NATIONAL TRANSPORTATION SAFETY BOARD
PIPELINE SAFETY HEARING
Inspection and Integrity Verification
Conference Center and Board Room
National Transportation Safety Board
Washington, D.C.
Wednesday, November 15, 2000
9:30 a.m.
Day 1 Transcript
Day 2 Transcript
Board Members Present:
JIM HALL, Chairman
CAROL CARMODY
JOHN J. GOGLIA
JOHN HAMMERSCHMIDT
GEORGE W. BLACK, JR.
Board Staff Present:
BOB CHIPKEVICH
JOSEPH KRIS
Hearing Officer
CLIFF ZIMMERMAN
Pipeline Accident Investigator and IIC
ROD DYCK, Associate Director
Pipeline Division
JIM WILDEY, Chief
Materials Laboratory
Office of Research Engineering
A G E N D A
AGENDA ITEM: PAGE:
Opening Statement 3
Chairman Jim Hall
National Transportation Safety Board
Honorable James Oberstar 9
8th Congressional District
State of Minnesota
Overview 37
National Transportation Safety Board
Staff
Remarks 24
Honorable Kelley S. Coyner, Administrator
Research and Special Programs Administration
Stacey Gerard, Associate Administrator
Pipeline Safety
Panels:
In-Line Inspection Service 49
Tom Sawyer, PII North America, Inc.
Ravi Krishnamurthy, PII North America, Inc.
John Parsons, Tuboscope
Afternoon Session
Integrity Assessment 123
H. Noel Duckworth, Consultant
Dr. John F. Kiefner, Kiefner & Associates
Pipeline Operators 168
Vic Yarborough, Colonial Pipeline Company
Rich Turley, PE, Marathon Ashland PipeLine
LLC
J. Andrew Drake, PE, Duke Energy
Elden R. Johnson, Alyeska Pipeline Service Company
Researchers 235
Dr. Tom Bubenik, Battelle
Dr. Brian Leis, Battelle
Al Crouch, Southwest Research Institute
P R O C E E D I N G S
9:36 a.m.
CHAIRMAN HALL: Before I gavel this hearing to order, I would like to make a brief announcement of welcome to our guests to the National Transportation Safety Board. You are -- we're very pleased to welcome you to our new Board Room.
There is an important announcement I would like to make in regard to any possible emergency evacuation of this room. In the event of an emergency, such as a fire, the building alarm system will activate, and a voice message will instruct persons to vacate the building.
You should proceed to the nearest exit. There are emergency exits up front, to the left and to the right of this platform and in the rear of the room.
Also, for your convenience, restrooms and telephones are located in the foyer on the left as you exit the room.
If there is anything that either myself or the other members of the National Transportation Safety Board can do to assist you while you are visiting with us, please do not hesitate to ask.
I'd like to open this Pipeline SafetyHearing, and I would like to note the excellent attendance that we have this morning, and I am very grateful for that, as we attempt to put attention on an extremely important safety issue that does not receive as much attention as many of the other modes of transportation that the Board is involved in.
Because of the importance the Board places on this critical safety issue, all five Board Members will participate in this hearing over the next two days. The safe transportation of natural gas and liquid petroleum products is vital to meeting the energy needs of every community in our country. Pipelines today provide a vital transportation service to America.
Over 2.1 million miles of pipelines criss-cross our great country, many of them running under our cities, our towns, our neighborhoods, and our playgrounds.
Last year, pipelines delivered over 13 billion barrels, 558 billion gallons, of petroleum products, such as crude oil, gasoline, diesel fuel, and heating oil, to customers all across the nation.
In addition, the number of customers using natural gas in this country has exceeded 60 million, and approximately 70 percent of new homes now havenatural gas service.
As many of you know, the National Transportation Safety Board has been the eyes and ears of the American people at accident sites for over three decades, and in those 30 years, we have seen too many tragedies or near tragedies that were all caused by the same fundamental problems.
We have scheduled this two-day Pipeline Safety Hearing to address two of those problems. Today, we will focus on Pipeline Inspection and Integrity Verification. Tomorrow, we will examine Leak Detection and Response.
The Safety Board is currently investigating six pipeline accidents that have occurred since last year, where time-dependent defects are being examined. Those accidents occurred in Knoxville, Tennessee, Bellingham, Washington, in which three young men were tragically killed, Winchester, Kentucky, Greenville, Texas, Chalk Point, Maryland, and Carlsbad, New Mexico, in which 12 people died.
Many of the hazardous liquid and natural gas transmission pipelines in our country are 30 to 50 years old. The Liquid Products Pipeline that ruptured in Bellingham, Washington, on June 10th, 1999, was constructed in 1966. The Natural Gas Pipeline thatruptured near Carlsbad, New Mexico, on August 19th, 2000, was constructed in the early 1950s.
Although age alone does not indicate that a pipeline is unsafe, it does make determining the integrity of pipelines increasingly important.
13 years ago, the Safety Board recommended that the Research and Special Programs Administration, referred to in this town as RSPA, require pipeline operators to periodically inspect their pipelines to identify time-dependent defects that may prohibit safe operations.
Just last week, RSPA issued a Final Rule to require pipeline operators who operate 500 or more miles of hazardous liquid pipeline to establish an integrity management program for high-consequence areas.
According to RSPA, this rule will cover 87 percent of all hazardous liquid pipelines. We will be examining this Final Rule closely in the next two days, but it appears to be the first step to ensuring that pipelines are properly inspected and tested.
The lack of timely recognition of a pipeline rupture is another recurring problem we see repeatedly in our investigations. Following a pipeline rupture, controllers often continue to operate a pipeline orrestart a system that had shut down rather than promptly shutting the system down and isolating the leak. This failure to recognize a problem in a timely manner can significantly add to the accident severity.
Over the next two days, we will be examining the technology available to address these important safety issues, looking at the limitations of the current technology and actions that are needed to identify time-dependent pipeline defects before they reach critical size and to recognize promptly when a failure does occur.
Before I begin, I want to thank each of the panelists who have agreed to participate in our hearing. I also want to thank Tuboscope and PII North America for bringing their in-line inspection tools to our hearing, so that all of us can better understand how they work.
The Tuboscope device is a model of an in-line tool or smart pig. It is located in the lobby just outside the Conference Center. The PII tool will be arriving later this morning. It is used to inspect 12-inch diameter pipelines.
I'm told that it is about 17 feet long and weighs approximately 1200 pounds. So, rather than bring it into this building, we'll display it on theplaza on the floor above us. You'll be able to see it just outside the building at the top of the escalator.
I hope that you'll take the opportunity to examine both of these items in the next few days.
Just a word of caution. The PII tool has a strong magnetic field. Therefore, if you have a pace-maker, you should not get close to the device.
Now, before we begin with our scheduled witnesses, it gives me great pleasure to introduce one of the truly exceptional individuals in the United States Congress today, and a true leader in the field of transportation safety.
Congressman James Oberstar has worked on Capitol Hill since 1963. 26 years ago, he was elected as the representative of the 8th Congressional District of Minnesota, and I'm happy to say he was re-elected again last week without needing a recount.
From 1989 to 1995, he chaired the Aviation Subcommittee. Currently, he is the Ranking Member of the Transportation and Infrastructure Committee, and he serves as an ex-officio member of the Subcommittees on Aviation, Coast Guard and Maritime Transportation, Public Building and Economic Development, Railroads, Surface Transportation, and Water Resources and Environment.
Over the years, Congressman Oberstar has worked ceaselessly to improve the safety of the nation's transportation system. Last month, Congressman Oberstar introduced the Pipeline Safety Act of 2000, legislation to improve the safe operation of hazardous liquid and natural gas pipelines, each kind of pipeline involved in the Bellingham, Washington, and Carlsbad, New Mexico, tragedies.
Congressman Oberstar has been a friend and supporter of the NTSB and its mission, and his presence here today is further testament of his commitment to improve the safety of our nation's pipeline infrastructure.
Ladies and gentlemen, I welcome to the podium Congressman Jim Oberstar.
(Applause)
CONGRESSMAN OBERSTAR: It's on? There it is.
Thank you very much, Mr. Chairman, for that very warm introduction, and, no, we don't need a recount in my district. I got 73 percent of the vote.
In fact, the second-highest vote total in the whole country.
More importantly, I thank you and the members of the Board for again pursuing the role that the NTSB serves so exceedingly well as the indisputableauthoritative, objective guardian of safety in transportation.
The recommendations of this Board on all forms of transportation over the years of its existence, since 1969, have saved countless lives, made transportation safer, made America a better place, but your continued vigilance is necessary because safety is only a matter of seconds. It is a matter of measuring risk, and we can never measure it too carefully or too closely.
I thank you for continuing this extraordinary service of the Board.
On Tuesday, July 8, 1986, a quiet neighborhood in Moundsview, Minnesota, was roused from its slumber when a wall of fire roared down that street. A mother and her six-year old daughter stepped out the front door shocked by the noise, frightened obviously, opened their door and were incinerated.
Mailboxes melted. Trees wilted. The road buckled. A third woman was severely injured. Quarter of a million dollars in property damage was caused. The origin of the fire, a hazardous liquid pipeline running through this neighborhood.
The neighborhood had overgrown the pipeline. It had once been a rural area, now suburban, and in theensuing investigation, it was found that cathodic protection on that pipeline had failed and had gone undetected, and the pipeline had rusted through, and the unleaded gasoline going through that pipeline leaked over an extensive period of time, no one is really sure how long, until it reached a critical mass in that street area, and the fumes rose to the surface as an automobile was driving along that street. A loose exhaust pipe caused a spark, and the road exploded.
I was Chair of the Investigations and Oversight Subcommittee of the House Public Works Committee at the time. We were preparing hearings on the condition of the nation's pipelines. We intensified our work, Mr. Chairman, when that tragedy occurred, and held a hearing in 1987.
We asked the General Accounting Office, in preparation for the hearing, to assess its evaluation -- to reassess its evaluation of OPS, Office of Pipeline Safety, operations. It was clear that OPS did not have sufficient manpower to carry out inspections, to carry them out at appropriate intervals.
The current regulations were not adequate. The federal/state partnership in pipeline inspections was not working. There were factors, such as one callsystems, automatic shut-off valves, clear path, other technologies for response to tragedies, that were grossly inadequate or non-existent. That was 1987.
Our subcommittee made recommendations for the legislative committees to act. They did act to increase the number of inspectors, but an unwilling Administration would not go further with more requirements in either the states or the Office of Pipeline Safety.
In the decade since then, more than 2500 accidents have occurred on the nation's pipelines. We concluded the last session of Congress or virtually have, appropriations aren't completed, but on this issue, there was no agreement on a pipeline safety bill.
We passed -- we were at the point of moving a bill in our committee when the Senate moved theirs, and the advocates for a weaker bill said, "Don't let the perfect be the enemy of the good." Well, that phrase was first uttered by Voltare. "Ne pas laissez le parfait etre l'ennemi de bon". Don't let the good be the enemy of the better.
But Voltare went further and said, "A la vivant, il faut. A la mort, il faut la vrai". To the living, we owe respect. To the dead, we owe the truth. The dead in this case are the innocent victims of pipeline tragedies, and the most recent being those in Bellingham, Washington, Carlsbad, New Mexico, as you've cited, Mr. Chairman.
These are not just numbers, these tragedies, these statistics. These are human beings, whose lives are wrenched, ripped apart, torn asunder. Marlene Robinson, the mother of one of the victims of Bellingham, told a group of members of Congress about her son. He had just graduated from high school. He didn't go off on a party with his friends. He didn't go drinking or carousing. He took his fly rod and went fishing.
While he was fishing, celebrating his graduation, a wall of fumes roared down that river and succumbed him and then exploded and burned three others -- two others. Excuse me. The cause, a ruptured pipeline, gasoline pouring into the creek, fumes roaring ahead of it. "A la mort, il faut la vrai". To the dead we owe the truth, and the truth is that we can do better, and we have to do better on the nation's --monitoring the nation's pipelines.
We have 2.2 million miles of pipelines, carry 617 million ton miles of oil and refined products, 20 trillion cubic feet of natural gas every year, and itcontinues to grow.
Pipeline mileage has grown 10 percent in the last 10 years, but it's growing at the very same time that the nation's suburbanization continues to bring more families near more pipelines.
But as the industry has grown, regrettably, our hearings 13 years ago, this Board's recommendations and investigations, General Accounting Office, congressional committee hearings have shown that safety has declined.
In the last 10 years, the decade of the '90s, there were 2241 major pipeline accidents resulting in death, serious injury or substantial property damage. Those explosions killed 226 people, caused $700 million of property damage and damage to environment, and the General Accounting Office reports that the rate of accidents is increasing four percent a year.
We are also confronted with a very aging pipeline system. 24 percent of gas pipelines are now more than 50 years old. The section of pipeline inspected and involved in the Carlsbad tragedy was almost 50 years old and suffered substantial internal corrosion, and this Board found that it had never been properly inspected.
Congress and the Board have been aware of theunacceptable state of pipeline safety for many years, have made numerous recommendations, and have given the Office of Pipeline Safety at the Department of Transportation guidance and the steps needed to be taken.
Regrettably, under both Republican and Democratic Administrations, OPS has not been responsive until just recently. GAO found that the Office of Pipeline Safety had failed to implement 22 statutory directives for regulations and studies. 12 of these provisions go back to 1992 or earlier.
The Office of Pipeline Safety has had the lowest rate of any agency at DOT for compliance with NTSB recommendations.
In addition, the General Accounting Office has challenged the OPS policy of reduced reliance on enforcement fines. These new actions by OPS are encouraging, but there's a long way to go.
The Administration -- on November 3rd, the Office of Pipeline Safety issued an important pipeline safety rule, and the White House issued a presidential directive for more safety measures. They're encouraging, but those are only first steps.
If the past is prologue, progress will be made only if the public, the Congress, this Board stayon course with DOT and with the OPS and keep this issue publicly visible and insist that actions be taken.
The Final Rule issued by OPS deals with one segment of the industry, the larger liquid pipelines. The rule requires these operators to inspect and promptly repair pipelines in populated as well as environmentally-sensitive areas, and to take systematic steps to detect and repair leaks. Those are important.
Mandatory inspections will prevent future tragedies. The need for regular inspections is under-scored by the age of our pipeline system.
The company responsible for the Carlsbad pipeline tragedy never conducted an internal inspection of the pipeline involved in the explosion. Properly-conducted inspection would very likely have uncovered the corrosion problems before they led to a tragedy.
If you don't require pipeline inspections, there will be more tragedies. We must not have another Bellingham, another Carlsbad, another Edison, or another Moundsview.
In 1987, this Board recommended that OPS require periodic inspections. In 1992, Congress passed legislation that directed OPS to adopt regulations. It didn't by law enact them, directed the agency to adopt regulations requiring inspections by 1995.
On November 3rd of this year, 13 years after this Board's initial recommendation for periodic inspections, eight years after the statutory mandate, the Office of Pipeline Safety has finally issued a rule imposing pipeline inspection requirements for one segment of the industry.
Now, there are many desirable provisions. Requires periodic inspections, at least one every five years, that they be conducted by internal inspection tools or pressure tests. Inspection can be conducted by other methods, if the operator demonstrates that the alternative method produces an equivalent under-standing of the pipeline.
They have to notify OPS nine months in advance of making a change, and the rule establishes schedules for repairs of defects identified in the inspections, and the office has pledged in its rule to review all inspection plans and make changes where required.
That is backed up by the presidential directive, and it goes on to state that if inspection plans are found to be inadequate, OPS should use its existing legal authority to review -- to require revisions in the program, including requiring the use of internal inspection devices where appropriate.
That parallels legislation that I introduced in the House that was never acted on but doesn't go quite as far as we think should go.
While I generally support the OPS rule, one part of the rule raises important questions, which I would hope the Board will study carefully, particularly when that issue will have to be resolved in the rules affecting the "rest of this industry", and that issue is the deadline for the first required inspection.
The first required inspection has a deadline of only seven years, with the proviso that at least half of an operator's lines, representing the highest risk, must be inspected in three and a half years.
I don't see why we need that lengthy period of time when there can be failures, given the age of the nation's pipelines.
In the rulemaking, a number of comments submitted to OPS suggest a baseline assessment of five years or less. The Environmental Protection Agency, the Department of Justice, several cities, the NTSB, several environmental groups, objected to the seven-year time line for baseline inspections.
The office concluded, I think a faulty conclusion, that a seven-year deadline would result in a better assessment than a five-year assessment, thatinternal inspection in vendors would not have the human and mechanical resources needed to conduct these inspections during the next five years while meeting the current needs of the industry.
Mr. Chairman, in my many years of work on aviation safety, that is the argument raised again and again for not proceeding with ground proximity warning device, with traffic collision avoidance systems. We have heard it again and again. The industry can't gear up. They can't manufacture it fast enough. They can't do this quickly enough, and yet when forced to do it, when the market is there and necessarily so by law or by rule, the industry has responded, and lives are saved.
The OPS conclusion that there would be inadequate capacity for internal inspections over the next five years is based on a consultant's memorandum. The memo suggests even on its face that this conclusion is not definitive. The consultant says, "Getting a good handle on these numbers has been like pulling hens' teeth. These pigging guys are extremely protective of their data and sometimes misrepresent purposely so as to confuse their competitors." The consultant admits that his estimate of utilization rates is a guesstimate.
