The San Bruno Explosion: Pipeline Safety in California

A Joint Informational Hearing of the Senate Committees on
Energy, Utilities & Communications and Public Safety

On the evening of September 9, 2010 a 30-inch natural gas transmission line ruptured in a residential neighborhood in the City of San Bruno. The rupture caused an explosion and fire which took the lives of eight people and injured dozens more; destroyed 37 homes and damaged dozens more. Gas service was also disrupted for 300 customers.

The pipeline in question is owned and operated by Pacific Gas & Electric (PG&E) and originally built in 1948. In 1956 it was relocated and rebuilt to accommodate new housing development. The National Transportation Safety Board (NTSB), in conjunction with the California Public Utilities Commission (CPUC) was on scene within 24 hours to investigate the cause of the explosion. Although preliminary elements of the investigation have been detailed, a final report on causation could take months. In the meantime the investigating agencies are not expected to release any further information unless a finding is made during the course of the investigation for which investigators believe an immediate action or repair of the system is warranted. During this stage PG&E is precluded by its regulatory agencies from discussing specific details related to the explosion.

Although causation will not be known for some time, it does not preclude the Legislature from taking stock of this tragedy and launching its own review of the maintenance, inspection and funding of gas transmission pipeline infrastructure in California. That is the purpose of today’s hearing.

NATURAL GAS PIPELINES

The transportation of natural gas from the wellhead to the consumer involves three major types of pipelines: gathering systems, transmission systems, and distribution systems. Gathering pipeline systems gather raw natural gas from production wells. Natural gas transmission pipeline systems transport natural gas thousands of miles across many parts of the continental United States. Natural gas distribution pipeline systems can be found in thousands of communities from coast to coast and distribute natural gas to homes and businesses.

The pipe used in natural gas pipeline systems can range in size from 2 inches to 42 inches in diameter; transmission lines generally start at 4 inches. Natural gas gathering and transmission pipeline systems are constructed from steel pipe. However, natural gas distribution systems can be constructed from steel or plastic pipe. The use of modern plastic pipe is becoming more and more prevalent for distribution systems.

Natural gas pipeline systems are owned and operated by many different companies. The location, construction and operation of these systems are generally regulated by the U.S. Department of Transportation's Pipeline and Hazardous Material Safety Administration (PHMSA) and, for California, the CPUC. According to the PHMSA, California has 12,414 miles of gas transmission lines: 5,777 owned and operated by PG&E and approximately 4,000 miles owned and operated by Sempra doing business as SoCalGas and San Diego Gas & Electric. The state has 102,475 miles of distribution lines: 42,017 miles for PG&E and 47,000 miles for Sempra.

Combined, Sempra and PG&E own and maintain approximately 85 percent of the gas transmission and distribution lines in the state.

GAS PIPELINE REGULATION

PHMSA, acting through the Office of Pipeline Safety (OPS), administers the national regulatory program to ensure safe transportation of natural gas, petroleum, and other hazardous materials by pipeline. Federal/state partnerships have been established to ensure uniform implementation of the pipeline safety program nationwide.

Federal pipeline safety regulations are intended to: (1) assure safety in design, construction, inspection, testing, operation, and maintenance of pipeline facilities; (2) set out parameters for administering the pipeline safety program; and (3) delineate requirements for onshore oil pipeline response plans. Gas pipeline regulations are written as minimum performance standards. The regulations for gas transmission pipelines are published in the Code of Federal Regulations, 49 CFR Part 192.

While PHMSA is primarily responsible for developing, issuing, and enforcing pipeline safety regulations, the pipeline safety statutes provide for assumption of the intrastate regulatory, inspection, and enforcement responsibilities by the states under an annual certification. To qualify for certification, a state must adopt the minimum federal regulations and may adopt additional or more stringent regulations as long as they are not incompatible. A state must also provide for injunctive and monetary sanctions substantially the same as those authorized by the pipeline safety statutes.

For California the result of this regulatory framework is that PHMSA regulates interstate gas transmission pipelines and the CPUC has assumed responsibility for intrastate gas transmission and distribution pipelines. The CPUC has adopted the sections of Title 49 of the CFR which are pertinent to gas safety in its General Order (GO) 112-E. Subsequent changes to the Federal Pipeline Safety Code are automatically updated in GO 112-E with the effective date being the date of the final order as published in the Federal Register.

