airport.

This letter and the following response from PHMSA is used by the Office of the State Fire Marshal as a basis for determining jurisdiction at facilities where the local CUPA agencies are questioning inspection and enforcement authority.

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Interpretations

DOGGR SLC Requirements QuestionsSpills Definitions Interpretation

PHMSA Interpretation 195.2 36August 11, 2009Mr. Adam F. Kovacs

Environmental Coordinator

WestPac Pipelines

2355 Main Street, Suite 210

Irvine, CA 92614

Dear Mr. Kovacs:

On January 9, 2009, and February 10, 2009, you wrote to the Pipeline and Hazardous Materials Safety Administration (PHMSA) to request an interpretation of the applicability of the Federal pipeline safety regulations in 49 CFR Part 195 to your underground jet fuel filter sump tank at the San Diego Airport Terminal. You provided the following information:

1. The jet fuel filter sump tank is located at the 10th Avenue Marine Terminal, 961 East Harbor Drive in San Diego, California, and is operated by Jankovich Company but owned by WestPac Pipe Lines – San Diego LLC (Buckeye).

2. 2. Until November 26, 2008, the above mentioned sump tank had been regulated by the California Office of the State Fire Marshal (OSFM) under the authority of the California State Code Section 51010 and in the OSFM’s capacity as an agent for PHMSA in enforcing the pipeline safety regulations in 49 CFR Part 195.

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Interpretations


Cont. PHMSA Interpretation 195.2 36August 11, 2009

3. 3. A question regarding jurisdictional authority for the jet fuel filter sump tank arose during a November 26, 2008, County of San Diego compliance inspection at the Jankovich Company’s facility.

4. 4. The County of San Diego inspection resulted in the County requesting you do one of the following two things by January 25, 2009:• Provide current evidence that this sump tank is regulated by OSFM and subject to the 49 CFR Part 195

regulations; or• Provide tank information on updated forms in order to register the sump tank as a County regulated

underground tank.

5. Previously, in the fall of 2001, the County of San Diego conducted an inspection of the jet fuel filter sump tank, and the OSFM formally took the position that the subject sump tank served a breakout function to the pipeline and consequently was under OSFM jurisdiction. However, since the November 26, 2008, inspection you stated that OSFM changed its view and no longer believes that this sump tank should be regulated as a breakout tank.

6. The sump tank receives overpressure-generated product (pressure relief) from the filter system. The filter system and the subject tank are integral components of the pipeline system.

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Interpretations


Cont. PHMSA Interpretation 195.2 36August 11, 2009

7. The sump tank stores hazardous liquid (jet fuel), which is temporarily transported to an aboveground breakout tank (also part of the pipeline system), and subsequently re-injected into another pipeline segment (in via pipeline, out via pipeline). The aboveground breakout tank that the jet fuel filter sump tank empties into is a part of the pipeline system as well.

You expressed your view that the jet fuel filter sump is a pipeline regulated tank under 49 CFR Part 195 and therefore should be regulated by the OSFM. You ask that PHMSA make an official determination of whether or not this tank is subject to the Part 195 regulations.

Based on the information you provided, PHMSA’s determination is that the jet fuel filter sump tank is equipment used in the transportation of hazardous liquids. Therefore, the jet fuel filter sump tank is a pipeline facility and is subject to all applicable 49 CFR Part 195 requirements including corrosion control, integrity management, and personnel qualification and OSFM is currently responsible for regulating the tank.

I hope that this information is helpful to you. If I can further assist you with this or any other pipeline safety regulatory matter, please contact me at (202) 366-4046.

Sincerely, John A. Gale

Director, Office of Regulations

USDOT-PHMSA

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Interpretations


• We identified what is a jurisdictional facility • We established regulatory agency boundaries• We will now cover federal regulatory requirements for maintenance

and inspection activities as specified in CFR 49 Part 195. • These include:

Pressure Testing Integrity Management Corrosion Control Security Signs Fire fighting equipment Scraper Traps BO tanks Remote operation procedures

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What Does This All Mean?