The key question of how much the industry would expand over five years, consultant made estimates of growth but gave no indication of the basis for his estimates.
When the Government adopts regulations requiring increased inspections of an industry, the industry will develop the capacity to conduct those inspections. The burden of proof should be on those who claim that the industry will not be able to expand to conduct the baseline assessments or produce the necessary equipment to conduct those inspections.
I don't think that the memorandum on which OPS relied satisfies this burden, and I think it should be revisited.
Fortunately, the issue has been taken to the level of the President, who has responded and pressed the Department of Transportation to act. However, I am concerned by the lack of specificity in the directives.
Of great importance is when OPS will issue regulations on inspections for the operators not covered by the November 3rd rule. That November 3rd rule covered the large liquid pipelines but not smaller liquid nor gas pipelines. For these operators, OPS hasn't even issued a notice of proposed rulemaking.
The President only required OPS to develop aplan by January 15th for adoption of rules for small liquid pipelines. A plan. Mr. Chairman, I think that the office should be required to issue an NPRM by January 15th so that we have something on paper, in place, for the public to respond to. A plan is insufficient.
With only a plan in place, there's every possibility that the new Administration of either party will want to step back and reassess the issues, and then this thing will drag out for another three or four years.
I'm also concerned about the difficulty OPS has had over the years adopting rules, and parenthetically, from a safety standpoint, Mr. Chairman, this is not just a problem with OPS, it is Department of Transportation-wide.
I asked the Inspector General of DOT to evaluate the performance of the Department of Transportation on rulemaking. The study confirmed my very worst fears, that we've gone backward, not forward. The IG found serious deficiencies in the rulemaking process, that the department is taking on average twice as long to issue rules as it did six years ago.
In 1993, DOT issued 45 rules and took anaverage of 1.8 years to complete work on each one. In 1999, the department issued 20 rules after taking 3.8 years on each one. It's taking twice as long to do half as much. That's a sad commentary, but it's like the Russian economy was. Not as good as last year but better than next year. They need to do better, and this Board helps by keeping the spotlight on their safety rulemaking inadequacies.
The Inspector General concluded, and I agree, that the problem is basically one of management. The existing process requires the concurrence of so many offices in DOT before rulemaking can go forward, that inevitably it gets bogged down.
The problem in rulemaking at DOT is that if any office disagrees with the rule, that office has the power to stop the process dead in its tracks. DOT's top management doesn't get adequate information about delays in rulemaking and fails to communicate to the responsible offices.
So, when we're talking about issuing a plan, about issuing future rules, all these hoops and hurdles that you have to go through to get a safety rule out, Mr. Chairman, are discouraging and disappointing, and in that scenario, I think this Board is the last best hope for forceful action, keeping the spotlight on thecurrent steps forward that the Office of Pipeline Safety has made, addressing the issues of technology, and assuring that there is clarity on the issues before us.
There is a role of prime importance here for the Board. It should be the counterforce demanding prompt passage of effective regulations, both within the department and within the Congress.
There's momentum now from the issuance of this rule on large liquid pipelines, but we need to assure that all of those steps are taken vigorously, and we need to work with all interested groups, and I'm certainly willing to do that, to ensure that we continue to make progress.
"A la mort, il faut la vrai". To the dead we owe the truth. The truth is we can make the nation's pipelines safer, faster, more effectively than we've ever done in history. This Board is on the right track.
Thank you, Mr. Chairman.
(Applause)
CHAIRMAN HALL: Thank you, Congressman.
Because RSPA Administrator Kelley Coyner has a scheduling conflict, we've offered her the opportunity to speak before we begin our staff'spresentation on the issues.
As I mentioned earlier, RSPA's Office of Pipeline Safety has begun to take action that will strengthen the nation's pipeline safety requirements, and I want to urge the industry to support RSPA's efforts to establish national pipeline inspection and testing standards.
Administrator Coyner, I appreciate your willingness to be with us this morning. I know that I appreciate, also, the fact that both of us traveled together to Bellingham and to Carlsbad, saw together and witnessed together the devastation of those two events, and I appreciate your commitment and your willingness to be here this morning, and we look forward -- the Board looks forward to hearing from you.
ADMINISTRATOR COYNER: Technology. What can I say?
I appreciate your creating this forum to examine both the state of technology for assessing and managing pipeline integrity and identifying those areas where we need to go forward.
Mr. Chairman, you mentioned our visits to Carlsbad and also out to Bellingham, which really underscored why this is so important.
The timing of this hearing is particularly helpful on the heels of congressional action in the appropriation area and the debate concerning pipeline safety reauthorization as well as President Clinton's announcement of significant actions to strengthen pipeline safety and environmental protection in this country.
As you know, I'm the Administrator of the Department of Transportation's Research and Special Programs Administration, which is responsible for the Office of Pipeline Safety. I welcome the opportunity to highlight the strategies we are taking to improve pipeline safety.
We have issued a Final Rule enacting tougher standards for pipeline integrity. This rule includes mandatory testing and strengthening our regulatory enforcement and research activities. The rule will improve pipeline integrity using existing technology and promote the development of enhanced technologies that we hope will provide even better tools in the future.
Our Final Rule strengthens protection for pipelines transporting hazardous liquids in populated and environmentally-sensitive areas. It is now complete. This integrity management rule is the firstof a series. It applies to operators of hazardous liquid lines that are 500 miles or more in length.
A second rule, which will follow shortly, will apply to operators of hazardous liquid lines which are less than 500 miles in length, and we expect to be very similar to the first rule.
A third rule will apply to the operators of gas transmission lines and will be published in the Spring. The rule requires operators to assess the baseline condition of their pipelines. The most high-risk segments must be tested within three and a half years, the balance in no less than seven years. We also require operators to perform periodic testing with an interval of not more than five years. Testing alone is not sufficient. This rule significantly raises the bar for safety by requiring operators to bring together information on all risks facing a pipeline system. Something we saw how critical it was when we were in Bellingham, Washington, last year.
We require operators to document those risks, lay out a plan to address those risks on a prioritized basis, and then implement the plan. Upon review of the plan, we will hold operators accountable. The risk for third party damage must be considered with the testresults to truly evaluate the significance not only of the baseline assessment but also the mitigation and prevention measures which must be taken as a result.
When operators have determined what additional preventative and mitigative actions are needed, they are required to assess the adequacy of their existing leak detection capability.
Leak detection capability may be the most important prevention action. The technology in this area is rapidly advancing, and the systems for assessment vary enormously.
In our review of operator integrity management plans, we will assess whether or not the operator has correctly determined the need to modify its leak detection capability to protect critical areas and enforce corrections that are needed.
We must make use of technology now available to maximize the protection of people and the environment from pipeline ruptures. At the same time, we must remain committed to improving the ability of tools to detect more types of defects with greater sensitivity and reliability.
Here are the areas we see immediate need for further research action. Transverse flux technology offers promise in detecting problems of seam welds. Itmust be fully field verified and documented.
Technologies to detect existing outside force damage and to monitor damage in real time as it occurs is a key priority.
Tools, such as sensing devices, to prevent damage from occurring in the first place that can be mounted on construction equipment to detect the presence of underground pipelines could be very beneficial.
Improvement in the capacity of leak detection technologies to be more sensitive to the size of the leak and to reflect the distinct qualities of individual pipeline systems. These leak detection systems must be less dependent on the human controller to increase their efficacy.
Consistent with the President's memorandum, we have been working with the Department of Energy for some time to coordinate national pipeline research by leveraging public and private resources to address pipeline safety and reliability issues.
We have been assisting the Department of Energy review responses to their recent solicitation proposals in the area of common interests, including third party damage, leak detection, enhanced inspection technologies, integrity evaluation and advancedmaterials.
By working together, we can maximize the results that enhance the integrity and the reliability of the nation's pipeline network.
Next year, the Research and Special Programs Administration plans to hold a national symposium, sponsored jointly with the Department of Energy, and I invite the Board to join us, to further highlight current research and development efforts, to clarify national pipeline research needs, and to identify the most effective and efficient means of meeting those needs.
I want to challenge the pipeline industry to invest resources in developing new and better inspection and detection tools and practices.
In closing, I would like to thank the Board for holding this hearing and help highlight the need for enhanced research and development efforts. The information generated by this hearing will contribute directly to the development of a national research program for pipeline safety and create a climate of innovation that will in turn lead to enhanced safety.
We know a lot about what will improve pipeline safety, but many unanswered questions remain. We must continue to be vigilant, whether there is anaccident or not, to ensure that we have the best, most effective tools in place to protect people from future pipeline ruptures.
I appreciate this time with you, and I'd be glad to answer any questions you may have.
CHAIRMAN HALL: Well, thank you very much, Ms. Coyner, and in the interest of time, the Board has assembled just a few questions for you. We know you're on a tight schedule.
Are many liquid pipeline companies now conducting internal inspections, and do you know whether they inspect all or just part of their systems?
ADMINISTRATOR COYNER: About 20 to 30 percent of the liquid pipeline companies conduct internal inspections, and I'd have to ask Stacey in terms of what the percentage of that means in terms of their entire systems. I think it's probably the bulk of their system.
CHAIRMAN HALL: Stacey, would you please identify yourself, since we have a court reporter? Your microphone's working fine. We just would like to have you identify yourself for the record.
MS. GERARD: I'm the Associate Administrator for Pipeline Safety.
I think our analysis shows that a great manyof them are testing, but it would have taken 12 years to complete the testing that this rule requires without the regulation.
So, we believe this regulation would approximately double the rate with which this amount of testing would be completed, and that would be the high-consequence areas.
CHAIRMAN HALL: Now, this is the liquid pipeline. How would that compare to the natural gas transmission lines?
ADMINISTRATOR COYNER: It's roughly the same in terms of the percentage of the lines.
CHAIRMAN HALL: Okay. Now, we have all referred to the fact that the President issued new regulations for pipeline safety which requires the companies to assess their pipelines, conduct inspections and tests, establish regular repair schedules and employ methods for leak detection.
Does RSPA have the resources necessary to ensure that the pipeline companies meet these new safety requirements?
ADMINISTRATOR COYNER: We do not. With 55 inspectors on hand, we are not currently in the position of reviewing these plans on a two-year basis to ensure compliance.
We will be working to fulfill the President's request that we identify what the necessary resources are and ask that that be included in the President's budget request next year.
CHAIRMAN HALL: And how is your agency funded?
ADMINISTRATOR COYNER: Our agency is funded through pipeline user fees that are assessed on the transmission companies in both the liquid and natural gas area, and we are also funded through a draw-down on the Oil Pollution Act Trust Fund as well.
CHAIRMAN HALL: Okay. What is the percentage of each? Do you have any idea?
ADMINISTRATOR COYNER: It changed somewhat this year. Let me defer to Stacey Gerard in terms of what the percentage is.
MS. GERARD: I think we're currently getting about $8 million of $47 million from the Oil Reliability Trust Fund.
CHAIRMAN HALL: Okay. But the agency is not funded similar to most of the other regulatory arms of the Department of Transportation through taxpayer dollars?
ADMINISTRATOR COYNER: It is not funded through direct appropriations, through the GeneralTreasury Account.
CHAIRMAN HALL: So, you are essentially dependent on the industry and this Oil Fund for your funding?
ADMINISTRATOR COYNER: That's right. Whatever the appropriation level is determines what the levels of the user fees are.
CHAIRMAN HALL: Okay. Well, some, as you know, have been critical that the new safety requirements may not be strong enough.
Can the pipeline operators meet the new requirements without doing internal inspections?
ADMINISTRATOR COYNER: The pipeline companies have to either do -- use a smart pig, which is what we typically think of as an internal inspection. They are to do hydrostatic testing or they must show an equivalent level of safety.
One of the things, I think, that's very important, and it's made very clear in the preamble, is that these plans must be reviewed and are subject to our directing them to use a better technology if we determine that's what's necessary in that area.
CHAIRMAN HALL: Okay. And when do you anticipate completing rulemaking to include all natural gas transmission pipelines and liquid lines less than500 miles, which are not covered in this rule, and I believe would not therefore have covered the Bellingham accident?
ADMINISTRATOR COYNER: It would have covered the Bellingham accident.
CHAIRMAN HALL: Would have.
ADMINISTRATOR COYNER: The 87 percent of all liquid transmission lines were covered by this particular rule.
When we devised this particular approach to the rulemaking about 18 months ago, we thought that the approach for small liquid lines might be substantially different. At this point, we believe it's going to be very similar, and we expect to have that rulemaking out in a matter of weeks.
CHAIRMAN HALL: What about on natural gas?
ADMINISTRATOR COYNER: On natural gas, we expect to have an NPRM out in the Spring of this year, and it will probably take the balance of the year to complete the rulemaking.
CHAIRMAN HALL: And the Final Rule addresses the need to test pipe in high-consequence areas. We both obviously were out in Carlsbad which would not fit under that rule.
How long a period of time would it take forthose pipes to be covered? That pipeline to be covered?
ADMINISTRATOR COYNER: We would expect that that pipe would be covered by including areas where people congregate. This is, as you might imagine, a very difficult area definition, but I believe that we are in agreement within the Government and also with the various stakeholders that we absolutely have to find a way to cover areas where people congregate.
This, as you know, Mr. Chairman, was an area that was an informal campsite but one that was very popular and well known, and we believe that it's important that we look to those places where people may congregate for worship or for recreational purposes or for any purpose and make sure that they're covered by high-consequence areas as well.
CHAIRMAN HALL: And, finally, does RSPA have any plans to support research to enhance the capability of pipeline inspection tools?
ADMINISTRATOR COYNER: We have an extremely limited budget for this at this point in time. It's a few hundred thousand dollars.
We hope to request substantially more in the coming year and to leverage our resources with the Department of Energy's research as well, but inactuality, there needs to be a substantial investment by the private sector, not only by the pipeline companies themselves but also by the technology sector, in order to achieve the goals that we've set for ourselves.
CHAIRMAN HALL: And I guess, in closing, Ms. Coyner, how many years have you been in this position?
ADMINISTRATOR COYNER: I was confirmed in August of 1998.
CHAIRMAN HALL: Well, I would like to personally thank you for your public service and for the leadership you've brought to bringing about action on many of the recommendations of the Board that have been longstanding, and I've appreciated your dedication in attempting to move those recommendations through rulemaking into regulation.
ADMINISTRATOR COYNER: Thank you, Mr. Chairman. This actually, I think, will be my last public hearing to participate in as Administrator of the Research and Special Programs Administration, and I believe that it is really an opportunity to lay down a marker about what else we need to do, not only in responding to your recommendations and congressional mandates but really maximizing the protection that we afford the communities along the pipelines and theenvironment, so that none of us are in the position of visiting communities, such as Carlsbad and Bellingham, in the wake of such a terrible, terrible tragedy.
I appreciate your focus on this and the rest of the Board Members' focus on this. Pipelines, a lot of times people say now, you're at the Department of Transportation, and is that a mode of transportation, and you all certainly understand that it is an important mode of transportation to meet our nation's energy needs but also understand that we have to do that in a way that is safe and protects the environment.
Thank you very much for your service as well.
CHAIRMAN HALL: Thank you very much, and Congressman Oberstar, and Ms. Coyner, thank you very much for joining us. You all are excused, and we appreciate your attendance and participation.
ADMINISTRATOR COYNER: Thank you.
(Applause)
CHAIRMAN HALL: We will now proceed with our public hearing, and I'll call on Mr. Bob Chipkevich for an introduction of staff and the program.
MR. CHIPKEVICH: Thank you, Mr. Chairman and Board Members.
On my left is Joe Kris, who's the Hearing Officer for this hearing. On my immediate right is Cliff Zimmerman, Pipeline Accident Investigator and IIC on some of the accidents we'll be talking about today.
Rod Dyck, next to him, who's the Associate Director for the Pipeline Division. Then, next to him, Jim Wildey, who is Chief of the Materials Laboratory in the Office of Research Engineering, who helps us extensively in examining pipelines that have been involved in accidents.
If the Chairman pleases, Mr. Dyck does have a presentation for the Board, when you're ready for it.
CHAIRMAN HALL: All right. Please proceed, Mr. Dyck.
MR. DYCK: Thank you, Mr. Chairman and Members.
According to the Research and Special Programs Administration or RSPA, it regulates over two million miles of natural gas pipelines and about a 157,000 miles of hazardous liquid pipelines.
This slide shows major pipelines in North America. It doesn't include natural gas distribution pipelines. The operation of pipelines with integrity problems has been a reoccurring issue in accidents investigated by the National Transportation SafetyBoard.
In 1987, as a result of investigations into three pipeline accidents, the Safety Board recommended that RSPA require pipeline operators to periodically inspect their pipelines to identify corrosion, mechanical damage, and other time-dependent defects that may affect their safe operation.
As noted, RSPA has completed a Final Rule on Integrity Management and plans to publish it in the Federal Register this month.
Accidents investigated by the Safety Board involving the operation of pipelines with time-dependent defects have continued to occur. For example, in 1994, in Edison Township, New Jersey, a natural gas transmission pipeline ruptured. The gas ignited, sending flames 400 to 500 feet upward and destroyed eight buildings.