Responsibility for the regular inspection of all gas transmission lines falls to the owner and operator of the line. PHMSA and the CPUC conduct audits of the design, construction, maintenance and operations practices of the pipeline companies to ensure that they are in compliance with state and federal law. In the event of a violation of the regulations, the CPUC and PHMSA have the authority to impose administrative, civil, or criminal remedies.

PG&E reports that its practices for the design, construction, maintenance and operation of its gas transmission pipelines are:

 

…documented in its standards and work practices. At a minimum PG&E's practices must comply with GO 112-E. PG&E has some latitude in deciding how it will comply with GO 112-E. PG&E's practices may not match identically practices used by other natural gas transmission pipeline companies across the United States. The CPUC does not specify the exact design, construction, maintenance and operations practices a company must use. The CPUC only determines if PG&E's practices satisfy the requirements of GO 112-E. Other organizations such as the Society of Mechanical Engineers (ASME), American Gas Association (AGA) and the National Association of Corrosion Engineers (NACE) publish recommended practices for designing, constructing, maintaining and operating natural gas pipelines. PG&E strives to understand and follow practices recommended by these organizations.

PIPELINE CORROSION: PREVENTION & INSPECTION

PG&E reports that it inspects its gas transmission pipelines semi-annually or annually for leaks, quarterly for general inspection patrol, and every seven years for an integrity inspection if warranted. Federal law sets forth approved methods for inspection and corrosion assessment. PG&E has provided a summary of the process of corrosion, the techniques used to prevent pipeline corrosion, and inspection processes and timelines to detect corrosion and leaks. It appears at the end of this document as Attachment 1.

The CPUC reports that audits of pipeline operators include a review of records of operation and maintenance at the pipeline owner’s local division or district. The following is a list of records most commonly reviewed during this type of audit:

• Leak survey
• Leak repairs
• Cathodic protection survey and repairs
• Atmospheric corrosion control monitoring
• Line patrolling records
• Compressor station procedures and inspection/maintenance records
• Pressure limiting and regulating stations inspection records
• Valve inspections and repairs
• Vault maintenance
• Odorization sampling
• Identifying changes in Class Locations and review of the maximum allowable operating pressure (MAOP)
• Pipeline testing records for new segments placed in service
• Uprating records
• Operator qualification records
• One-call tickets in response to the damage prevention program.

Program-specific audits are also conducted. These audits include a review of the operator’s processes and procedures for compliance with 49 CFR 192. The following is a list of program-specific audits:

• Operation, Maintenance, and Emergency Plans
• Operator Qualification
• Welding and Joining procedures
• Drug and Alcohol testing
• Public Awareness Program (going forward as the Pipeline and Hazardous Materials Safety Administration creates inspection process for this) Integrity Management Program.

 SAN BRUNO LINE 132 INSPECTIONS

Line 132 in San Bruno was inspected by PG&E in 2008, 2009, and 2010. The CPUC provided the following summary of those inspections:

PG&E performed aerial pipeline patrols of Line 132, from approximately 16 miles south of the rupture location to the San Francisco county line, on the following dates (03/18/09; 06/29/09; 09/16/09; 12/09/09; 03/17/10; and 06/16/10). None of these patrols noted any dead vegetation, construction, or other activity occurring near the incident location.

Leak surveys performed by PG&E, which included the rupture location on Line 132, were performed on the following dates: May 23-25, 2008; March 25, 2009; and March 18, 2010.

Finally, in 2009, PG&E performed a Direct Assessment on line 132 as part of the baseline assessment of the line required by federal pipeline safety regulations. [An External Corrosion Direct Assessment (ECDA) process was utilized] which has four steps. Step 1 – pre-assessment includes data collection, and feasibility assessment to select the appropriate indirect assessment tool to use. Step 2 of the ECDA process includes indirect inspections. Indirect assessment was performed on a segment of Line 132 (M.P. 37.80-43.75), which included the location involved in the September 9th explosion and fire. The particulars of this indirect assessment will be examined as part of the NTSB’s investigation. The type of indirect assessment method generally utilized by PG&E for this segment is a Close-Interval Survey. A close-interval survey involves a person holding electrodes walking along the line or close to the line to measure the current to ensure that the cathodic protection is working all along the line. The purpose of the survey is to identify areas where the cathodic protection may not be working effectively. This survey method detects situations such as pipeline coating holidays, interference, contact with other metallic structures that may interfere with cathodic protection. Based on the indications received in the Step 2 survey, Step 3 calls for direct examinations of specific locations. Direct examination requires excavation of the pipe to measure coating defects, metal loss. Step 3 may also include ultrasonic testing or X-ray of the pipe. PG&E performed some Phase 3 – direct examinations in 2009 on Line 132 (specific locations will be confirmed as part of the NTSB investigation), but no direct examination excavations included the location involved in the September 9th explosion and fire.