DOGGR SLC Interpretations QuestionsSpills Definitions Requirements

• Must perform an initial Part 195 hydrotest• 8 hours or 4 hours if entirely visible• Must notify SFM and use independent 3rd party• Follow SFM hydrotest guidelines

• There are currently no requirements for the operator to periodically retest PHMSA jurisdictional piping within a facility.

• Unless…………………………….your integrity management program identifies a need to do so.

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Pressure Testing for Facility Piping

§195.302 General requirements.(a) Except as otherwise provided in this section and in §195.305(b) , no operator may operate a pipeline

unless it has been pressure tested under this subpart without leakage. In addition, no operator may return to service a segment of pipeline that has been replaced, relocated, or otherwise changed until it has been pressure tested under this subpart without leakage.

§195.305 Testing of components.Component means any part of a pipeline which may be subjected to pump pressure including, but not limited to, pipe, valves, elbows, tees, flanges, and closures.

(a) Each pressure test under §195.302 must test all pipe and attached fittings, including components, unless otherwise permitted by paragraph (b) of this section.

(b) A component, other than pipe, that is the only item being replaced or added to the pipeline system need not be hydrostatically tested under paragraph (a) of this section if the manufacturer certifies that either-

(1) The component was hydrostatically tested at the factory; or

(2) The component was manufactured under a quality control system that ensures each component is at least equal in strength to a prototype that was hydrostatically tested at the factory.

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Pressure TestingCode Sections relating to facility piping

2.1 Does the rule apply to more than line pipe?

Yes. The continual evaluation and information analysis requirements of the rule apply to pipelines as defined in 49 CFR 195.2. This includes, but is not limited to, line pipe, valves and other appurtenances connected to line pipe, metering and delivery stations, pump stations, storage field facilities, and breakout tanks. The baseline integrity assessment and periodic re-assessment requirements apply only to line pipe.


Pressure TestingHazardous Liquid Integrity Management: FAQs

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2.12 Does the rule apply to the operator of a marketing facility if that operator does not own or operate a pipeline but rather receives and delivers hazardous liquid from/to third-party pipelines?

Yes, if the facility is otherwise covered by Part 195. (The integrity management rule, by itself, makes no changes to the applicability of Part 195 rules). Since Part 195 applies generally to pipeline facilities, not just to line pipe, the requirements of §195.452 for HCA identification also apply to facilities that fall under Part 195 jurisdiction. If the operator’s facilities could affect an HCA, then the operator would be required to have an integrity management program that implements all applicable requirements of the rule including, the need to identify risks to the facility and take preventive and mitigative actions to reduce these risks.

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3.17 Must non-pipe elements of a pipeline system that can affect HCAs (e.g., stations and facilities) have been identified?

Yes. While the assessment requirements of 49 CFR 195.452 are applicable to line pipe, all other requirements, including segment identification, are applicable to the entire pipeline system as defined in 49 CFR 195.2. PHMSA Pipeline Safety expects operators to understand which pump stations, terminals, and other facilities might also affect HCAs in the event of a failure.

• Essentially, identical to mainline pipeline• Annual cathodic protection surveys• 3 year atmospheric corrosion survey• Internal corrosion mitigation• Bi-Monthly Rectifier inspections

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Facility Corrosion ControlRequirements

(a) Each buried or submerged pipeline that is constructed, relocated, replaced, or otherwise changed after the applicable date in Sec. 195.401(c) must have cathodic protection. The cathodic protection must be in operation not later than 1 year after the pipeline is constructed, relocated, replaced, or otherwise changed, as applicable.

(b) Each buried or submerged pipeline converted under Sec. 195.5 must have cathodic protection if the pipeline--

(1) Has cathodic protection that substantially meets Sec. 195.571 before the pipeline is placed in service; or

(2) Is a segment that is relocated, replaced, or substantially altered.