Examination of the ruptured pipe revealed previous mechanical damage to the exterior of the pipe that reduced its wall thickness. A crag grew to critical size when it then ruptured. Contributing to the rupture were brittle properties of the pipe material.
In 1996, almost 500,000 gallons of gasoline were released into marshland near Grammercy, Louisiana,when a previously-damaged section of pipeline ruptured. This slide shows mechanical damage found on the pipe.
I can't get my pointer to work, but the Numbers 1 and 6 show scrapes, and the circled areas with dotted lines show dents on the pipe that were found, and these are -- this is the mechanical damage that we found. The contractor damaged the pipe about six months before the rupture occurred.
In 1996, nearly a million gallons of fuel oil were released into the Reedy River near Fork Shoals, South Carolina, when a section of corroded pipe ruptured.
In 1987, an in-line inspection device was run through this segment of pipe. The inspection contractor noted an anomaly at the eventual rupture location. The anomaly was assessed as a dent and was judged to require no corrective action.
In March of 1996, another in-line inspection device generated data that indicated pipe wall thinning. The Safety Board found that the subsequent efforts by the pipeline operator to measure the extent of the wall thinning were insufficient and did not reveal the full extent of corrosion damage. Before the corroded segment of pipe was replaced, the pipe ruptured during a pressure surge.
Also in 1996, a rupture of a pipeline near Lively, Texas, sent a butane vapor cloud into a residential area. The vapor ignited as two residents in a pick-up truck drove into the vapor cloud, killing both.
In May of 1995, an in-line inspection tool was run through the pipe, generating data that led to the conclusion that the rupture area only had light corrosion damage. The Safety Board found that rapid corrosion had occurred on the pipeline since the 1995 in-line inspection.
In 1998, a rupture in a pipeline in a landfill in Sandy Springs, Georgia, resulted in the release of more than 30,000 gallons of gasoline. When the pipe was excavated, it was found to be buckled and cracked. The Safety Board found that the pipeline ruptured because of settlement of soil and trash underneath the pipeline.
The Safety Board is currently investigating six other pipeline accidents that occurred during 1999 and 2000 that may also involve pipeline integrity problems.
In 1999, a pipeline rupture in Knoxville, Tennessee, released over 50,000 gallons of diesel fuel into the Tennessee River. A brittle-like crack wasfound on the pipe. The Safety Board is investigating whether corrosion initiated the crack and if the material's toughness had a role in this rupture.
Two days before the rupture, an in-line inspection device was run through the pipe segment with no anomalies in the rupture area reported.
In June 1999, in Bellingham, Washington, a pipeline accident released approximately one-quarter million gallons of gasoline, and three persons lost their lives. We found several areas of external mechanical damage in the vicinity of the rupture.
The arrow points to the gouge in which the rupture initiated.
In 1996 and '97, the pipeline operator conducted in-line inspection of the pipeline which indicated the presence of anomalies in the area of the subsequent rupture. The pipeline was not excavated in this area before the accident.
In January 2000, in Winchester, Kentucky, a pipeline accident released about 490,000 gallons of crude oil. Safety Board investigators found a dent on the bottom of the pipe in the rupture area.
In March 2000, in Greenville, Texas, a pipeline accident released about 565,000 gallons of gasoline. We found indications of cracking thatinitiated at the edge of a longitudinal seam weld.
In April 2000, near the Chalk Point Electric Power Generating Station in Maryland, a pipeline accident released about a 125,000 gallons of fuel oil. We found a crack and a buckle at a bend.
In 1997, an in-line inspection of the pipeline was conducted. The inspection report indicated the presence of a welded pipeline fitting at the approximate location of the bend. However, there was no fitting at this location.
In the case of an August 2000 natural gas pipeline explosion and fire near Carlsbad, New Mexico, that killed 12 people, we found significant internal corrosion at the rupture location. The pipeline segment that ruptured was constructed in 1950.
Today, we will focus on technologies available to assess the integrity of pipelines, such as the use of in-line inspection tools. We need to identify the benefits and limitations of these tools and to determine the status of on-going research.
Tomorrow, this Pipeline Safety Hearing will provide a forum to address the capabilities of pipeline-operating systems to identify leaks and provide sufficient alarms so that controllers can take timely action to reduce the consequences of leaks.
The lack of timely recognition that release has occurred has also been a reoccurring issue in accidents. For example, in the May 1996 accident near Grammercy, Louisiana, almost immediately after the rupture, several alarms sounded in the pipeline operator's control room, some showing that pumps had automatically shut down.
The pipeline controller said that he initially believed that the alarms resulted from refinery activities that had in the past generated alarms and which also automatically shut down pumps.
One alarm reported a line balance alarm, showing that the amount needed from one part of the pipeline differed significantly from another part. The controller said that he had anticipated a positive value from the line balance alarm because of the shut down of the pumps.
He said that he therefore did not read the full alarm message and did not note that the line balance alarm actually showed a negative value. The controller worked to restart pumps that had shut down automatically.
About an hour after the rupture, the controller received another line balance alarm. This time, the controller closely examined data and thenconcluded that a leak had occurred. Ultimately, 500,000 gallons of gasoline were released.
In the case of the November 1996 pipeline accident near Murfreesboro, Tennessee, a pipeline rupture resulted in the release of about 85,000 gallons of diesel fuel.
During the accident, a controller did not notice an over-pressure condition building against a closed valve at a pump station because the control room displayed an incorrect location for a pressure transmitter. The system recorded a sudden pressure drop at another pump station but no alarms occurred.
Although company procedures required shut down of the line in the event it was blocked, the controller continued to operate the pipeline and eventually succeeded in reopening the closed valve. He continued to pump diesel fuel through the ruptured pipeline for approximately one hour, until he realized that the expected pressure rise on the pipeline was not occurring.
The Safety Board is currently investigating five other accidents that may involve a delay in recognition of a leak. For example, in the February 1999 pipeline accident in Knoxville, Tennessee, the pipeline was not operating when the pipeline ruptured.
Records from the pipeline operator's control room indicated a sudden but small pressure drop at a pump station. No alarms were relayed to controllers. The pipeline was started up twice before controllers concluded that the pipeline ruptured, about four and a half hours after the rupture.
In the June 1999 Bellingham, Washington, pipeline accident, the pipeline operator reported that the computer systems became unresponsive because of inadequate computing capacity during the time frame that the rupture occurred.
Controllers did not recognize that the pipeline had ruptured and restarted the pipeline. About an hour after the rupture, controllers shut down the pipeline.
In the January 2000 Winchester, Kentucky, pipeline accident, the controllers shut down the pipeline about two hours after the rupture.
In the March 2000 Greenville, Texas, pipeline accident, at the time of the rupture, a pump automatically shut down. The controller didn't recognize the reason for the shutdown and started another pump in an attempt to keeping the line running.
In the April 2000 pipeline accident near the Chalk Point Electric Power Generating Station inMaryland, the pipeline operator for over one hour after the first indication of abnormal operation of metering instruments for monitoring the pipeline were not functioning during a maintenance operation that was on-going at the time.
Mr. Chairman and Members, the Safety Board staff has been deluged with requests to participate on panels. With just one day devoted to each topic, we simply do not have time to include all requests and have had to make difficult choices in choosing our panelists.
Therefore, we invited those that we could not include on panels to provide us with additional information for subsequent review and consideration.
For the panelists that are participating, we thank you for sharing your knowledge and experiences with us.
Thank you.
CHAIRMAN HALL: Thank you.
We're now going to -- before we move to the panels, we will take a short break, but if you would hold in your seats a moment, we will have four panels today.
The first will be on In-Line Inspection Service and will include representatives from Tuboscopeand PII. Then we will have a panel on Integrity Assessment, Pipeline Operators and Researchers.
I suggest we take a 15-minute break, return at 11:00, and we will then begin our panels, and we'll stand in recess until then.
(Recess)
CHAIRMAN HALL: We will reconvene this Public Hearing on Pipeline Safety, being conducted by the National Transportation Safety Board.
For our information of those in attendance, at the Board's website, www.ntsb.gov, we will have later in the day a webcast of the proceedings that you are now participating in, and we anticipate also having a transcript of these hearings available for -- on our website later as well.
So, if you have not had an opportunity to view our website, we certainly would encourage you to do so, and if you have any comments on how we might improve our website, particularly in the areas of pipeline and hazardous materials information, we would also welcome your comments.
We now begin the first of four panels that we will have today. Let me observe that, as Mr. Dyck commented, we have had a number of people that have wanted to present. We have had to be -- unfortunately,we have not been able to accommodate everyone that wanted to present, but we do have a number of presenters, and because we want to get through these presentations, we have a time limitation that will be enforced on the presentations.
So, Mr. Chipkevich, I will turn the hearing back to you. We will have this first panel of presentations, questioning by the staff and then questions by the Board.
MR. CHIPKEVICH: Thank you, Mr. Chairman and Members of the Board.
The next panel is the In-Line Inspection Service Panel. On this panel is Mr. Ravi Krishnamurthy and Mr. Tom Sawyer from PII North America, Incorporated, and Mr. John Parsons from Tuboscope.
Panelists, I would like to remind you that you have 15 minutes to give your presentation. The yellow light in front of you will go on when you have two minutes remaining. The red light indicates that your time is up.
Mr. Chairman, staff is ready to hear from the panelists.
CHAIRMAN HALL: Well, please proceed. Who will be going first? Mr. Krishnamurthy, please, sir.
Panel: In-Line Inspection Service
MR. KRISHNAMURTHY: Yes, I'll start.
I wanted to get my presentation on there. We're going to talk about pipeline integrity management, and we're going to try to attempt to present the inspection tools in context of the pipeline integrity management, and there is myself and Tom Sawyer, and I'll make the presentations, and we'll answer some questions.
I'm sorry, yes. Again, whenever you do a pipeline integrity management plan, you look -- you start with assessing the risk as the first step and of a system or a segment or sections of a pipeline. Then you attempt to identify potential failure modes. Is it corrosion? Is it cracking? And then, you look at in-line inspection tools or other mitigation methodologies.
Now, a critical factor in that is you want to match the appropriate inspection tool or technology to the potential failure mode, whether it's metal loss or weld deterioration, cracking, or dents, and a very critical aspect, next aspect, is post-inspection assessment.
You want to do remaining strength assessment or corrosion management or time-dependent modeling and longer-term modeling, but the in-line inspection has tobe put always in context of overall pipeline integrity management, and, of course, an on-going reassessment.
So, with this infrastructure in mind, I'll go into a little bit more depth on in-line inspection tools.
Now, really in-line inspection tools travel as products. They've been introduced since 1960s. They use very traditional technologies. Primarily, you can break it down into two. It's magnetic and ultrasonic. Pretty much all tools can be broken down into two.
They really record and store data. That's what they do, and they basically provide a snapshot of the condition of the pipeline.
Now, a key element to in-line inspection tools is quality of inspection, and that's where the difficulty in developing and analyzing the data, doing everything with these tools, come in.
Number 1 is detection. Next is discrimination. You can detect pretty much every anomaly in the line, but discrimination is very critical. Then you want to size these anomalies, sizing accuracy, and, last and the most important one, is repeatability.
So, in an in-line inspection designmanagement, you're looking at those four elements, all of them together, and when they come together, you will have a very good inspection and database at that point.
There are a variety of tools. You can look at geometry, bend, mappings, strength, but in my presentation, I'm going to primarily focus on defect detection and discrimination. That's all I'll focus on, and I'll focus on a few tools around that, and the different types of defects. I'll try to attempt to characterize our metal loss, cracks, laminations, etc., etc.
Now, there are -- remember, when we look at tools, you have to remember constraints. There are a lot of constraints with inspection tools. There are operational constraints in terms of what speed you can run this tool at, and how quickly, how much segment you can collect the data in, and there are a lot of operational constraints. Pipeline dimensions are a constraint. The bends are a constraint, and especially ultrasonic cleanliness is a constraint.
So, keeping this in mind, I'll go through every tool, identify what it can do, and what are the limitations, and what are some of the -- one of the most fundamental technologies people have used for ages is magnetic flux leakage.
It's the oldest of technologies being used. There are fundamentally two types. There is axial MFL, and then there is circumferential MFL, and circumferential MFL is what is referred to as a transverse of flux leakage, and it's basically circumferential, one is axial.
Now, really in an MFL tool, what you're looking at is a magnetic flux field imposed parallel to the pipe wall, and what you're looking for is the magnetic flux lines will be deflected if there's a crack -- if there is corrosion. Sorry. There's a metal loss, but if there's a ferrous material near the pipe wall or the properties of the steel change, you'll see deflection, and that deflection or that leakage is recorded by the sensor, which is that yellow spot there.
Now, at the bottom, there's a photograph of a magnetic flux leakage tool, a typical tool. You'll see the brushes represent the magnets, the magnets and the senses in the center.
Now, the length of these tools depending on the dimension you're looking at can range anywhere from 2.3 to 5.6 meters, and the velocity anywhere from half a meter per second to 5 meters per second. So, it's a range. 5.6, approximately 18 feet.
Now, (2) Specifications, and this is a very critical aspect of it, and these specifications normally are dependent on the diameter of the pipe.
As you go smaller in diameter, the specifications will deteriorate a little bit. Now, the minimal depth you normally can detect with this tool is about 10 percent wall, but I want to focus in on one aspect which I'll come to when I go to ultrasonic, is the pitting surface area, and what the axial MFL can do is actually detect a very, very small area, .28 by .28 inches, and are .4 times the wall thickness, and the sizing accuracy is 10 percent wall thickness, and again you can vary that. But I want us to remember that.
The other thing this tool does, it's been used in industry for a lot of times, and it effectively discriminates metal loss, splitting, circumferential defects, wall defects, but there's something this tool is not very good at. It is very poor at discriminating long longitudinal defects.
So, if you have a corrosion, which is long and stretches along the length of the pipe, this tool will detect the ends, maybe a few spots along the way, but it won't map the entire corrosion because it's an indirect measurement of corrosion. That's something we have to remember when we use this tool.
Another thing it cannot do is it cannot detect discriminate mid-wall defects. Now, these are some key limitations of this tool, but it's very effective at metal loss, pitting, circumferential defects.
Now, axial MFL tool comes with varying resolutions. You have, you know, low resolution, standard resolution. You have high resolutions. Then you have extra-high resolution, and what I've shown in the specifications here is what we would call high resolution.
Now, there's what we call extra-high resolution, also, but again that comes down to what value it adds at the end of the day, and again this tool, as far as our company itself, it's applied in over a 150,000 miles, and the industry has quite a bit of experience with this particular tool.
The next MFL technology tool we want to focus in on is the circumferential MFL. It induces circumferential magnetic field. Again, it's as opposed to the axial MFL. It goes around the circumference, and I want to show this picture here.
These two brushes represent the magnets and the sensor in the center. So, what you will do is you will have another segment, another section, like thisdownstream which will straddle the magnets. So, you will be at 100 percent circumferential coverage. So, this is basically a circumferential MFL tool. Again, length approximately 18 feet.
Now, this tool, it characterizes corrosion. It gets accuracy very similar to the axial MFL. In some cases, a little less, but it was primarily developed to detect seam weld defects, and what it does is it doesn't actually get you an exact depth, but what it allows you to do is to discriminate between crack-like and non-crack-like seam weld features.
But there's a key limitation on this tool which is very critical to note. It will only detect seam weld features or cracks which have an opening greater than .1 millimeter. This is very fundamental to this tool. It is because magnetic field is not disturbed, and we don't see a signal at that point for cracks.
It also detects and discriminates dents with and without corrosion and cracking, but exactly opposite to the axial MFL tool, the circumferential MFL is poor at detecting narrow circumferential indication. So, if you're looking for circumferential indications, this is not the right tool. Axial MFL is the right tool, and it cannot -- like the axial MFL, it cannotdetect or discriminate mid-wall indications.
Now, this is a much newer tool, introduced in the last two to three years. It only has about 3500 miles' experience.
Now, I just have an example of data from axial and circumferential there. If you look at the axial, you can see these spots, and if I read the axial MFL data in isolation, I would look at it and say these are pits. These are isolated pitting and maybe shallow. It may not impact the integrity of the line, but I go to the right side and look at the circumferential MFL data.
It actually characterize a very long-running corrosion, a long narrow axial corrosion, and that's where understanding what problem I'm looking at, what failure mode I'm going to look at is very fundamental to what tool I would use.
Ultrasonic -- again, ultrasonic is a wall thickness measurement tool. Unlike MFL, it's a direct measurement tool, and it's a compression wave tool which sends out compression ultrasonic wave and measures directly the wall loss.
Now, again, it also has two lengths of approximately 18 feet, and it comes in all different sizes, and this is a much more precise corrosionmapping tool. It actually maps the corrosion very accurately, whether it be isolated, pitting or long axial pitting.
But there is a down side to this, and I had mentioned in the axial metal loss tool, if you look at the size of metal loss it can detect, it can only detect and size metal loss greater than 20 millimeters. So, it is a limitation of the two when you run it at one meter per second and a certain pulse repetition frequency.
There are ways to improve that accuracy, but with the standard tool, you have this limitation. So, there is a point at which ultrasonic is very appropriate, and then there is a point at which axial MFL is appropriate.