ENFORCEMENT

The tables below provide a summary of probable violations discovered and compliance actions taken by the CPUC against all gas pipeline operators and includes transmission, distribution, and gathering infrastructure. These data are reported to PHMSA annually as part of the CPUC’s annual pipeline safety program certification to PHMSA. The source is this data is: http://primis.phmsa.dot.gov/comm/reports/stenforce/StateEnfDet_state_CA.html?nocache=4284#_TP_1_tab_2

This table provides a summary of probable violations identified and corrected during each year. Probable violations are alleged non-compliances with any state or federal pipeline safety regulations. Although state enforcement procedures vary, operators are provided an opportunity to respond to these alleged non-compliances and defend their actions as part of resolving each case. Separate tables are provided for hazardous liquid and gas pipeline oversight.

Number Found During Year: The number of new probable violations identified during the calendar year through inspections, investigations, and other means.

Number Submitted for DOT Action: The number of probable violations that are referred to PHMSA for Federal enforcement. Compliance actions may be referred to PHMSA in situations where the State pipeline safety program is not certified to take enforcement action on certain intrastate pipelines. For example, some States do not have enforcement authority of municipal pipeline systems. Furthermore, some State pipeline safety programs are authorized by PHMSA to inspect interstate pipelines on PHMSA's behalf as Interstate Agents. In these situations, any probable violations identified by Interstate Agents must be referred to PHMSA for enforcement.

Number Corrected During Year: The number of probable violations that were satisfactorily corrected during the calendar year. These could be violations identified in the current year as well as violations that were carried over from previous years. Violations are satisfactorily resolved when the operator provides evidence and satisfies the agency that the non-compliances have been properly addressed and corrected.

A compliance action is an action or series of sequential actions taken to enforce Federal or State pipeline regulations. One compliance action can cover multiple probable violations. A compliance action may take the form of a letter warning of future penalties for continued violation, an administratively imposed monetary sanction or order directing compliance with the regulations, an order directing corrective action under hazardous conditions, a show-cause order, a criminal sanction, a court injunction, or a similar formal action. This table provides the number of compliance actions taken by the State agency in each year. It also provides the number and amount of civil penalties that were assessed each year to pipeline operators and the number and amount of civil penalties that were collected each year from operators. Because there are occasions where a civil penalty is assessed in one year but not collected until a following year, the amount assessed and collected in a given year may not always be the same.

VALVES

Gas flow to Line 132 was not stopped until more than an hour and a half after the September 9th explosion. PG&E dispatched a crew at 6:45 p.m. to isolate the ruptured pipe section by closing the nearest mainline valves. The upstream valve (MP 38.49) was closed at about 7:20 p.m. and the downstream valve at Healy Station (MP 40.05) was closed at about 7:40 p.m. Once the ruptured section was isolated and the gas flow was stopped, the resulting fire from the ruptured line self-extinguished. Later that evening, PG&E isolated the natural gas distribution system serving residences in the area, and within a minute of stopping the gas flow at about 11:30 p.m., fires from escaping natural gas at damaged houses went out.

The flows to Line 132 were controlled by manual valves which are hand-operated by wheel and gear assembly or by a wrench with an indicator to show whether it is open or closed. Many have questioned whether other technologies such as automatic or remotely-controlled valves should be in greater use so that gas flows can be interrupted more quickly.

Remotely-controlled and automatic valves are also used for gas transmission pipelines. Remotely-controlled valves are generally operated by personnel stationed at a control center. PG&E’s San Francisco Gas Control Center uses the Supervisory Control and Data Acquisition (SCADA) system to monitor operating information on the gas system for San Bruno. PG&E reports that:

Sensors along our natural-gas system feed information about pressure, flow rate and other operating information to SCADA where it is used by the Gas Control Center operators. Operators see both graphical and tabular information on their computer screens and use this information and available tools, to monitor compressor stations and pipelines along our natural-gas system. Additionally, the Gas Control Center operators are able to adjust pressure and flow rate within the system, as needed.