(c) All other buried or submerged pipelines that have an effective external coating must have cathodic protection.(see Note below) Except as provided by paragraph (d) of this section, this requirement does not apply to breakout tanks and does not apply to buried piping in breakout tank areas and pumping stations until December 29, 2003

(d) Bare pipelines, breakout tank areas, and buried pumping station piping must have cathodic protection in places where regulations in effect before January 28, 2002 required cathodic protection as a result of electrical inspections. See previous editions of this part in 49 CFR, parts 186 to 199.

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Facility Corrosion Control§195.563 Which pipelines must have CP?

§195.436 Security of Facilities

Each operator shall provide protection for each pumping station and breakout tank area and other exposed facility (such as scraper traps) from vandalism and unauthorized entry.

TSA Pipeline Security Guidelines, December 2010

§195.434 Signs

Each operator must maintain signs visible to the public around each pumping station and breakout tank area. Each sign must contain the name of the operator and a telephone number (including area code) where the operator can be reached at all times.

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Additional Facility Requirements

§195.430 Firefighting Equipment

Each operator shall maintain adequate firefighting equipment at each pump station and breakout tank area. The equipment must be-- (a) In proper operating condition at all times; (b) Plainly marked so that its identity as firefighting equipment is clear; and (c) Located so that it is easily accessible during a fire.

§195.426 Scraper and Sphere Facilities

No operator may use a launcher or receiver that is not equipped with a relief device capable of safely relieving pressure in the barrel before insertion or removal of scrapers or spheres. The operator must use a suitable device to indicate that pressure has been relieved in the barrel or must provide a means to prevent insertion or removal of scrapers or spheres if pressure has not been relieved in the barrel.

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§195.432 Breakout Tanks

(a) Except for breakout tanks inspected under paragraphs (b) and (c) of this section, each operator shall, at intervals not exceeding 15 months, but at least once each calendar year, inspect each in-service breakout tank.

(b) Each operator must inspect the physical integrity of in-service atmospheric and low-pressure steel aboveground breakout tanks according to API Standard 653 (incorporated by reference, see § 195.3). However, if structural conditions prevent access to the tank bottom, the bottom integrity may be assessed according to a plan included in the operations and maintenance manual under § 195.402(c)(3)

c) Each operator shall inspect the physical integrity of in-service steel aboveground breakout tanks built to API Standard 2510 according to section 6 of API 510.

(d) The intervals of inspection specified by documents referenced in paragraphs (b) and (c) of this section begin on May 3, 1999, or on the operator's last recorded date of the inspection, whichever is earlier.

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(8) In the case of pipeline that is not equipped to fail safe, monitoring from an attended location pipeline pressure during startup until steady state pressure and flow conditions are reached and during shut-in to assure operation within limits prescribed by §195.406.

(9) In the case of facilities not equipped to fail safe that are identified under §195.402(c)(4) or that control receipt and delivery of the hazardous liquid or carbon dioxide, detecting abnormal operating conditions by monitoring pressure, temperature, flow or other appropriate operational data and transmitting this data to an attended location.

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§195.402 operation and maintenance procedures

• Gauges – if you have them on the system, they should be regularly inspected and calibrated.

• Buried piping • How do you know what condition it is in? • Dead legs – internal corrosion leak waiting to happen• Many of our operators are voluntarily conducting integrity

testing to determine fitness.

• I believe PHMSA will eventually strengthen code requirements regarding inspection, testing and maintenance of facility piping and equipment.


Additional Considerations

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Contact information:

Bob Gorham

Email: [email protected]

Office phone: 562-497-9100

http://osfm.fire.ca.gov/

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DOGGR SLC Interpretations RequirementsSpills Definitions Questions

Questions

Documents

Facility Piping What is it and what do I need to know about it? Office of the State Fire Marshal Pipeline Safety Division Bob Gorham, Division Chief Spring