But it is extremely precise at long axial corrosion, and, more importantly, it will characterize laminations. So, again I wanted to point out where these complement with the other tools.
Now, there's a very elegant tool for cracks, the ultrasonic shear wave. Now, this is a shear wave which is incident on the pipe wall at about 45 degrees, and like the compression wave, it comes perpendicular to the wall.
Now, this is a very, very, very sensitivetool, very accurate. It has 500 to 800 to 1000 sensors, depending on the size of the tool you're looking at.
Now, at this point, I wanted to point out that with all these tools, data interpretation is an extremely labor-intensive and a very difficult process. So, there's always a time delay in running the tool to getting the data analyzed.
In this particular tool, you generate 100 terabytes of data when you run this tool, and you go through an automated pattern recognition software to drop it down to 20 gigabytes, and from 20 gigabytes down on to usable data form, you're looking at manual interpretation.
But the value of that manual interpretation is it's extremely accurate in characterizing internal cracks, external cracks, and again I'm focused on longitudinal cracking. This can be reset for circumferential, but it's primarily used for longitudinal cracking, which is a problem you focus in on.
Again, there's a minimum defect line. There is a length accuracy. But again I want to focus in, it's very appropriate for stress corrosion cracking. It's very appropriate for fatigue cracks, weld defects,but again there's a size limitation.
It cannot go below 16-20 inches in diameter, and the other down side of every ultrasonic tool is extremely clean lines. That's a limitation. Much less restrictive in the MFL tool. It's actually been involved since '95-96, and it has over 5000 miles of experience. It's a very accurate tool.
Now, this is an example of a C-scan output, which is basically looking at an amplitude signal versus relative angle, and it has actually mapped the SCC cracks at this bottom with the C scan.
It's very valuable in characterizing these defects, but what I want us to remember is it characterizes length very accurately, depth estimates.
Now, there's another version of ultrasonic shear wave, which is for gas lines. Now, all ultrasonic tools require a liquid medium, and there's a tool which is modified using wheel probe for gas lines, where you have contained glycol, which allows you to use it in gas lines.
Again, I'm kind of running through it a little bit just to catch up on time, and I wanted to come to this particular tool. We are in the process of working on a new tool which is electromagnetic acoustic transducers, and this is focused for gas pipelines.
What the intention is, it should provide the same accuracy and ultrasonic shear wave that is provided for liquid lines. It uses a magnet to generate an ultrasonic sound through the pipe wall.
So, it will do the same things as an ultrasonic shear wave tool would do. This is in development. It's in R&D right now. We expect to have it out in a couple of years.
Now, again, I just want to summarize very quickly. Inspection tool selection, you know, I wanted to summarize to say when you're looking at metal loss, you're normally looking at three options: axial MFL, circumferential MFL, and compression ultrasonic tool.
In crack or crack-like defects, you're looking at shear wave ultrasonics or circumferential MFL.
So, really, when you go through this decision-making, you have to be very careful about how you decide what you need to run, if you need to run anything.
Again, inspection tools are very valuable for integrity management, but timing and technology is very critical to note. So, in terms of when you run this tool in the integrity life cycle for pipeline and the technology you use are extremely critical, and you always have to know the limitations, and it has to bein context of an integrity management plan.
Sometimes tools may not be the right answer. A pressure test may be a more appropriate approach, and we have to put it in that context, and post-inspection assessment is absolutely fundamental to having an appropriate in-line integrity management program.
Appropriate excavation data, good corrosion engineering mechanics, reliability of engineering has to be applied to this, for this -- for any of these tools to add value to integrity management.
Again, this timing of running inspection tools, to me, those timings should be decided based on time-dependent phenomena and inspection tools. A fixed timing, you always run the risk of either not running the right technology or sometimes when you run a corrosion after five years, your corrosion rates may be so slow, you're not going to see any difference between the two runs.
So, we have to be very cautious about how we time it and how we put it in context of an integrity management program.
I'm done.
CHAIRMAN HALL: Well, thank you very much, Ravi. That was an excellent presentation. A lot of information in a very short period of time.
We will have both presentations before the questioning. So, I'll ask Mr. Parsons if he would please proceed, and again welcome you, sir. We appreciate your participation in this hearing.
MR. PARSONS: Thank you, Mr. Chairman.
First of all, I'd like to say that the complexity of the tools has increased very rapidly in the last couple of years, and --
CHAIRMAN HALL: Mr. Parsons, these microphones are excellent, but they have the disadvantage that you have to pull them fairly close. So, if you would.
MR. PARSONS: Sorry. So, I'll -- if you can start the presentation. Okay. Thank you.
I think Ravi did a good job of talking about some of the complexities and the breadth of the new software packages and the tool systems that have been released recently.
So, what I thought I'd do is start off by looking at the true path system, which is our GIS package, and what that does is allows this data to be put together in a single platform and allow our analysts and our customer analysts to look at the data in a more rapid and more meaningful way, and to take a quick look at the tool fleet that we have today, andthen maybe take a quick look at the data analysis platform and some of the research we're currently carrying on.
The GIS platform basically allows you to look at the in-line inspection data in a real-world environment, and as you can see there, there's a wetlands area and a river, navigable waterway, which is traversed by a pipeline, and down here in the bottom left-hand corner is the elevation of the pipeline, and, so, you can see it crossing the river, and over here is the database that's supporting this information, and up on the top left is all the various types of information you can pull down on to a smart map.
On that map, the trajectory of the pipeline is actually placed there by the in-line inspection tool. It's not drawn, and all the features on that pipeline, every girth weld, every bend, is put there by the internal inspection tool itself.
The GIS work space itself, as you can see here, is able to identify lots of different features. For instance, here we have a school, and you can see the distance between these types of features, HGAs and USAs, in respect to the pipeline.
One of the abilities of this system is to measure distances between the pipeline and any HGAs orother school zones or whatever may be around the pipeline, and we can zoom in and out and measure those distances, and you're going to see right now we're measuring the distance between a housing development and the pipeline.
The system does have the ability to store data at every location. It allows you to pull down video of people on the pipeline. Here's somebody boring a hole along the side of a right-of-way. It allows us to access any type of information that the pipeline owner might gather, and in a second, I think you'll see a few more data items come up.
You can place reports on to the system. Here, we're taking a survey of a valve on the pipeline, and the exact location of that will be placed into the map. Here, you can see us observing a small river and the crossing across the pipeline. Obviously we can relate this to any anomalies that may be in the system after the fact. Here's a temporary launcher that was put on to the system to launch the in-line inspection tool.
Okay. One of the features of the software package is it allows us to interact between the GIS platform and the data from the in-line inspection tool, the actual evaluation data.
At the bottom of this system, you can see the database itself. Above it, you can see some anomalies on the pipeline, including the girth weld itself on the system, and you can scan or move by looking at database and applying different severity rules, sort in that, and then jump into those positions on either the smart map or the actual view of the data itself.
The current applications that we have on the platform is to provide a visualization tool for high-consequence areas and USAs. We can integrate this data with direct access information, CPs, CIS data. Any information from excavations that have been done on the pipeline can be put on there in order that you can make assessments of which are the most important anomalies to go to first.
We can interface this thing to a corporate GIS package that a pipeline owner may have, and we can also output directly to the National Pipeline Mapping System.
Future developments we have in mind is to apply a special query engine which will allow you to query on the system with simple rules, like give me all the positions where I have significant corrosion in relation to a river crossing or a school zone or a Class 3 area.
The second option that we're looking at is to put some risk assessment or integrity management rules into the system, and the third one is to make the system available across the web, to have a thin client capability, and last is to apply the system to field management directly.
Looking at the tool fleet that we actually run today, this is a typical tool that we run today. This one was released on to the market last month, and we'll see if the mouse now works. The front end of the tool is the drive module and includes the power system for the tool.
As Ravi mentioned, the second module in the tool is a large magnet that saturates the steel, and then there are some sensors between the two magnets which measure any flux leakage due to metal lost.
So, that section of the tool has another ring of sensors that discriminate between ID and OD corrosion. There are 256 channels on this particular tool to measure that data, and the third unit has the inertial navigation system in it and a measuring system to measure the distance along the pipeline.
The inertial navigation unit is a unit that applies the input on to the smart map which I showed you earlier, and the third ring of sensors is adeformation sensor ring which allows us to look at pipeline dents, wrinkled bends, and other features, besides corrosion.
We have similar features on our standard large diameter tools, but this is a new tool which we will be releasing the middle of next year, and this has some incremental features which are new to the industry.
The speed control has been out for a number of years now, and it allows us to control the speed, to get better data accuracy in gas pipelines. The second module is a circumferential magnetizer, which, as Ravi mentioned earlier, allows us to look at longitudinal narrow defects and to some extent cracking, and perhaps if you add to that the axial magnetizer in the same tool, you can increase the accuracy of the data for traditional corrosion or metal loss measurement.
We're also adding multi-access sensors to increase our accuracy, and the deformation sensors I showed on the previous page are also on this tool, and the data processing for these tools is significantly higher than tools on the market today, and we can run up to 4000 channels of data, and one of the other new features on this tool will be that we can look at the data directly in the field because it will be processedas it passes down the pipeline.
So, typically, a customer has to wait a number of days before he gets a report back from this. So, it will speed up the processing of the data, so they can act quickly if they find any significant anomalies.
This is a typical look at the data from the analysis system, and the top graph or view is of a saturated data on some spiral weld pipe, and the lower information is a reduced field, and in the reduced field, you can see there's a lot richer data which is due to the pipe itself not being saturated by the magnetizer, and you can actually see some of the mill defects and some high spots in the tool. This is actually a sample from our data.
So, the tribute package provides a very user-friendly interface for our analysts and our customers' analysts to use. It's a very accurate representation of the pipeline with regard to the data we have acquired, which is corrosion and deformation information, to date, and provides grading tools for anomalies.
We not only use the standard rules, we also do cluster interaction with things like R string, which I think Ravi also mentioned, and we can produce eithercustom reports or standard set of reports for our customers.
Development plans for the future. If the tools are run multiple times in the pipelines, we can
-- we should be able to predict whether particular corrosion area in the pipeline is active or inactive, and what the growth rate of the corrosion may be.
From the tool I showed earlier, we have multi-access, multi-magnet and multi-field strength sensors which allow us to increase the accuracy of the tools in the future, and we'll be able to provide improved strainer analysis in the very near future.
A quick look at R&D that's carrying on associated with that tool. The tools now will look at the magnetic field in multiple angles, and here's a quick look at some of the components of a -- here's a small corrosion pit in the pipeline.
As you can see, it's smeared from the circular component north and south in this particular view, and if we look at the magnetization field in the circumferential direction, we can then see the front and back of an anomaly fairly easy but perhaps not the sides, and in a third access, we can see that anomaly pretty well. So, by adding -- looking at all three axis of data, we can provide a lot more accurateresults.
If we then restrict the number of sensors we use just to a single sensor in the same plane as the magnetizer, and then look at this particular pattern here, we produce some holes in a piece of steel, and it lets it respond to the sensors.
As you can see, you see this smearing effect with an axial magnetizer, with axial sensors, which makes it difficult to discern holes themselves. With a circumferential magnetizer, the exact opposite happens, and you get smearing in the other direction, and that's why we believe if you take the two magnetizers shown on the previous tool, you can now see that pattern very clearly, and if you add the multi-access sensors, then it allows us to discriminate those holes even more clearly.
Looking at the mechanical damage and reduced field, this is a gouge that was placed in a sample in a pipeline, and this is a typical response from a saturated field. This is the response from the reduced field, which is taking into account the material characteristics of the steel in the pipe, and then if we subtract the two, we can see more clearly that gouge and perhaps the higher load created around that defect.
We still are not able to grade or discern thetype of defect, but we can identify that it's there, and that's what we hope to do in research over the next one to two years.
Looking at straight deformation-type systems, here's a rock dent on the bottom of the pipeline, and you can see that represented there, looking down the pipe and across the pipe.
Here is the internal combined strain inside the pipeline and the external combined strain, and we can see this quite clearly now in the system. Unfortunately, this is not accounting for structural steel changes due to mechanical damage.
Thank you.
CHAIRMAN HALL: Okay. Well, thank you very much, and we'll now move to the Technical Panel for questioning.
Mr. Zimmerman?
MR. ZIMMERMAN: Thank you, Mr. Chairman.
CHAIRMAN HALL: Please pull the microphone close, Mr. Zimmerman.
MR. ZIMMERMAN: Yes, okay. My first question I'd like to ask to Mr. Krishnamurthy.
MR. KRISHNAMURTHY: Murthy.
MR. ZIMMERMAN: Murthy.
MR. KRISHNAMURTHY: Ravi's fine.
MR. ZIMMERMAN: I'd like to know what is the confidence level that you now have in your cracked tool data and the evaluation of that as far as being commercially viable.
MR. KRISHNAMURTHY: Again, which tool --you're referring to the ultrasonic shear wave or which one are you referring to?
MR. ZIMMERMAN: Well, we can talk about --
MR. KRISHNAMURTHY: Okay.
MR. ZIMMERMAN: -- any of the tools that you have, yes, at this point.
MR. KRISHNAMURTHY: Okay. Again, the ultrasonic shear wave -- let me go to that one. That's the easy one.
It's very highly reliable. It's been documented to have confidence intervals of 90-95 to 100 percent in terms of locating linear indications.
Now, all of that -- it's -- I have seen documentations of about 80 to 85 percent of identifying whether it's SCC or some other type of anomaly, but now if you go to the TFI or the circumferential MFL, we are still more -- that is where the demarcation comes in.
When you look at that greater than .1 millimeter defect in identifying a seam weld that's crack-like, we're looking at about a 75 percentconfidence when you see where the seam weld is crack-like.
Now, we can identify all seam welds, whether it's crack-like or non-crack-like. That discrimination is much harder. So, there, we're looking at a much smaller confidence interval.
So, it depends on what kind of defects you're looking at and that.
MR. ZIMMERMAN: Okay. And then, the next point now, first, you have to find them obviously, but then your evaluation of them to determine which defects are significant, so that a pipeline company will know which ones that they need to repair. That's the critical part that I see once you can find a defect.
MR. KRISHNAMURTHY: Yeah. Again, let's go back to the shear wave tool.
The shear wave tool will very easily identify which ones are -- which -- what I would call critical cracks, which will fail by a traditional fraction mechanics analysis or whatever.
Now, what they -- the subcritical cracks, again they'll meet that threshold, 30 millimeters, and greater than one millimeter in depth. You can be 90-95 percent confident that it'll meet that very accurately.
Now, coming back to the TFI, TFI willidentify all seam weld features because you'll see an indication in the traces or in the control field they look at.
Now, the question is when they discriminated, they're only 75 percent confident that it's crack-like. That is where I'm talking about.
MR. ZIMMERMAN: Okay. And out of those indications, what kind of a report do you then prepare for the pipeline company so that it can act on the ones that are problems?
MR. KRISHNAMURTHY: Okay. Again, we saw them -- again, going back to the circumferential MFL, we saw them by what we would call crack-like and what we would call -- they call them -- we are 75 percent confident that it's crack-like, and we also give another category which we say we're 50 percent confident that it's crack-like. We're not sure about this one, and then there are seam weld features. So, we kind of categorize them.
In the circumferential MFL, we don't quantify the depth. It just meets specification depth, whereas when you go to the ultrasonic shear wave, you get an actual length, estimated depth, categorized depth. So, it's a different kind of reporting structure than shear wave.
MR. ZIMMERMAN: Okay. So, here again, I believe we're -- I'm not sure you're answering my question.
If we have -- we know to whatever confidence level you can determine these cracks and the depths, what kind of a report do you then put out to the pipeline company that indicates which one -- let's say you have 10,000 indications.
MR. KRISHNAMURTHY: Hm-hmm.
MR. ZIMMERMAN: Maybe five of them are significant. Maybe 200 of them are significant, that they should go out there and look at them and examine them.
How do you make -- how does your analyst go in and make that evaluation?
MR. KRISHNAMURTHY: Okay. Now, the analysts don't make the evaluation that they should go out. What they'll identify is these already deep cracks. We think they're long.
Now, that -- in the report, they'll identify these as significant cracks or, let's say like you said, out of 10,000, five are significant, they will be identified and highlighted, and then the rest will be categorized or summarized based on whether they're crack-like or non-crack-like or where they fall inthat. So, they are identified in the report.
The same thing in the shear wave tool. If you see some really bad cracks, absolutely, you won't wait for the report. There will be a direct communication on that. But it will be identified in the report as significant cracks or cracks which we think are significant or the analyst thinks is significant.
MR. ZIMMERMAN: Okay. For Mr. Parsons. A similar question. What's the confidence level in using your crack tool for commercial applications and evaluating the inspection data?
MR. PARSONS: Currently, we only have a prototype tool. It's still in the research phase. We took over a project from another in-line inspection vendor that was exiting the business, and when we developed or took that tool out on some preliminary runs, we found that it did not grade as accurately as had been advertised, and we have taken it back to the research phase and are redeveloping the sensors, and we expect that tool to take about two years to develop.
MR. ZIMMERMAN: Okay. Thank you.