PG&E was able to detect pressure changes in Line 132 from SCADA but could not stop the flow of gas due to a lack of remotely-controlled valves which necessitated the dispatch of a crew to manually stop the gas flow.

Automatic valves are also used in some instances and have control programs which trigger a closure based on specified changes in pipeline conditions.

PG&E reports that its transmission pipeline system has tens of thousands of valves. Approximately 2,600 are block valves designed to sectionalize transmission pipelines. Of these, about 200 are remotely or automatically controlled. They further report that the cost to replace a manual vale with an automatic valve and the accompanying control mechanisms is estimated to average $500,000 per valve and can range from $150,000 to $1 million for a 24-inch valve.

 TRANSMISSION LINE MAPPING

Maps of all gas transmission lines are available through the National Pipeline Mapping System. Through this web-based system a viewer can view transmission lines one county at a time. The maps are available at: https://www.npms.phmsa.dot.gov/PublicViewer/. Since the September 9th explosion, PG&E has established a website which has two additional views available. Individual customers can log-in to their PG&E account and view, with great detail, all lines in the immediate vicinity of their service-address as well as “segments that have been identified for engineering analysis and future work as part of PG&E’s ongoing preventive maintenance process.”

PG&E also has a map viewer available to the general public, listed by city, which is very similar to the National Pipeline Mapping System. Finally, PG&E has made available maps of its current “Top 100” segments which form the basis of future workplans and monitoring.

PG&E’s Top 100

PG&E inventories approximately 20,000 transmission pipeline segments and evaluates them against several criteria including: 

• potential for third-party damage;
• potential for corrosion;
• potential for ground movement; and
• physical design and characteristics.

The data is collected, catalogued and used to help plan and prioritize future work resulting in the top 100 list of pipeline segments of lines “to help inform future work plans. As conditions change from year to year, PG&E reevaluates the segments included on the list. There are a range of actions PG&E may take for the segments identified on the list. For example, if a segment is on the list due to a high level of construction activity in the area, PG&E might enhance the physical markings of the lines and conduct outreach to help avoid accidental dig-ins. In other cases, PG&E may increase its monitoring or propose to rebuild the line sometime in the future.” The list changes on a regular basis and is available at PG&E’s mapping viewer.

Line 132 was not on PG&E’s Top 100 List.

EMERGENCY PLANNING

Federal law (49 CFR 192.615) currently requires each gas transmission line operator to have an emergency plan in place with specified components. Pipeline operators are required to establish written procedures to minimize hazards resulting from pipeline emergencies. They must establish methods of receiving notifications of emergencies, and communicating with emergency responders. Operators must also establish appropriate procedures to ensure a prompt and effective response to various types of pipeline emergencies. Operators must train their personnel on the emergency requirements, establish liaison with emergency responders and public officials, and periodically perform exercises to ensure that emergency response procedures and training are effective.

Neither state nor federal regulations specifically require a gas transmission pipeline operator to provide maps of its gas transmission pipelines to first responders or any other local agency. Specifically, 49 CFR 192.615, in part, provides that:

(c) Each operator shall establish and maintain liaison with appropriate fire, police, and other public officials to:

1. Learn the responsibility and resources of each government organization that may respond to a gas pipeline emergency;
2. Acquaint the officials with the operator's ability in responding to a gas pipeline emergency;
3. Identify the types of gas pipeline emergencies of which the operator notifies the officials; and
4. Plan how the operator and officials can engage in mutual assistance to minimize hazards to life or property.

FISCAL/BUDGETING

Funding for the maintenance, inspection and replacement of pipelines by PG&E and other gas utilities is under the jurisdiction of the CPUC. Two public proceedings concern this funding – the general rate case (GRC) and the gas accord. Funds are requested by the regulated entity for specified categories including, for PG&E, “Pipeline Safety & Reliability” and “Pipeline Integrity Management” and the utility presents information on projects for which it is requesting revenue. The CPUC reviews the utility’s request and considers comments from interested third parties in a public proceeding to make a final determination or approve a settlement among the parties. Once the utility has its revenue set (which comes from rates), it can make decisions that it believes are appropriate for the safety and reliability of its system, including switching out one project for another. 