The Board has seen cases where anomalies have been misinterpreted in both MFL tools and ultrasonic tools. I'd like to address my first question to Mr.Krishnamurthy first, and can you tell us if the evaluation of signatures of anomalies can be improved, so that we don't miss the ones that are critical?
MR. KRISHNAMURTHY: Yeah. Let me go back to your previous question, which is defects missed or defects misinterpreted or miscalled or called wrong or not even called in some cases.
There could be three or four reasons for that, and I want to go back to my presentation. One reason is the appropriate tool for the appropriate application. That's very fundamental to this. No one tool is a panacea for all problems. It identifies the predominant problem and use the right inspection, and in the context of right integrity management plan. The tool is only a subset of that plan.
The other aspect to that is a lot of these inspection technologies, there's an element of this which is automated, and there's a huge element which is you have a bunch of very dedicated analysts, like 50-60 people, sitting in offices, looking at data day-in and day-out.
So, there is a human element to it, which is why you'll see sometimes the confidence interval is reflected by virtue of the technology in some cases, and in some cases by virtue of the fact that it's ahuman interaction. So, those are two or three possibilities.
Now, there are ways to improve it. The first way, I think, to improve it is to put -- always put a tool in context of integrity management plan, and understand what you're looking at, understand what kind of corrosion you're looking at, not just going and say I'm going to run a UT tool for every five years or every eight years or run an MFL tool for -- we have to have an understanding of why we are doing that. That is one way to improve it.
The other way, which companies, like PII, in our Inspection Division, are working on it is, of course, improved training a lot more people. I mean, by virtue of the fact that as the load increases, you know, we are not always positioned. So, we have to be proactive about lower management in that respect.
Thirdly, improvement of technology, and the EMAT is an excellent of that, where it will be more accurate than sizing cracks in gas lines, for example, than the traditional -- Tom, did you want to add?
MR. SAWYER: Yeah. I think, just to add on Ravi's, I think there is an opportunity for more rigorous testing using facilities in the industry.
In looking at a multitude of defects andsamples from industry, which we can accurately characterize the tools against and build up a defect library much, much faster than we currently we do right now.
As I say, to show new technologies, you have to build up the track record, and there is feedback required from the industry, and the better feedback we get, working with the industry, the faster we can improve tool accuracies and confidence intervals and probabilities of detection.
MR. ZIMMERMAN: Well, that's another question. So, before I go on to Mr. Parsons, and now I'll get to you on this one.
Tell me a little bit about what kind of feedback you're getting from industry. Is it sufficient? Could you characterize that for us?
MR. SAWYER: Well, it varies, of course. I think in some of the newer technologies, we've been quite pleased with the feedback with the Transcan tool or the circumferential tool.
Because of its newness and seeing many things for the first time with this technology in situ as opposed to a laboratory environment or what we call a "pool test", the feedback has been tremendous in most cases.
In areas where we can improve is with some instances where there is no feedback. So, we also need to perhaps work more jointly with industry in terms of setting up of test programs where we can evaluate situations with depth samples.
Again, as I say, it can improve, but for the most part, the new technologies, it's been excellent.
MR. ZIMMERMAN: Okay. And then, in general, in your work course tools, the majority of inspections that you do, is it possible for you to, you know, set up some communication with the company so that the differences that they find would be reported back to you, so that you can again use them to further define your evaluation of defects?
MR. SAWYER: Yes. We use that on a case-by-case basis. It is dangerous sometimes to take a very specific example and then adjust your algorithms and your mathematical models and apply it across all the board.
We do on a case-by-case where there are difficulties, and we do verification digs in many instances, if not most instances, and we use that feedback mainly to adjust for that specific run or that specific inspection, but we don't necessarily apply it across the board entirely because there are dangers indoing that.
We are embarking on some initiatives in the future to where we would like to see industry user groups in which we have -- bring together multiple users of a certain technology to discuss what they have found, so we can get a more broader picture or holistic picture of what the tools' capabilities and limitations are.
MR. ZIMMERMAN: Okay. Mr. Parsons, could we go back to this first question then? Can the evaluation of the signatures of anomalies be improved, and how do you go about doing that at your company?
MR. PARSONS: Yes, they certainly can, and there are two things that we can do.
One is to improve the algorithms we've developed from the software side, and to model those and to build samples and verify the models, and we are actively working on that now.
The second thing we can do is to apply multi-magnet technology to the systems. I think as Ravi said, the circumferential tool is very good at narrow axial cracks, and the traditional tools are better at typical pits and general corrosion, and if you put those two things together, then you are going to get a higher-accuracy tool, but it is a much more complextool, and it's a more expensive tool.
So, we can improve the accuracy but not without cost.
MR. ZIMMERMAN: As usual, yes. Thank you.
Rod, would you like to -- I'm going to pass the questioning to Rod Dyck now.
MR. DYCK: Yes. This is directed to the entire panel.
What constitutes a pipeline that would be capable of accommodating these in-line inspection devices versus pipelines that can't?
MR. SAWYER: That's a very general statement. It's difficult to answer it succinctly.
There are certain restrictions in terms of bends, is one of the single largest restrictions. These tools typically are only capable of negotiating through pipelines in which the bends are not tighter than one and a half diameters of that pipe. The bend radius is not less than one and a half diameters.
Things, such as reduced port valves, can obstruct certain technologies. Other technologies, there are tools available that do -- that are called multi-diameter pipelines.
I know Tuboscope has developed such tools. We have also developed tools which can inspect multi-diameter pipelines. There are other -- a host of other features that make it impossible to detect through certain parts of the pipeline as well.
Line cleanliness is always a factor, as Ravi mentioned, particularly with ultrasonics, where you need direct contact with the pipe surface.
MR. DYCK: The entire panel, that constitutes your answer.
Could you talk just a little bit about putting these devices through hazardous liquid pipelines versus gas lines? What the differences might be, and what the end result might be from this activity?
MR. PARSONS: On gas pipelines, we are more concerned about the compressibility of the product. So, if there are reduced port valves or other restrictions in the pipeline, the tool will tend to surge, and, so, that's why we've built speed control systems to allow gas to pipe through the tools, and that's really the major difference, I would say, between a liquid pipeline and a gas pipeline, although certain products are quite corrosive, and, so, we have to be careful about the type of compounds and seals we use to ensure they don't fail in the pipeline, in the liquid pipeline.
MR. KRISHNAMURTHY: And just one other point after John's point, is the liquid lines normally offers more flexibility in terms of tools because at least, for example, in a liquid line, you can go to ultrasonics, which is very easy to do. In gas lines, it's extremely difficult to do that. It's a huge operation in fact. So, that's a big impact.
MR. DYCK: Is there a difference in the end result between the liquids and gas?
MR. SAWYER: No. There would be none, other than, say, line cleanliness would be the issue, but magnetics, for example, works -- is not affected by the medium whatsoever.
MR. DYCK: Thank you.
CHAIRMAN HALL: Mr. Wildey?
MR. WILDEY: Yes. I just have one question area for both of the companies here.
I'd like for you to comment a little bit on the interaction between the in-line inspection companies, such as yours, and the operators. Is there a synergistic thing going on, where are they a part of the evaluation of the data, and do you provide feedback to them perhaps on the frequencies of inspections? What can you comment on that area, please?
MR. KRISHNAMURTHY: Yeah. Again, as partof -- there is a lot of synergy. Like Tom mentioned, we get a lot of feedback on different systems and different tools, especially the new ones, quite a bit.
But the part of it where PII is moving in the direction, where we are getting more into integrity management and assisting operators in doing tool selections and providing frequency predictions. Absolutely.
Like I said, it has to be a holistic approach, and absolutely that's something we do, and we are continuing to do that.
MR. PARSONS: Yeah. I think Ravi's hit the main points. I don't have anything to add.
MR. ZIMMERMAN: Okay. Thank you, Mr. Wildey and panel. Mr. Chipkevich?
MR. CHIPKEVICH: For anyone on the panel, just a couple of brief follow-ups.
On the issue of obstacles that would prevent a pig from being operated to the line, other than bends in the pipeline, I guess that would include a bend, either horizontally or vertical because of hills and things of that nature.
What other type of obstacles do you face? Because, you know, the Board's been pushing for internal inspections and the testing of pipelines forsome time, and we do get answers back that a lot of pipelines can't be inspected.
You know, what are some of the other obstacles, and, you know, how difficult is it to change some of these pipelines so they can accommodate the tools?
MR. PARSONS: I would say the biggest single issue would be plugged valves in gas pipelines. They're extremely expensive to replace, and clearly the pigs can't pass through them. So, they'd have to be removed, and in terms of multi-diameter capacity, we, as a company, don't have a lot of those tools. So, we would have to build a new fleet of tools to handle a lot of reduced port valving.
MR. CHIPKEVICH: But there are tools that could be --
MR. PARSONS: We do have tools that handle reduced port valves, yes.
MR. SAWYER: We also have tools that handle not necessarily specifically port vales but multi-diameters in which -- so, any restriction on pipeline inspection is sometimes the availability of traps either not built into the system, and with looping of new systems and expanding the pipeline infrastructure, we have worked with vendors to build tools that willinspect more than one diameter, so that they don't have to spend the money on adding infrastructure which again is costly.
MR. CHIPKEVICH: Would you all have an estimate on the amount of pipeline by percentage is piggable today?
MR. PARSONS: Not really. Don't have a handle on that.
MR. CHIPKEVICH: What about a comparison of pipeline runs? We've had some accidents we've looked at over the years where there was an anomaly in a pipeline at a particular location, and then a subsequent run of that line showed a change in that anomaly.
Is it difficult, when you've got a pipeline that's a thousand miles long that you're examining, to identify and to compare anomalies that you see in a pipeline so you can give that information to the operator?
MR. KRISHNAMURTHY: Again, there are a lot --it is -- it can be done, but it's very difficult. Occasionally, it can be difficult. For example, you look at technology and what you have collected.
In ultrasonics, it's a direct measurement. So, you can do it a lot easily. I mean, if there isvalue, you do it. Especially on an overall integrity management program, there's value because it can assist you in predicting when you need to run your next inspection.
Going back to MFL, the way the data is analyzed, you have a clustering definition in MFL, and because of the change, as time-dependent corrosion happens, there is a change in the clustering. So, next time the analyst looks at the data, he'll cluster the data a little bit differently.
So, it's very difficult to do a direct measurement looking at tool reports and saying which --has it grown or not? But what we do normally is look for specific cases. We use the raw magnetic data and go joint-by-joint and subtract the signals and look for corrosions, and that's one way we overcome that problem.
Again, we don't -- we try not to do that for every defect. We try to do it in areas where we suspect there is excess of corrosion or some sort of thing. So, it can be done, but that's --
MR. SAWYER: Yeah. That technology is available now and was introduced to the marketplace earlier this year. As Mr. Krishnamurthy said, we analyzed the signal match, raw-to-raw signal, whichremoves the operator interpretation uncertainty and goes back to the accuracies of what the tool is capable of. It's raw signal matching.
So, that software is now available and those algorithms are available for all the magnetic technology within PII.
MR. CHIPKEVICH: And just one final question, and that is, the difference in inspecting gas lines and liquid lines.
You mentioned some of the tools couldn't be used, such as the ultrasonic, in a gas line, but what about the other tools? Can you inspect them with the gas lines? Can you get as good of data, and can you do the test without filling the gas line with liquid?
MR. PARSONS: From an MFL perspective, there is no difference between the two. In fact, typically the gas pipelines are easier to get the data because we don't suffer from things like waxing that we might get in a crude oil line. So, technology works very well.
MR. CHIPKEVICH: Thank you very much. Did you have --
MR. SAWYER: Well, the -- on the crack detection technology, as Ravi mentioned, there is a shear wave, which is designed for liquid, and there's a shear wave that's designated in a fluid-filled wheel,and that typically doesn't have the same level of probability of detection or the same level of confidence interval and accuracy that there is for the gas.
There is crack detection technology available. The newer technology is the EMAT technology, as Ravi mentioned, which is due to come out in the year 2002.
MR. CHIPKEVICH: Okay. Thank you.
Thank you, Mr. Chairman.
CHAIRMAN HALL: Okay. We'll move for questions up to the Board Members. Member Carmody?
MS. CARMODY: Yes, thank you.
Good morning. You've had the Technical Panel. You're now having the non-technical questions.
My first one goes to Mr. Krishnamurthy. I was interested in your comments that an integrity management program was crucial to determine what it is you're looking for and then select the tool.
With that philosophy, I would assume that you could use a number of different tools then on one pipeline, depending on what you were looking for.
First, my question, is that correct, and, second, is it common?
MR. KRISHNAMURTHY: Yeah. Absolutely. Thatis correct, and it is common whenever you look at a pipeline, and I have seen a few cases and have been involved in cases where you have corrosion and cracking. If you have corrosion and cracking, you have to look at -- you want to look at your technologies.
But normally, you don't look at your technologies. If -- again, when you're doing an actual risk assessment, you can come out and say this is the most predominant mode of failure, and in terms of risk -- I want to first address that.
So, you focus in on that and address that and come back, reassess and see if my next trend may be a different tool, depending on what I'm looking for. So, it can be staggered that way, too. So, that may be a better way of managing it.
MS. CARMODY: Okay. Thank you.
The training. I was also struck by what you said about the difficulty of interpretation, the difficulty of, I guess, training.
MR. KRISHNAMURTHY: Yeah.
MS. CARMODY: How much training does it require for a typical analyst to be able to interpret data?
MR. KRISHNAMURTHY: It depends. For example, MFL, it could be two-three months, but when you look atshear wave crack tool, it's normally a year's worth of training before we can get them up to speed. So, it's not something you can go out and -- we cannot just hire five people and bring them in. There is intensive training, and there is an experience level.
So, then even though we have base analysts and every analysis is checked by a senior analyst. So, there's a process involved there in order to capture this human element which I talked about. So, there is quite a bit of training, and again it depends on the individual, but it's training, and it can get tough on the folks because it's a very -- it can get very boring, I would say, because they look at like thousand miles of pipeline, and they're looking at every spot. So, it's a very tough job. It's an extremely hard job.
MS. CARMODY: Well, you touched on my next question, which is, I assume you have multiple people looking at particular interpretations. So, you have kind of a consensus opinion on --
MR. KRISHNAMURTHY: Correct.
MS. CARMODY: -- something like --
MR. KRISHNAMURTHY: Yeah. And in something like a shear wave crack tool, it actually goes through three or four people before it gets cleared and because of the complexity of interpretation there.
MS. CARMODY: And that would be before you send it on to the --
MR. KRISHNAMURTHY: Yes, yes, yes. Absolutely.
MS. CARMODY: I went out to the Carlsbad accident with Member Hammerschmidt and with Mr. Zimmerman. So, I have a special interest, I guess, in that one.
I know El Paso had said they could not inspect that particular pipeline with an internal device because of, I think, fittings, pipe fittings on the -- that went over the bridge.
Is there a tool in development or a tool you know of that might be useful in a pipeline like that?
MR. KRISHNAMURTHY: Tom?
MR. SAWYER: I believe it was an issue that was -- it was a couple of issues regarding fittings. I'm not intimately familiar with the specifics. I mean, some technical problems are surmountable, some have physical limitations which you just can't get around. So, I don't know specifically about that particular pipeline, no.
MS. CARMODY: Anyone else want to speculate?
(No response)
MS. CARMODY: Okay. I think that's all forme. Thank you very much.
CHAIRMAN HALL: Member Black?
MR. BLACK: Just a couple of questions, I think primarily about data.
Do you have -- say on a 10 or 15-20-year old pipeline, do you have any idea how many hits, in other words, how many spots need inspection on the data return per mile or per foot or whatever?
MR. KRISHNAMURTHY: Again, see, that would depend on the -- even if you fix the age, it will depend on the type of coating, type of service, type of environment. It's a very difficult question to answer.
Some lines would be one per mile, some may be one every 50 miles. So, it cannot -- it depends on the operating conditions. It depends on -- that's kind of why I would look at that risk assessment or integrity management plan to understand why that pipeline needs inspection.
MR. BLACK: But we're not talking about hundreds of hits per mile. We're talking about --
MR. KRISHNAMURTHY: Again, it depends on the pipeline. You could have pipelines which could be --
MR. BLACK: There's disagreement there or --
MR. SAWYER: Well, no. We've -- in our experience, I think Tuboscope would confer that thereare pipelines that are very old, that are extremely clean in terms of the number of hits, and there are pipelines due to the factors Ravi talked about where we have seen literally millions of significant features.
MR. BLACK: I guess that goes to the next question. With the location, with this inertial navigation system, what is the location accuracy?
In other words, if you're going to have your client go out and dig down, can you get it to the nearest foot or the nearest meter or whatever you're --
MR. PARSONS: Yeah. That's about right. About the nearest meter is typical. It depends a lot on the products in the pipeline and the tortuosity of the pipeline itself, how many bends it's got in it, but typically, less than a meter for a dig, for an anomaly.
MR. BLACK: And this is inspected by -- I did some arithmetic here, and if it's correct, I make it for a 24-inch pipeline, 10 miles of it, is something like 300,000 square feet, and you record that data for the full circumference of the pipe --
MR. PARSONS: Every tenth of an inch.
MR. BLACK: Every tenth of an inch.