This funding process is commonly referred to as “rate forecasting” – the CPUC adopts a revenue requirement and the utility has the discretion to determine how best to use that revenue to operate its system. The utilities do not need permission from the CPUC to shift funds between funding categories. In very limited circumstances, the CPUC has approved a specific funding amount for a specific type of work (tree trimming for example). In that case, those funds can only be used for that purpose and cannot be shifted elsewhere.

What stands out in this process is a lone assessment by the utility as to what it determines is necessary to maintain and inspect its capital infrastructure. It is not apparent that the CPUC or interested third parties consider whether the utility is allocating a sufficient level of funding to achieve and maintain a safe transmission system. Moreover, when the next rate case or gas accord is presented by the utility; neither the CPUC nor interested parties appear to look back in an effort to determine whether the forecasted funding levels were utilized for the specified purpose. Finally, the CPUC often relies on “settlement agreements” between stakeholders such as the Division of Ratepayer Advocates (DRA) and The Utility Ratepayers Network (TURN) to finalize funding levels.

Last year PG&E filed an application with the CPUC proposing its funding for gas transmission and storage for the years 2011-2014 which is under review by the CPUC commonly referred to as “Gas Accord V.” A proposed settlement was filed in connection with a joint motion to adopt the settlement on August 20, 2010. TURN and DRA are parties to the proposed settlement. The settlement recommends a one-way balancing account, which protects ratepayers by requiring unspent funds to be returned to ratepayers, but allows PG&E to spend additional funds at their discretion. The revenue requirement in the proposed settlement is shown below.
 

 On Sept. 15, 2010, the administrative law judge for the proceeding issued a ruling requesting that the parties (approximately 20) file comments by September 20th on whether the proposed settlement is adequate in light of the pipeline safety, integrity, and reliability concerns raised by the San Bruno explosion. A capital expenditure plan was included in the proposed settlement showing amounts budgeted for various types of projects or major work including:

Pipeline Safety and Reliability includes capital costs of replacing high-risk, high-consequence pipeline segments identified by PG&E’s Pipeline Risk Management Program and expenditures necessary to comply with construction, maintenance, and operation of gas transmission pipelines. These amounts are approximately $0.5 million/year below the amount requested by PG&E in its application (pre-settlement position).

Pipeline Integrity Management includes capital costs of upgrading pipelines enabling PG&E to inspect them with an in-line inspection tool and to mitigate any damage found. These amounts are the same PG&E requested in its application (pre-settlement position). In its application, PG&E also identified 31.9 miles of Line #132 to be inspected by 2013 and included the same replacement project proposed in its prior rate case.

PG&E also has a Pipeline Integrity Management Program to assess and manage the integrity of all gas transmission pipelines whose potential impact encompasses High Consequence Areas (HCA). Currently, 1,020 miles of PG&E’s pipelines fall under the program. Under the proposed settlement, the revenue for this program would be:

LIABILITY

Historically the state’s utilities have secured insurance policies that have been sufficient to cover third party claims for damage and litigation losses as a result of major incidents such as wildfires. The costs of policies have always been considered by the CPUC to be a part of the normal cost of doing business and therefore have been borne by ratepayers. The utilities now report an insurance crisis where policy limits/coverages are declining and premiums are increasing. As a result the three major utilities have filed a joint petition with the CPUC seeking guaranteed rate recovery for uninsured costs resulting from wildfires in advance of any actual loss. This filing predates the San Bruno explosion.

The utilities argue that the CPUC should authorize the recovery because:

• Such recovery essentially preserves the status quo because it provides for the same ratemaking treatment for uninsured costs as the CPUC traditionally has applied to the costs of insurance against those costs;
• Rate recovery is consistent with the CPUC’s constitutional and statutory obligation to allow utilities a reasonable opportunity to recover their costs of providing public utility service;
• Rate recovery of the uninsured costs of wildfire parallels the rate treatment of the costs of other natural disasters, such as earthquakes, tornados, or major storms; and
• Assurance of rate recovery is needed to protect the utility’s financial integrity.

The protests against this filing include DRA and TURN. The issues they have raised include:

• Ratepayers should not pay for premium increases that result from an insurer’s negative assessment of a utility’s failure to adequately maintain utility infrastructure;
• In order to ensure that the utilities have the property incentive to safety maintain their system as well as defend against frivolous claims, shareholders should be required to pay for a percentage of all expenditures recorded above policy limits; and
• Utilities should not be permitted to secure wildfire related expenditures incurred as a result of damages caused by a utilities’ gross negligence, violation of a general order or violation of state or federal law.

# # #

Attachment 1

PIPELINE CORROSION: PREVENTION & INSPECTION

PG&E has provided the following summary of the process of corrosion of pipelines, the techniques used to prevent pipeline corrosion, and inspection processes and timelines to detect corrosion and leaks.
 

Pipeline Corrosion Process

Almost all natural gas transmission pipelines are made of steel. Unless protected, the exterior surfaces of buried steel pipelines will corrode. The exterior surfaces of above ground steel piping can corrode as well, if exposed to certain conditions. Under specific conditions the internal surfaces of natural gas steel pipelines can corrode. If the corrosion of natural gas pipelines is not controlled, gas leaks will occur. Severe corrosion of transmission pipelines can result in catastrophic failure.

In general, the presence of water is required for the corrosion of steel. Buried pipe as well as above ground pipe is exposed to moisture in the environment. Chemical elements in the soil and the air dissolve in the water to produce an electrolyte – a substance that breaks into individual ions becoming electrically active when dissolved. The ions present in the electrolyte combine with the iron in steel to form corrosion. Electrochemistry is the subject of whole courses for pipeline engineers. For our purposes, it is sufficient to understand that the electrolytic corrosion process always involves a cathode (with negative voltage) and an anode (with positive voltage). The cathode is the cell or portion of the pipeline protected from corrosion while the anode corrodes. 

Prevention of Buried Pipeline Corrosion

Federal regulations (49 CFR 192.455) require that the external surfaces of buried pipelines be protected from corrosion. The primary means for protecting buried pipelines from corrosion is the application of an effective pipeline coating. The secondary means prescribed in the code for protecting buried pipelines is the application of cathodic protection (CP) systems. The proper application of pipeline coatings and CP systems, working in concert, can virtually eliminate external corrosion of pipelines. Pipeline coatings prevent water from coming in contact with the surface of the pipeline while CP systems protect those areas of the pipeline where water has penetrated the coating.

Cathodic Protection of Pipelines

Cathodic protection systems use direct current (DC) to manipulate the corrosion process. Long rods made of special alloys, known as sacrificial anodes, are installed deep into the ground near the pipeline and DC is applied to both the pipeline and the anodes in such a manner as to maintain the pipelines as the cathode (protected from the corrosion process) while the anode is allowed to corrode. If applied correctly, CP systems cause all corrosion to take place at sacrificial anode rather than on the pipeline.

The DC used for CP is usually supplied by rectifiers that convert the alternating current (AC) available in the power grid to the DC needed for CP. In order to be effective rectifiers must be in continuous operation. CP systems that use rectifiers are referred to as impressed current type cathodic protection systems. These CP systems are usually installed on large diameter pipelines like transmission lines.

For small diameter distribution or service lines, zinc or magnesium anodes can be connected directly to small diameter distribution pipelines to provide cathodic protection current. This type of CP is referred as a galvanic CP system. Galvanic CP systems do not use rectifiers.

Pipe-to-soil Potential Measurement

Adequate levels of cathodic protection is demonstrated by taking a measurement called a pipe-to-soil potential. Pipe-to-soil potentials are referenced to a standard copper copper-sulfate reference electrode. A measured pipe-to-soil potential that is at least as negative as -850 millivolts is required to demonstrate that sufficient cathodic protection current is being applied to a pipeline (49 CFR 192.463).

Inspection of Buried Pipelines

It is not practical to routinely dig up buried pipelines to inspect for exterior corrosion. The federal code requires the inspection of buried piping for corrosion damage whenever the pipe is excavated for repairs, construction or other reasons (49 CFR 192.459). For PG&E, records of such visual pipeline inspections are recorded on A-Forms and maintained in the local division maintenance supervisor’s office. However, only a small fraction of the entire length of a pipeline can be inspected in this manner each year.

Cathodic Protection Maintenance

Because it is not practical to routinely inspect buried pipelines for corrosion and because it is understood that properly applied CP can eliminate pipeline corrosion, the proper maintenance of CP systems is required by the federal code (49 CFR 192.465). The code requires that CP rectifiers be inspected for proper operation six times per year. The inspection consists of measuring the output DC voltage and current at intervals of about 60 days. The code prescribes that pipe-to-soil potentials be measured annually. For PG&E’s transmission lines, annual pipe-to-soil potential measurements are recorded in the pipeline management (PLM) computer program.