MR. PARSONS: Yeah.
MR. BLACK: So, no wonder you're getting terabytes of data.
Has there been any -- are you already using any sort of an intelligent system to scan this data, to try to pick up the blips for you and then have someone look at them individually?
MR. PARSONS: Yes. The initial run through the data is automatic, and it highlights the most significant anomalies for us. So, there's a preliminary grading done by the computer, and then we hand grade from there.
MR. BLACK: I'm trying to ask these in order, and they've sort of come to be scattered.
Obviously from our reports, virtually every accident or incident that we've looked at, the defects are numerous. I don't know whether -- what the percentage is. It seems like from reading this report, almost every one of these incidents had a hit in the area that failed ultimately and caused the leak, and it didn't rise to the level of requiring any more intensive inspection.
What's causing that? Is that just the inaccuracy or the insensitivity of the existing systems or are the operators, the -- what do you call them? The analysts? Why do you think we have this problem?
MR. PARSONS: I think to some extent, in some of the examples given, they weren't necessarily typicalcorrosion-type anomalies. They were mechanical damage anomalies, where third party damage may have caused the incident, and until very recently, we could not even detect mechanical damage, and we now have a prototype so we can do that, and hopefully we'll commercialize that next year.
MR. BLACK: Okay.
MR. PARSONS: The tools have been designed just for straight deformation and corrosion.
MR. BLACK: And just -- you mentioned, I think, in your presentation something about a National Pipeline Mapping System. Is that something maintained by the Government or by the industry or what?
MR. PARSONS: By the Government.
MR. BLACK: It is?
MR. PARSONS: Yes.
MR. BLACK: And, so, your GIS, which, to me, from local government, means GO Information System, that it's the same exact sort of --
MR. PARSONS: Yes, it is.
MR. BLACK: -- system. We use them for water pipes and traffic signals and police precincts --
MR. PARSONS: Yes. Right-of-way management.
MR. BLACK: -- and -- but this system, your system, is more sophisticated, I assume, than this --what I guess is some sort of an inventory.
The Office of Pipeline Safety maintains that?
MR. PARSONS: Yes. DOT?
MR. BLACK: Yes.
MR. PARSONS: Yes.
MR. BLACK: Okay. But this is a far more --you have far more data than they have in their inventory system?
MR. PARSONS: The National Navigation System takes a 100 points a second down the pipeline. So, it is quite accurate, yes, and it exports that data into a GIS package.
MR. BLACK: So, you just -- again, to try to close this out, the problem we have here is we have hundreds of thousands of square feet of return from your inspection, and then sifting out these defects, and then there's a certain degree of inaccuracy in those defects in the first place, and that is what we're dealing with, and then you're working to try to improve the accuracy of the hits.
MR. PARSONS: Yes. We're trying to increase the accuracy of the data we're providing to our customers and the ease with which they can get to that data, and there is so much data, as you said, that it's -- to make a flexible system that allows rapid accessto the database, we believe is quite valuable.
MR. BLACK: Thank you, sir.
CHAIRMAN HALL: Member Goglia?
MR. GOGLIA: Yes, sir. Thank you.
I have a few questions, and I'll bounce them back and forth between the panelists.
Mr. Parsons, you mentioned just a moment ago about the scanning or data processing of the preliminary data that's gathered, and in order to do that, the machine has to have certain parameters that the data would fall within and without to identify you.
Who sets those standards?
MR. PARSONS: We do. What we're trying to do is just identify severe anomalies for the customers to look at very rapidly. So, we would look at their operating pressure and whether we were approaching that operating pressure.
MR. GOGLIA: And do you have competitors in the business? I assume that PA -- how do you say it?
MR. SAWYER: PII.
MR. GOGLIA: PII is a competitor?
MR. PARSONS: There are four major companies that supply these systems.
MR. GOGLIA: And do you collaborate with the other companies on those standards or those thresholds,I should say?
MR. PARSONS: There was a European consortium put together for grading different types of defects, and that's the standard we use in Tuboscope, and I believe PII does as well. It's called the Pipeline Operators Forum.
MR. GOGLIA: Now, do I take from that response that the Europeans have efforts that parallel what we're doing in this country?
MR. PARSONS: I think that standard's been adopted over here, but I'm not aware of a committee that is working on a standard for the U.S.
MR. GOGLIA: And in the general sense, where are the Europeans with monitoring their pipelines as compared to the U.S.?
MR. PARSONS: Do you want to --
CHAIRMAN HALL: Now, we recognize that you all have customers in the audience, but we would appreciate honest answers.
MR. PARSONS: We run about an equal amount of pipe internationally as we do in the U.S. So, I would say there's probably about the same level.
MR. SAWYER: Yeah. Western Europe, we do roughly about -- it's an equivalent type of business. So, they don't have maybe quite the same miles ofpipeline. So, perhaps there is more on a percentage of the pipelines in Western Europe than in North America.
MR. GOGLIA: Okay. Now, I'm not going to begin to try to pronounce your name.
MR. KRISHNAMURTHY: Ravi.
MR. GOGLIA: You may not know the mix of this Board, but I'm the only one from the North, and since I do speak properly, I'm always -- I'm reminded of that. So, I am not going to touch your name at all.
But you mentioned about the qualifications of your analysis people. I wonder if you would take us right from the beginning. When you bring a pig out to install in a pipe, the technicians that do that work, who are they? Are they your employees? Are they contract employees?
MR. KRISHNAMURTHY: I'll give it a shot. Let Tom take it up to data analysis, and then I'll take it over.
MR. SAWYER: Yeah. We have -- most are full-time employees. We take on site typically just a technician or we call them a project leader, project manager, and their job is to ensure that the tool is working properly before it goes into the line.
We sometimes have contractors that assist as laborers in that process, but generally the techniciansthat have electronics and mechanical skills, technologist-type skills, then take the data.
When the tool comes out, they check for completeness of data in terms of what was expected to be collected, and they do summary checks along the line to check for the quality of the data.
If the quality checks and the sum checks are appropriate, the data is then sent back to a data processing center, which there are many, and then it is handed over to an analyst.
Sometimes an analyst will accompany the tool to look at data immediately as it comes out, but it's just a difference of taking the tapes or the tapes or the hardware, the memory, back to the office to be inspected.
So, you can do it on site or you can do it back in the analyst's office. That's just a plain right-away, but we do offer preliminary reports, and I'll leave it to Ravi to go through the analysis process.
MR. GOGLIA: Just one second, please. The manager, the person, your own person that comes out to oversee the actual running of the pig. What kind of qualifications typically will that person have?
MR. SAWYER: He goes through projectmanagement skills. Often, they are people who are engineering level. They're often degreed engineers or they've come up through the ranks as a technologist or technician, and they've gone through project management training. The technicians.
The technicians have internal training capabilities. All of our field technicians have to be DOT -- pass DOT and OSHA testing as well because of the DOT regulations. So, they all have that type of training to be able to work on site as a technician.
MR. GOGLIA: Now, you typically don't dig a hole to put this pig in. The pipe's constructed in such a way that you can insert it along the way.
You mentioned, in response to an earlier question, about waxing and other contaminants that would get on the pipe that would impact the readings.
How many -- typically, how many of these voids would you see, and at what point would you retest, you know? I assume that you're never going to get a 100 percent coverage when you run a pig through. You're going to have voids.
How many voids do you get before you decide you don't need to do it again?
MR. SAWYER: It's generally done in consultation with the operator and looking at all theother factors in the pipeline in terms of, as Ravi mentioned, the integrity issues.
If it is in an area perhaps where there is --it's understood there is good coating, good CP, it's a new section of pipeline, maybe -- you may not go back in or you'd wait till the reinspection interval to kick -- pick up the rest of that data.
Many times, we go in multiple runs to get all the data. That's generally the norm, is you continue to run until you get complete coverage. But you make judgment calls from time to time based on the various factors, and that's in consultation with the operator.
MR. PARSONS: Perhaps one point to add there as well is that it's normal to run cleaning in caliper pigs before running an in-line inspection tool to make sure the line is prepared, and we can get good data.
MR. GOGLIA: I just have a general question on data because you just tickled a thought in my mind.
Sometimes these pipes are in contact with other metal objects that are inadvertently in the hole. Does that impact upon your readings?
MR. SAWYER: In terms of MFL, it -- getting flux leakage, metal gain does affect the magnetic leakage signal, and you do see metal objects near or in contact with the pipe.
Ultrasonic technologies typically are blind to that.
MR. GOGLIA: Okay. Are any of your customers doing this work themselves without your people being present with your tool?
MR. SAWYER: No.
MR. GOGLIA: Okay.
MR. KRISHNAMURTHY: But history was --British Gas and TCPL, two companies, did start it on their own. I mean, so, PII was spun off from British Gas. British Gas had its own inspection division, and, so, that was eventually spun off, but it started out like that. It started that way.
MR. SAWYER: And TransCanada Pipelines in Canada was the other half of the founding companies that have formed PII, and it was developed through those two companies.
MR. GOGLIA: Okay. We've had some discussion about the sections of pipe that you run your pig through, and we've also discussed areas where you cannot use your tool.
What is the process for determining the integrity of that sections or those sections of pipes that you cannot use your tool?
MR. KRISHNAMURTHY: Again, the onlymitigation at that point you have is hydrostatic test. That's one of the options, but before you get to that point, again there is enough technical knowledge in metallurgy corrosion or fraction mechanics that you can sit down and say what is the probability that I will have a problem here, and what is the action I need to take, and these technologies are very well developed for a lot of other industries and in the pipeline industry.
So, there is enough background there to say I have this type of coating, my environment has a lot of water, my CP system is not -- was interrupted at this period, then I have a problem, and, so, you have many other parameters you have to look at, and you can make a very educated, a very good decision.
So, it's not -- the part of it -- the one which is the most difficult anomaly, even to that degree, you can make a good judgment as by the damage, and then you look at depth of cover, and you say where it's located and what kind of activities were happening there.
So, if you go through a process like that, you can make a decision, saying, you know, I may not need to run a tool. I can do a hydrostatic test or I don't need to do either.
MR. GOGLIA: But that third party damage is a big concern.
Well, I have one comment, I guess, more than a question, and maybe any one of you can respond to it, and that gets to the standards, the question I asked a moment ago about standards.
I'm very concerned that we don't have a universal standard across the board. I'm concerned that your industry hasn't sat down collectively to develop such a standard. This is not an immature industry.
I personally received my first training working for the airlines from the pipeline industry and MDT. So, your experience predates much of the commercial aviation side in non-destructive testing, and yet I'm disappointed to hear that you don't have a standard, and you haven't said -- there hasn't been any efforts to set one.
So, thank you very much. No further questions, Mr. Chairman.
CHAIRMAN HALL: Member Hammerschmidt?
MR. HAMMERSCHMIDT: Okay. Thank you.
I have a few follow-up questions on many other questions that have been already asked. Following up on some of Member Goglia's questioningconcerning pipeline operator personnel being on scene with in-line inspection equipment personnel, when a suspect portion of pipe is identified, and the pipeline operator wishes to, say, dig down and inspect it first-hand, are there people from the -- from your companies that accompany the pipeline operator out to that site to more or less provide synergy, as Mr. Wildey put it in his questioning, and also to be there to validate those data discriminations?
MR. KRISHNAMURTHY: Yeah. Again, absolutely, especially again -- this is especially true if you're looking at very unusual situations. We look at data interpretation, and the data interpretation is very difficult or is very complex corrosion or deep cracking, and absolutely.
In-line inspection, appropriate people from the company will be there. Head analyst will be there or the analysis people normally will be there.
MR. SAWYER: If requested. There are cases where there is not. It is done without a joint, but it seems to be more of a common practice now that we are on site during the excavation and validation.
MR. HAMMERSCHMIDT: Okay. Thank you.
And following up, I believe, on one of Mr. Dyck's questions concerning limitations on using thisin-line inspection technology, what is the smallest diameter that you can use this technology, and what is the largest diameter pipeline?
MR. KRISHNAMURTHY: I'll give you numbers for certain types. It is six inches and higher for most of the tools. Again, I'm talking high-resolution, okay, and there are tools smaller than that, also, but they become what we would classify as standard resolution, separate set of tools, but most -- from six inches upwards, you can inspect, but like I mentioned, the crack tools, the ultrasonic shear wave has a limitation of about 16 inches diameter.
MR. HAMMERSCHMIDT: Okay.
MR. KRISHNAMURTHY: But most of the tools, you can go down to six.
MR. HAMMERSCHMIDT: I know in your presentation, you included many diameters, but I was just curious what the very smallest diameter was.
MR. PARSONS: Yeah. I beg to differ with Ravi. We have a three-inch high-resolution MFL tool. So, we go down to three inches.
MR. SAWYER: And the circumferential tools are currently available down to 12-inch, and they're being developed for 8 and 10 for 2001 on the circumferential magnetic tool, but they're available as-- the upper side is typically 56 inches on the upper limit.
MR. HAMMERSCHMIDT: Okay. Thank you.
And in response by Mr. Parsons to one of Mr. Chipkevich's last questions, I didn't quite catch the answer, but Mr. Chipkevich asked what is the most prominent problem for using in-line inspection devices in gas pipelines, and you said something. I didn't quite hear that.
MR. PARSONS: Valving systems, typically.
MR. HAMMERSCHMIDT: Valving systems?
MR. PARSONS: Yeah.
MR. HAMMERSCHMIDT: All right. Would you have any estimate as to how -- what percentage of the pipeline in the U.S. would have systems that would prevent using the in-line technology, I mean, through your work with pipeline operators?
MR. PARSONS: No.
MR. HAMMERSCHMIDT: You have no concept on that?
MR. PARSONS: I wouldn't say no concept, but I think I'd rather our customers give you a better number on that.
MR. HAMMERSCHMIDT: Okay. Thank you.
And also, Mr. Parsons, I enjoyed very muchyour presentation, in fact, both presentations, but on this smart mapping, that, I thought, was very impressive. Now, is this technology that's in use today?
MR. PARSONS: Yes, it is.
MR. HAMMERSCHMIDT: Okay. And how widespread is it being used?
MR. PARSONS: We launched the product this Summer. So, it's pretty limited right now, but the use of it is growing.
MR. SAWYER: I think several of the vendors, if not all of them, now have a GIS platform and inertial mapping capabilities. It's been widespread for as long as -- the inertial mapping has been around since the late 1980s.
Integration, full integration into GIS really occurred in the late 1990s. As I say, we -- these inertial mapping systems are -- data can be integrated into any GIS platform, you know. Those are other vendors that build the GIS, typically a different platform, but I think all the vendors have mapping, what we call inertial measurement unit mapping or INS mapping.
MR. HAMMERSCHMIDT: Right. Thank you.
And the last question, I know this has beenasked, I think, at least twice so far, but concerning this major problem that exists in this country that causes pipeline accidents, and that's dents and gouges on the outside of the steel pipe, currently, can in-line or in-line inspection tools discover those type of pipeline problems?
MR. PARSONS: From our perspective, we have a full range of tools that can detect physical dents, but sometimes that isn't the only issue. Sometimes the dents are rerounded by the line pressure, and, so, you can't see them with a simple caliper-type device. You have to look at the structural changes in the steel as well.
MR. SAWYER: The circumferential technology is very sensitive to stress changes that are related to dents and gouges as you referred to them as, and we're finding in some recent projects here in the U.S., we're having a very high success rate of even discriminating dents, planar dents and cracks in dents, which are far more critical.
So, the technology exists. We do need to refine it and quantify it to get -- increase the confidence level and to increase the discrimination, and that would be an area where we would invest R&D money to do just that.
MR. HAMMERSCHMIDT: Okay. Thank you. That's all I have.
CHAIRMAN HALL: Thank you. Thank you.
Gentlemen, I appreciate all of you all being here. Did most of you all fly to be here?
MR. PARSONS: Yes, we did.
CHAIRMAN HALL: Everybody did? Well, I guess you take comfort in the fact that the integrity of your airplane is looked at under federal regulations about every 15 months, and on a piecemeal basis, and then the whole structure is inspected, I think Member Goglia's really the expert in this area, but approximately 10 to 12 years, depending on the aircraft.
How often do you think pipelines should be internally inspected?
MR. PARSONS: Depends an awful lot on the product and the temperature, the type of steel, the type of coating. It's extremely variable.
CHAIRMAN HALL: Goes, I guess, to the risk assessment, Ravi, that you were talking about?
MR. KRISHNAMURTHY: Yeah. Yeah. Again, see, -- and I'll tell you why it is dangerous to inspect it too often, and it's not dangerous. It's not value-added. You intend to make decisions.
For example, let's take an example I'm veryfamiliar with, that's cracking. If you look at SCC or stress corrosion cracking, and you run a tool year one, and then you run it every fourth year or third year or fifth year, the cracks will not have grown substantially for you to discriminate it with a tool. It doesn't add value. It potentially may not.
So, you have to model it to understand it may be a seven- or an eight-year period may be more appropriate in that case or you may have a corrosion which might grow in a certain area very fast, and a three-year inspection may be more appropriate.
So, there is a huge amount of technical background and corrosion and fraction mechanics which we have to bring to bear on this to appropriately address it. Inspection done in isolation, we run the danger of not doing what is right for the reliability of the line.
CHAIRMAN HALL: Well, do you think a piece of pipe that's been in operation and not inspected for 40 to 50 years, should that -- is that something that should in your mind be permitted or should that pipe be replaced if it has bends and cracks where it cannot be inspected?
MR. KRISHNAMURTHY: Again, --
CHAIRMAN HALL: Obviously I'm talking aboutan investigation we presently have on-going out in Carlsbad, New Mexico, where you had some of the pipe that had never been inspected in the entire time that it had been in the ground, and -- or been in operation.
MR. KRISHNAMURTHY: Again, in our -- I go back to what I -- there are lines which are operating at 50 percent or 20 percent of yield in some cases, extremely low operating pressures, and those are scenarios where maybe inspection right away is not the answer. Maybe we should do a few excavations to say do I have a problem, do I have an external problem? I need to do some actual MB to understand is there an internal problem?
Then you can make the right decision. Again, you could go either way on an issue like that. So, --
CHAIRMAN HALL: You know, we have the technology available now, and as you know, we have a lot of pipe in this country that's grandfathered in that there's no inspection at all.
Let me ask you in regard to Europe and overseas. You all operate worldwide?
MR. SAWYER: Yes.
CHAIRMAN HALL: And I'll be the one to say that it's my observation, going and traveling in other countries, that many of the countries in the world,particularly in Europe, are ahead of us in this area.
What are the things that you think we could learn or we should be doing in this country based on your experiences overseas?
MR. KRISHNAMURTHY: Again, I'll attempt to make a comment without offending anyone, but again, the complexity of the pipeline --
CHAIRMAN HALL: Well, we guarantee that none of your customers will leave as a result of any of your comments.
MR. KRISHNAMURTHY: Yes. The complexity of the pipeline networking, again in my brief understanding of U.S. and Canada, U.S. is by far the most complex system. Okay. The complexity here cannot -- I don't think it's matched anywhere else in the world.
Now, again, as a virtue for fewer incidents, the Canadian industry, I believe, is ahead of -- a couple of years, a few years ahead of where the American industry is going to eventually get, and there, it was driven by a few incidents and a very, very systematic approach of integrity management and doing it.
If there was a place where I think we can learn something from is the Canadian industry. It's anopinion of mine, yeah. It's not shared by PII.
MR. GOGLIA: And do they have a set of standards?
MR. KRISHNAMURTHY: Pardon?
MR. GOGLIA: Do they have a set of standards for --
MR. KRISHNAMURTHY: Yeah. Again, they have the follow-up principle of integrity management and looking at inspections and aggressively pursuing technologies, where appropriate, and, see, the danger in going after everything is it becomes a shotgun approach. We have to be very focused in a very systematic fashion to address it, and that's kind of what they've attempted to do, and they're still continuing to do it.
MR. SAWYER: There was a panel group in Canada which was between vendors and pipeline operators, in which they worked with the Canadian Standards Association to develop some broad guidelines.
However, it is not as detailed as perhaps you may think in terms of data analysis and defects as perhaps the operator, the pipeline operator's forum worked on in Europe, for example.
So, there has been varying degrees of work on standards in different parts of the world.
CHAIRMAN HALL: Mr. Parsons, any comment?
MR. PARSONS: I guess the only comment I'd add to that is that we are not without standards entirely. All our new tools have been tested in a third party pipeline, in a blind test, that some of our customers provided samples for us to run our tools in.
So, we don't know what they put in those samples. So, we are qualifying our tools to a standard, and it is tested by a third party.
CHAIRMAN HALL: Okay. And you mentioned that you all were doing some research and development. Is that funded entirely by your company or is there any industry or government participation in the R&D that either of your companies do?
MR. PARSONS: From our perspective, about 80 percent of the funding for R&D comes from our corporation, and about -- the remaining portion has come through FERC funding through GRI.
CHAIRMAN HALL: Okay.
MR. SAWYER: We've been involved in both GRI-related funding but most comes internal. We do have joint projects on specific tools, where the industry has funded them directly and shared a portion or a substantial portion of that specific tool development.
CHAIRMAN HALL: One last question. We havehad a number of accidents, some that Rod referred to in his earlier presentation, where anomalies were found, and they weren't dug on, and then a catastrophic event took place.
You know, do you all leave that obviously to your customer to have to make that hard decision or where do you all come in on the decision of whether to dig and replace or not?
MR. KRISHNAMURTHY: As I mentioned earlier, we are in the direction where we believe it's synergistically useful. There's good synergy there for us to get into an area where we assist the customer with pipeline integrity management, where we would assist them in making those calls.
So, I believe there's a huge advantage for us to get into -- for us to do that, because we can turn around and go to our analysis folks and say, you know, we need to look at this more carefully or there's a signal we missed, or go to R&D Division and attempt to improve a few things.
So, we are headed in that direction. We are not there at this point. We are doing quite a bit of that in different parts of the world, and in U.S., we're starting to do t hat at this point.
CHAIRMAN HALL: Well, you all have been avery informative panel. We appreciate greatly your participation and your candor, I think, and I do want to encourage everyone that PII's inspection tool is set up outside the building. So, when we take the break, I'll -- I think we'll all try to go up and take a look at that.
We hope that some of the Board's recommendations will increase your activities in the United States, and we certainly hope and encourage you all in your work and in -- as Member Goglia's pointed out, getting some standards set for your industry.
We will take an hour break. We'll return at 1:30 promptly. We will -- the gavel will come down at 1:30.
Let me tell you that upstairs are a number of fast-food places that you can get lunch. In addition, there is a CVS that has antacid pills and other things available as well.
But we will be recessed for one hour and reconvene at 1:30.
(Whereupon, at 12:32 p.m., the hearing was recessed, to reconvene this same day, Wednesday, November 15th, 2000, at 1:30 p.m.)
A F T E R N O O N S E S S I O N
1:32 p.m.
CHAIRMAN HALL: We will reconvene this Pipeline Safety Hearing.
Again, we greatly appreciate the presence of the individuals that are here observing this hearing, and we now will go to our second panel on Integrity Assessment, and I'll ask our Hearing Officer, Mr. Kris, if he will please introduce the panel.
MR. KRIS: Thank you, Mr. Chairman, and Members of the Board.
The next panel is the Integrity Assessment Panel. On this panel is distinguished consultant, Mr. Noel Duckworth, and Dr. John F. Kiefner from Kiefner and Associates.
Panelists, I would like to remind you that you have 15 minutes to give your presentation. The yellow light in front of you will go on when you have two minutes remaining. The red light indicates that your time is up.
Mr. Chairman, staff is ready to hear the presentations.
CHAIRMAN HALL: Okay. Well, gentlemen, let me first say welcome. It's nice to have two distinguished individuals. My only question before youbegin is are either one of you gentlemen as distinguished as Charles Batten? For those of you who know Charles Batten, you can answer that question easily.
All right. Please proceed. Who's going first? Mr. Duckworth?
MR. DUCKWORTH: I think so, sir.
MR. DUCKWORTH: While they're bringing the slides up, I just wanted to tell you that my basic presentation will be more in line with utilization of the devices described heretofore by -- so eloquently by the people in the pigging business, and to try to get -- move a little bit closer to the ditch, so to speak, in terms of assessment.
The currently-available in-line inspection equipment can be described in three general categories: those related to physical deformation of the pipe, those related to utilizing magnetic flux to determine locations of metal loss, and those using ultrasonics to define methods of manufacturing defects, metal loss, and welding defects as well in some cases.
I won't dwell a whole lot on the limitations so much and the capabilities of this equipment but how it can be practically used in the field, and so thatyou can really understand what's available to you as a tool.
In the first category of deformation, that can be further broken down into three types of devices. The first device is a caliper-type pig that is usually a single channel of data information, and it is direct recorded, and it is typically used to prove up the integrity of a new construction effort or to identify anomalies, physical deformation anomalies, in an operating pipeline that would prohibit or cause damage to one of the more expensive ILI tools that would be used.
The second one is more or less a conventional tool. It typically has sensors that are about three inches in width around the circumference of the pipe. So, typically if it's a 16-inch pipeline, for example, these will be looking at 3-inch widths around 16 samples around the pipe, and also the resolution along the pipeline is more akin to three-quarters of an inch. In some cases, down to a half an inch sample rate.
So, this would be conventional resolution in the deformation sense, and then we have the high-resolution deformation, which is taking a sample rate approximately every tenth of an inch along the pipeline, and it can be many, many, many channels,typically three-quarters of an inch wide or less around the full periphery of the pipe.
So, the basic difference in all three is resolution. How much resolution do you want? How much do you want to pay for?
The next general category is magnetic flux, and it's divided into three categories, and as you heard the gentlemen talk this morning, they are -- they also come in varying degrees of intensity or resolution, and the first one is what is called the conventional pig, and it's lower in resolution, many, many less channels, and the magnetics aren't nearly as strong, and then you have the high-res longitudinal flux fields, and the high-res transverse flux fields. Both have hundreds of channels, very good resolution, and they are very definitive.
The conventional tools have served us well. They are quite hardy. Their capabilities are well known in the industry. I don't think that they're dead yet, just because the high-resolution tools exist, and as was mentioned earlier, this could be a determination from the actual integrity assessment planning process as to whether you would need a conventional or a high-res tool.
And the last category is ultrasonic, and asalso stated this morning, the ultrasonic tools bring with them a significant capability in just straight compression wave that describes metal loss-type defects, such as corrosion, internal or external, or manufacturing defects contained within the wall of the pipe, such as laminations, and these -- and also, I must add that the compression wave tool does a very good job of describing dents. It doesn't describe gouges within dents sometimes, but it does describe, and you're able to visualize dents, and it's a very useful tool when doing -- locating dents, but it does not evaluate dents.
The shear wave tools, and there was a lot of discussion about them this morning, one of the things that I want to point out to you about shear wave is that there's a practicality issue here in that the time -- from the time you run the pig until the time you get the results, it can be quite a long time. They can get back to you quickly on serious defects, but to get a complete analysis usually takes quite a long time.
But in many cases, when you select that tool, you have a serious problem, and in order to solve the serious problem, it's quite often prudent to bear the cost of time.
Next, I want to talk to you about secondaryanalysis techniques that I think have been very useful in the industry. This is something that maybe the pigging companies don't push quite as much as some of the other of us, and I just want to point out that a significant percentage of the failures, and especially the catastrophic failures, in the United States, in recent times, has been due to third party damage.
A significant percentage of the third party damage has occurred on top of the pipe, and, so, therefore, if you looked at all indications occurring on top of the pipe, then you could say that you could remove or have the opportunity to remove a significant percentage of the failures by using just the concept of secondary analysis. If it shows up on the top, you need to look at it.
Now, the reason I say that is if you ran, for example, a conventional pig or a longitudinal flux MFL pig, it would not be descriptive of a longitudinal impact-type gouge. These longitudinal long impact-type gouges are very dangerous, and they fail.
We have seen in many occasions where the pig did not do a good job in those categories. However, had you ran a transverse pig, you would have seen it. So, even if you didn't run transverse, and you got just a little small indication, then the recommendation isthat you dig it, and you look at it, and you understand for sure what caused it.
Another secondary analysis technique that I use, and that I think is very, very important, quite simply put, if nothing changes, the pipe is not going to fail. It will be okay. You can rest assured about that. But if something's changing, then you need to understand why.
So, when I try to help people understand their pipeline better through utilization of log data, I hone in on change. I'm looking for change. Change is important, and I'm always looking for even subtle changes.
It was mentioned this morning that it's very difficult to evaluate sometimes. That's true. But if there's been a true change, and you can ascertain that there is a change or you can develop a trend, then it becomes very, very useful in maintaining and especially assessing the integrity of an operating pipeline system.
I was asked to talk about what's in the future in the pipeline industry, and I know that you will have some very qualified people, you already have had, and you will later on today, that will talk about development of new tools, but I think the greatestopportunity is better utilization of the ones that we have.
There is no panacea. There is no single tool that would do it all. Quite often, one tool -- the information fed back or the lack of information fed back from one of the devices will lead you to another and possibly even to a third one, and my opinion is that let's learn to do better with what we have, and that should be a significant development effort.
I think integration of data, whether it's integration of the data from a previous run to current data or if it's between the axial and transverse or from high-flux density to low-flux density, that -- and information of deformation, all -- integration of all of the elements that you can identify becomes extremely important, and then through the INS systems, you can integrate that further with the use of GPS into all of the other GIS data, and I mean all of it, from environmental to whatever comes in a database form, you will be able to integrate the pig data as previously described into that and into all of the other integrity management and risk evaluation concepts that are being utilized.
That's basically it. Thank you.
CHAIRMAN HALL: Thank you very much, Mr.Duckworth.
Dr. Kiefner, please proceed whenever you are ready.
DR. KIEFNER: All right. Thank you, Mr. Chairman.
My presentation is going to describe some of the methods that pipeline operators use to verify the integrity of their systems, and it includes a little bit about hydrostatic testing as well as in-line inspection, and I think some of the things I say will be -- you may have heard already, but it's probably worth repeating, I hope.
First of all, transporting natural gas, crude oil and refined products involves some inherent risks, but objective comparisons of the data show that this is still the safest mode for transporting these commodities.
Federal regulations and industry safety codes and recommended practices provide guidelines for the safe design, operation and maintenance of pipelines, but pipeline operators still have to continually monitor and assess the condition of their pipelines to prevent them from being seriously degraded by things like corrosion, damage from outside forces, which includes excavating equipment, and operational wear andtear, and I'll describe some of the more important preventive and mitigative techniques.
First, I'd like to say that my definition at least of pipeline integrity is you want to assure that there are no leaks or ruptures, and by accomplishing that, we can prevent damage to people and property and the environment.
Pipelines are designed initially with factors of safety against rupture or leakage. The materials are made according to standard specifications which assure accurate dimensions, minimum strength levels, and adequate levels of other performance characteristics. The verification of pipelines is done by highly-trained personnel in accordance with proven practices.
An anti-corrosion coating is installed to protect each piece of pipe and the field joints, and prior to being placed in service, pipelines are subjected to rigorous inspection and an in-place hydrostatic test.
The pre-service hydrostatic test to a minimum of 1.25 times the maximum operating pressure either eliminates defects that might cause an immediate failure or assures that they don't exist, and after the pipeline is placed in service, it's subjected tocathodic protection to protect it from corrosion.
The effectiveness of the cathodic protection is monitored periodically, and the rights-of-way are marked and patrolled at regular intervals to prevent the chances of excavating equipment coming in contact with the pipe.
In spite of the use of quality materials and good construction practices and the prudent monitoring of the pipeline, not all degradation is preventable, unfortunately, but pipeline operators, as you've already heard this morning, have a number of tools at their disposal to assess and, if necessary, counteract the potentially-degrading effects of corrosion and outside forces and operational wear and tear.
These techniques can be effective at preventing leaks and ruptures, but their universal use is not going to assure that we don't have any accidents. It won't prevent all accidents. It's necessary to inspect all pipelines, but you can't really do all pipelines, as I'll explain. There are some that are not piggable, and you can't inspect for all modes of deterioration.
The principle embodied in hydrostatic testing, for example, is that if you raise the internal pressure above the operating pressure with an inertfluid present, like water, it will either cause injurious defects to fail or it will prove that they don't exist.
The larger the ratio of test pressure to operating pressure, the more confidence one can have that no injurious defects remain in the pipeline. But there are some drawbacks. For example, whole pipeline segments would have to be tested even though the serious defects are only in isolated locations.
The logistics of procuring water and safely disposing of it are a big problem and would be a problem if pipelines were tested nationwide, and the time out-of-service would be unacceptable to customers and to users of the pipeline.
The other thing is that defects are found and removed only if they leak or rupture during the test. Those that do not leak or rupture are going to remain, and they may possibly continue degrading after the test, and a test has no value with any defect that's created afterwards, after the test that is.
Hydrostatic testing will continue to prove useful in specific situations, but alone it's not the universal answer to revalidating pipeline integrity.
In-line inspection involves propelling an instrumented tool through the pipeline while it remainsin service to interrogate the pipe material, the seams or the girth welds, for the presence of injurious defects.
The principle in-line inspection embodies universal coverage of the whole system. Minimal or no disruption to service. The ability to locate and characterize the problem defects before they can cause leaks or ruptures. But, unfortunately, in real practice, these tools fall somewhat short of this ideal concept for a number of reasons.
Pipeline operators know, for example, that the metal loss tools, and I think this was discussed this morning, will only reveal metal loss within plus or minus 10 percent of the wall thickness and will do so only about 80 percent of the time with high probability.
The rest of the time, some flaws will become -- will be mischaracterized, and others which fall below the detection limit will not be detected, and yet those flaws will grow at some point in time or perhaps will grow, and that brings on the need for future inspections.
Geometry tools, which Noel has talked about, are available to detect dents and buckles and other diameter restrictions, and I think you've already hearda little bit about the problem with that.
A pipeline operator may be faced with a choice of either excavating a large number of dents to see if they contain cracks or stress risers or using a second type of tool, such as a metal loss tool or a crack detection tool, to learn more about the nature of each dent.