Inspection of Above Ground Piping

Above ground portions of both transmission and distribution piping must be inspected for corrosion at least once every three years (49 CFR 192.481). Records of above ground pipeline inspections are maintained in PLM for transmission pipelines and in the local maintenance supervisor’s office for local transmission pipelines.

Inspection for Internal Pipeline Corrosion

Federal code (49 CFR 192.475) requires that, whenever a transmission pipeline is cut for replacement or for repair work, the internal surfaces of the pipeline must be inspected for internal corrosion. Records of internal pipeline inspections are maintained in the office of the local maintenance supervisor. Again, however, this type of inspection is very infrequent.

Pipeline Patrolling

The federal code (49 CFR 192.705) requires periodic patrolling of transmission pipelines. The frequency that patrols are conducted on transmission pipelines varies by location. Patrolling frequencies vary from once per year to quarterly. The highest patrol frequencies generally apply to locations with the highest population densities. Walking patrols of transmission pipelines are conducted to look for indications of pipeline leaks, missing pipeline markers, construction activity and other factors that may threaten the pipeline. Since natural gas leaks tend to kill vegetation near the leak location, aerial patrols are regularly conducted to look for signs of dead vegetation as well as any activity such as on-going construction that may threaten the pipeline. Records of pipeline patrols are maintained in the local maintenance supervisor’s office.

Leak Survey

The federal code (49 CFR 192.706) requires annual leak surveys of transmission pipelines. These leak surveys are conducted using combustible gas indicators. Newer leak detection instrumentation employing infrared or laser technology is also being used. In the usual case, a leak surveyor walks along the surface of the ground above the pipeline using leak detection instruments to conduct a leak survey. Leaks that are found are graded according to the volume of the leak and the threat it poses to the public. The highest priority leaks are repaired promptly. Small leaks that pose no threat to the public are monitored. Leak survey records are maintained in the office of the local maintenance supervisor.

Regulator and Pressure Limiting Station Inspection

The federal code (49 CFR 192.739) requires that all pressure limiting and regulating devices be inspected annually. This includes relief valves, regulators and pressure limiting valves. The records of these inspections are located in PLM computer program.

Emergency Valve Inspection

The federal code (49 CFR 192.745) requires annual inspection and operation of all valves that are required to isolate portions of the transmission pipeline during an emergency. The valve is given a visual inspection, the valve mechanism is greased and the valve is at least partially closed to assure that it will close during an emergency. The records for these valve inspections are found in PLM for transmission pipelines. Local distribution emergency valves inspection records are located in the office of the local maintenance supervisor.

Pipeline Hydrostatic Testing

Pressure testing of transmission pipelines in HCA’s involves using natural gas, air, inert gas or water to pressurize the pipeline above its maximum operating pressure (MAOP) by at least 50%.

In-line Inspection

In-line inspection of transmission pipelines involves the use of devices referred to as smart pigs that travel inside the pipeline to perform testing that identifies defects in the pipeline walls.

External Corrosion Direct Assessment

Various testing techniques such as close interval potential surveys, PCM surveys and DVGG surveys are used to assess the condition of the pipeline coating and cathodic protection levels. This testing is performed on the surface of the ground above the pipeline. Excavations to allow visual inspection of the external surface of the pipeline are used to confirm the results of the survey mentioned above are also performed. This has been called the “poking ground” method in some media reports.

Internal Corrosion Direct Assessment

Internal corrosion of transmission pipelines only occurs at locations where liquids are likely. Low places in the pipeline are identified and an analysis of the pipeline gas flow characteristics are used to identify potential locations where pipeline liquids are might accumulate. Testing using in-line inspection tools, ultrasonic wall thickness testing or guided wave testing is used to determine if internal corrosion exists at the location. If internal corrosion is detected additional tests are performed to determine, if repairs are required.

Pigging Pipelines

Natural transmission pipelines contain large volumes of natural gas at high pressure. The high pressure gas contained within the pipelines exerts high stresses on the steel walls of the pipeline. It is important that any damage to the pipeline walls that may lead to failure be identified and corrected.

One of the methods employed to locate damage to the walls of a pipeline is commonly referred to as “smart pigging” or in-line inspection (ILI). Pigging a pipeline involves inserting a devise into the pipeline which uses the gas flow to propel it along the length of a portion of the pipeline. Devices referred to as “smart pigs” contain instrumentation and data recording equipment that allow the pig to measure a variety of characteristics of the pipeline wall as the ILI tool travels down the pipeline.

To assess a pipeline using a pig, the pipe must be equipped with a launching point, a receiving point, and the line or line segment itself must be free of sharp bends, diameter changes or certain pipeline characteristics that would impede the passage of the pig, including compressors, regulators, plug valves, large changes in pipe diameter, bends that are too sharp and any obstructions protruding into the pipeline. Most older pipelines were not constructed to accommodate pigs; such lines are said to be not “pigable.” Making an old pipeline pigable can be very expensive and can require numerous shut downs of the pipeline.

The link below shows a pig inserted into a pipeline.
http://en.wikipedia.org/wiki/File:PipelinePIG.jpg

There are several types of pipeline pigs. Various types of cleaning pigs can be used to remove liquids and other debris from the pipeline in preparation for the use of smart pigs. Geometry pigs are used to measure the shape of the pipeline walls. Geometry pigs detect dents and pipeline out of roundness. Magnetic flux leakage (MFL) pigs are used to identify wall loss locations referred to as anomalies in the pipeline wall. MFL pigs contain instrumentation that induce a magnetic flux in the pipeline wall. Instrumentation mounted on the MFL pig measure any variation in the magnetic flux levels as the pig travels down the pipeline. Sophisticated computer programs along with analysis performed by technical experts is used to determine the size, shape and location of pipe wall anomalies. The data provided by smart pigs is used to identify pipeline wall anomalies that may pose a threat to the integrity of the pipeline. Using the smart pig data PG&E engineers decide if more investigation is required. All serious damage to the pipeline wall is repaired.

The link below describes the various types of pipeline pigs available.
http://www.rigzone.com/training/insight.asp?insight_id=310&c_id=19

In 2003 federal regulations (CFR 192 subpart O) were enacted requiring PG&E and other pipeline operators to implement pipeline integrity management programs for pipelines located in high consequence areas (HCA’s). HCA’s are areas of high population density. As part of the pipeline integrity program federal regulations (CFR 192.921) prescribe pigging pipelines as one of the three pipeline testing methods that are to be used to develop a baseline assessment plan (BAP): (1) internal or in-line inspection (ILI), (2) pressure testing using water, inert gas or some other medium, (3) direct assessment. The utility should select one or more methods depending on the threats to which the subject segment is susceptible.

Pipeline pigging services are provided by several different vendors. Some of the pig vendors PG&E has used are GE/PII, NDT and Intratech. ILI vendors provide the tools, collect the pipeline data and assist in interpreting the data their smart pigs obtain. PG&E engineers use the pig data to assess the pipeline integrity, identify locations for conducting direct inspections of pipeline wall anomalies found.

Helicopter Based Leak Surveys

PG&E has not used helicopters routinely to perform transmission pipeline inspections in the past. The routine aerial patrols currently conducted by PG&E are performed by fixed wing aircraft. Following the San Bruno incident the CPUC ordered PG&E to conduct a leak survey of its entire transmission pipeline system within 30 days. It is impractical to perform a complete leak survey of PG&E's transmission pipeline in 30 days using PG&E employees on foot. A contractor was engaged to conduct the 30 day leak survey of the transmission system. This contractor uses a laser based technology to locate natural gas pipeline leaks. The contractor's laser based leak survey equipment is mounted on a helicopter. It is not yet known, if PG&E will employ this technology to conduct transmission pipeline leak surveys in the future.

The contractor conducting the leak survey work to comply with the CPUC order uses mid-infrared laser technology to detect pipeline leaks. The leak detection equipment is mounted on a helicopter. As the helicopter flies over the pipeline a infrared laser is directed onto the ground above the pipeline. Reflected light from the ground is collected by a sensor mounted in the helicopter. Leaking natural gas from the pipelines creates a plume above the ground surface over the pipeline. The natural gas plume absorbs some of the laser light emitted from the helicopter diminishing the amount of light reflected back to the sensor mount on the helicopter. GPS technology is used to identify the location of the leak.

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