Ultrasonic shear wave technology is pretty good for detecting cracks and seam welds. It's had a pretty good track record so far. It's probably less effective with stress corrosion cracking because of the raise of cracking and the fact that there are numerous false calls, and, of course, the embodiment that's used in a gas pipeline is the one which has the wheels that contact the pipe, and it's not as efficient as the fluid-filled or liquid-filled pipeline.
The latest embodiment of in-line crack inspection, you've heard a lot about already. That's the transverse flux leakage tool, and I believe at least that more experience is needed to assess its true capabilities, but it certainly is capable of finding some types of crack-like anomalies.
Now, limitations, you've heard about some, but I want to review these nevertheless. No one tool is adequate, I think we've heard that before, forfinding every type of defects. Multiple runs involving different technologies may be needed to validate integrity when multiple types of defects are present.
Follow-up excavations are necessary to evaluate tool performance, and high confidence can only be achieved if you've done a statistically-significant number of anomalies.
The pipeline operator can expect that some excavations will be done which lead to only minor imperfections, and it's not a waste of time because you need to do that in order to assure that all necessary repairs are made.
A successful in-line inspection program depends not only on good tool technology and service but on a pipeline operator's commitment to make the necessary digs and repairs and to follow up with future inspections when needed.
Alternatives to hydrostatic testing and in-line inspection will be needed. Operators of unpiggable lines need time to develop -- to make their lines piggable, if they can be made piggable, and pipeline operators who operate low-pressure systems, those lines may never be piggable in the conventional sense because when you fall below, say, about 400 psi, it becomes difficult to get uniform performance or ifthe pressure differential because flow is low cannot be more than 50 psi, you'll have erratic performance and poor data.
Now, I'd like to point out that the industry is making a strong commitment to assuring pipeline integrity. The industry standard for managing pipeline system integrity, and this is the API Standard 1160, which we're developing at this point in time, has the following statement: "The goal of the operator of any pipeline is to operate the pipeline in such a way that there are no adverse effects on employees, the environment, the public or their customers as a result of their action. They do this while they fill the needs of the customer and earn a reasonable return on their investment. The goal is error-free, spill-free, incident-free operation of the pipeline."
I believe that pipeline operators are in the best position to assess the integrity of their system. Prudent operators rely on risk assessment principles and specific risk algorithms, and over a period of time, they learn from these assessments and improve upon them.
I strongly support pipeline operators who have made the necessary commitment of resources to assure pipeline integrity, and I challenge those whohave not to step up to the plate.
Thank you.
CHAIRMAN HALL: Proceed.
MR. ZIMMERMAN: Thank you, Mr. Chairman.
I will start the Tech Panel questioning. First to Mr. Duckworth.
MR. DUCKWORTH: Yes, sir.
MR. ZIMMERMAN: We've heard that there are limited number of tools and trained personnel and in-line inspection available.
With the advances made in magnetic flux inspection tool accuracy, will low-resolution tools still be viable alternatives to accomplish the inspections that will be required by both regulation and industry risk management needs?
MR. DUCKWORTH: I think the risk management issue and the integrity issue, the integrity plan, is going to be the governing element. I don't think that there's room for saying what is the minimum I can get by with, but I don't put this technology in that minimum category.
It just happens to be one that's been around a long time. It's served us well, and it can be very definitive in certain circumstances. In other circumstances, it's not so definitive.
So, I don't think there's a simple answer to that, Cliff. It's a complex question, and it's going to be an individual but complex response.
Yes, there's room for the tool. It's not going to be as widely used as it has in the past. It's probably going to be phased out somewhat by the higher-resolution devices because they can just do a better job on more things, and, so, you would want to get it done in one run, so to speak, or maybe just two.
MR. ZIMMERMAN: Thank you.
Mr. Kiefner, your thoughts on that same subject.
DR. KIEFNER: I believe that the standard resolution tools will still be used, and I think that it simply requires that perhaps you do more digs, more verification in that case to establish the confidence level. But they're still going to play a role.
MR. ZIMMERMAN: On hydrostatic testing, what has been your experience on the effectiveness of hydrostatically-testing pipelines in regard to creating or growing defect flaws that then eventually grow to failure under normal pipeline operating conditions?
DR. KIEFNER: It is possible for defects to grow during a hydrostatic test and not fail. That does happen. Our experience suggests that there's a verylow probability that the remaining strength of that kind of flaw will be lowered significantly. It might be lowered slightly.
On the other hand, as cycles of pressure are applied to a pipeline over a long period of time, then defects that are even too small to fail on the test might grow. So, cyclic pressures will cause defect growth over a period of time.
MR. ZIMMERMAN: How common is this type of occurrence that you actually create these defects during a pressure test? Have you had a lot of experience that shows that they are created often?
DR. KIEFNER: Well, if you're referring to the thing that we call "pressure reversal", where a defect actually grows during one cycle of the test, and then it won't sustain that pressure level again the next time, that does happen, but there's no clear evidence that that would significantly cut into the margin of safety guaranteed by a test.
MR. ZIMMERMAN: Okay. I'm going to pass the questioning to Mr. Dyck.
MR. DYCK: This is a question for both panelists.
What is it that would make a line unpiggable?
MR. DUCKWORTH: I -- that was somewhat statedthis morning, but basically the reduced conduit valves, such as plugged valves or reduced diameter valves, tight bends, wall thickness, changes in those really tight bends.
There -- and in terms of magnetic flux leakage, the -- there can be wall thicknesses in excess of the capability of the instrument to magnetize, and, of course, in the ultrasonic category, there has to be a liquid present or you use one of the other devices that then aren't quite as effective, and the other limitation is the presence of debris in the compression wave or shear wave ultrasonic systems that causes spurious signals.
DR. KIEFNER: I don't think I could top that.
MR. DYCK: Do either of you have an idea of how much of the pipeline system is unpiggable?
DR. KIEFNER: Well, I've got some numbers for hazardous liquid pipelines, and I've been informed that Mr. Andrew Drake, who will speak later, has the numbers for the gas pipelines.
But currently, 85 to 95 percent of the interstate hazardous liquid lines are capable of being pigged, and during the past 10 years, about 50 percent of those have been inspected.
MR. DYCK: Okay. One more question for me. Would either of you like to add anything on the differences in running these inspection -- these in-line inspection devices through hazardous liquid lines versus gas lines, and whether there's a difference in the end results?
MR. DUCKWORTH: I can comment to that. I've run the instruments in a lot of gas lines and in a lot of liquid lines, and the things that weren't said this morning, the liquid lines quite often lubricate well, and it makes it easier to run long distances, longer distances, whereas sometimes a dry gas line would be --there would be more wear, just abrasive wear, on the equipment.
So, other than that, the general statement is if the tool makes it to the end in good shape, a magnetic tool or a deformation tool, it doesn't know what environment it was in, and the same comment. It doesn't work well in gas lines. The ultrasonic pigs don't.
MR. CHIPKEVICH: I just have one question, and that is for either of you or both of you, and that has to do with hydrostatic pressure testing of a pipeline.
One of the issues that comes up is that in an older pipeline, that if there is a crack or some typeof defect that is dormant for a period of time, that if the line is then pressure tested, that it will then --it could possibly energize that crack or fail at a later time when it goes through cycles.
Do either of you have any comments on that, and is that a valid concern, or is that -- are there cases where those lines should be pressure tested anyway?
DR. KIEFNER: Well, I believe that there is some risk that a very deep short defect will become a leak, where it might not have leaked readily and may not leak during the test, but it might become a leak shortly after the test.
It would be extremely rare for a defect like that to survive and then rupture after a test at the operating pressure, though.
MR. DUCKWORTH: I concur.
MR. CHIPKEVICH: Thank you.
CHAIRMAN HALL: All right. We'll move up here to the Board. Member Carmody?
MS. CARMODY: Thank you.
This is for -- first, this is for Mr. Duckworth, please. You mentioned that sometimes there would be a long time elapsing between the time an inspection was made and the results. I think you saidin a situation with the high-res, it would -- perhaps the information would be available soon, but in other cases, it would be a long time.
Could you give me an example of what a long time is? How long would a company have to wait to get this information?
MR. DUCKWORTH: I made that statement specifically with regards to the shear wave ultrasonic system, and what I want to point out and make sure you understand that this is an extremely complex system. There is a tremendous amount of data that has to be manipulated, and it's very serious data that we're manipulating.
This type -- the type of data that we're talking about here is the type that causes catastrophic failures. Usually doesn't leak. These are the bad guys that we're going after with these types of systems, and I've been given the example that even though they provide interim information about the more serious of the serious defects along the process, that it could take up to a year to get the final information on, say, a 100-mile section of 20-inch pipeline. I've been told that. I don't know that firsthand.
MS. CARMODY: Would that be because of human or technological limitations?
MR. DUCKWORTH: It's extremely intense, and they describe to you -- Ravi described to you several levels of management of that data, and the reason is that they're getting it right.
Now, they hope that they will be able to let the machines do it, the computers do it more and more in the future, but right now, there's so much risk developing algorithms that are foolproof, that they don't want to take the chance, and they're doing the right thing.
MS. CARMODY: You also mentioned that if there was no change, there was no problem, but if there were a change, that would suggest something had occurred.
Do you mean a change between the last inspection and the current one? Something that was different?
MR. DUCKWORTH: Well, that's a very simple thing to say, you know. This can't blow up unless it can change, and, so, it's a quite simple thing to say, and I use that simplistic form to point out that we can talk a lot about high technology and new development, and when we have to walk over some of the obvious things in order to get to that high-tech utilization, and my philosophy of making sure that we're pulling asmuch out of what we have is what I offer the clients that I work with.
MS. CARMODY: Hm-hmm, hm-hmm. And then a question for Dr. Kiefner on hydrostatic testing. I'm not quite sure I understood when you first mentioned it.
Did you say that it was done on pipes always before they're put in service?
DR. KIEFNER: Yes, that's correct.
MS. CARMODY: Okay. Is that done on all pipes before they're put in service?
DR. KIEFNER: Yes.
MS. CARMODY: Has that always been the case?
DR. KIEFNER: No. It's certainly been the case since there have been federal regulations, but it was also common practice as early as the late 1940s and early '50s for pipelines to be hydrostatically tested.
MS. CARMODY: Do you have any idea of what percentage would have been hydrostatically tested of the pipes that are out there now?
DR. KIEFNER: All I could say is a guess that a high proportion of them have, but I really can't say.
MS. CARMODY: Okay. Thank you.
CHAIRMAN HALL: Member Black?
MR. BLACK: Thank you, sir.
Just a couple. You mentioned that multiple runs with different sorts of sensing devices were needed to address these. I thought I heard some of the people say earlier this morning that very seldom were there multiple runs with different sensing devices, is that true?
It sounds like it would be desirable, but how often is it done?
DR. KIEFNER: I don't know exactly how often it's done. The most common pigging, of course, is for metal loss, and that has been the case for 30 years or more, but in recent times, because we have the new technology, there are operators who have run two or three types of tool in a given pipeline.
MR. BLACK: Okay. But you don't have any idea about frequency?
DR. KIEFNER: I don't know how often it's done or in case of repeat runs, in some of the newer technology, we're not to that stage yet.
MR. BLACK: Okay. Thank you.
And then to either of you. Do -- I assume there are significant events that occur in a system, over-pressures that are a result of failure of the component or failure of an operator.
Do companies routinely check their systemafter they've had an over-pressure event of some sort?
MR. DUCKWORTH: I don't think that -- I think they do a lot of things when they have a -- they go through a lot of procedures when they have an over-pressurization, but I can't recall a situation wherein, at least in the last couple of years, where that provoked them to run a tool.
MR. BLACK: How about a hydrostatic test?
DR. KIEFNER: I don't think that would be done routinely, and I guess depending on the nature of the over-pressure, that in itself might be kind of a test of the system. Not the kind you want, but --
MR. DUCKWORTH: Mr. Black, I'd like to comment, also, about the multiple run situation, to give you some idea of the level of utilization of these types of tools that's going on right now in the United States.
Many people are proceeding to utilize multiple tools on a regular basis. I'm involved in four projects now, and all four of them requiring two and sometimes three different types of pigs to be run.
MR. BLACK: Excellent. Thank you, sir. Thank you, Mr. Chairman.
CHAIRMAN HALL: Member Goglia?
MR. GOGLIA: Yes. I'd like to follow up onthat a little bit with -- I guess I would call it mapping, the work that's being done now.
The data that's collected in subsequent inspections, are we comparing them?
MR. DUCKWORTH: Yes, sir.
MR. GOGLIA: Routinely?
MR. DUCKWORTH: Right. There are several --the pigging companies themselves are doing it as well as there are third party companies. There's an emerging group of companies out there that are bringing this together, and they can even do it retrospectively because they're seeing -- you see each girth weld, for example, in the pipeline. So, you know about each joint link, and, so, you can correlate that from data back to the '50s, you know.
It's -- well, '60s. I'm sorry. There wasn't one in the '50s. They didn't have any pigs then. But you can correlate it back to the old data.
MR. GOGLIA: Okay. And a moment ago, you mentioned some POD, probability of detection, and you mentioned a number of 80 percent.
Would you go over that again for me?
DR. KIEFNER: The numbers that you see, I believe, most often in the vendors' literature is that they will guarantee defects to be sized within plus orminus 10 percent of the wall thickness for a high-resolution tool 80 percent of the time.
In other words, 20 percent of the time, they can't get within those boundaries, but they may get within, say, plus or minus 15 percent 95 percent of the time.
MR. GOGLIA: Okay. And the shear wave is the most accurate tool we have today?
MR. DUCKWORTH: For certain types of defects, yes.
MR. GOGLIA: I understand that. Okay. I might ask both of you this question, if you would respond to it separately.
If we lived in a perfect world, and we were driving towards absolute zero risk in the pipeline business, what would you envision the process being to drive us there?
MR. DUCKWORTH: You first, John.
DR. KIEFNER: Thanks, Noel.
MR. GOGLIA: You've been to Fred Astaire School, I see.
DR. KIEFNER: Well, I do think that with a combination of inspection tools being run in as many pipelines as possible, we will be approaching that situation, but until we get more pipelines piggable andget them inspected, I guess we still have to face some risk, and the risk is never going to go to zero, but we could drive it further towards zero by inspecting more pipe more often.
MR. GOGLIA: And what do you mean by "more often"?
DR. KIEFNER: Well, I think that repeat testing or repeat inspection is -- can -- should be based, in my opinion at least, on evaluating the risk that you think is there, what types of defects are there, how fast you think they're growing, and, of course, subsequent pig runs compared with previous runs are going to allow us to get some handle, I think, on crack growth rates or pit growth rates, and it -- for the number of times you need to do a certain pipeline, it varies considerably, depending on the condition of the coating of the pipeline, how the cathodic protection was cared for over the years, and even a very old pipeline can be extremely good and maybe not require frequent inspection.
So, at least I would hope they would be done on a basis of evaluating the specific situation.
MR. GOGLIA: Okay. Fred, would you care to add to that?
MR. DUCKWORTH: I think John said what Iwould have said.
It's a tough question to answer, and we take that question very seriously, and believe it or not, I was asked that question by Stacey prior to the final rulemaking that just came out from OPS.
If you could describe what was the actual panacea, what would you describe with zero tolerance, and we talked a lot about the things that John talked about, but there are other issues other than pigs that I would like to point out.
For instance, I heard our Department of Defense is the greatest in the world. Their satellite capability is very, very substantial, and in these GIS systems that we're developing at each of the operating companies and utilizing the pig devices to map out the pipelines, if we -- when we run a pig, and we see an indication, we're not sure about it, if we could call up all of the history from the satellites and determine whether or not there's been some excavation activity close to that area, for example, there are many things that we can do to access data that's kind of out on the edge of the technology now, and I think that in 10 years from now, we'll think that it's maybe even backwards, that they're already using that, and there are other technologies.
I think we need to stay aggressive in pursing all opportunities.
MR. GOGLIA: How concerned are you gentlemen about the sections of pipes that are not piggable?
You know, we've heard a lot of discussion this morning about the pigs, that those sections, you know, we can't determine if they've been injured from construction work nearby. We can't determine their condition without excavating.
DR. KIEFNER: Well, I'm -- I guess my concern differs, depending on how they're operated. There are a lot of systems that are operated at low pressure, and the chances that they would cause a catastrophic rupture would be much less simply because they operate at low pressures.
So, there's less risk even if you can't pig those kind of sections, and on the other hand, if a pipeline operates at a very high pressure, 72 percent of SYMS, as they're allowed to in the regulations, then unless you perform some sort of either hydrostatic test or in-line inspection or an equivalent technology to that, which I think is still evolving, then you probably have no way of knowing exactly where you stand.
Although we certainly look at -- in a riskassessment, you'd certainly look at things like the condition of the coating and the measurements that you make on the cathodic protection and the leak history, if there is one.
There are other things that can tell you indirectly what is going on.
MR. GOGLIA: Mr. Duckworth, would you add anything to that?
MR. DUCKWORTH: Yes. I would think that if we're going to redefine piggable in terms of the operating pipeline company, is it piggable with the changing out of valves, and is that prohibitive?
You can -- failures are very expensive, and I think that assessment is going to be very, very important, and what can we -- what can the pigging industry do different that would make their systems more compatible with the operating pipelines?
So, I think we need to work on the definition of piggable.
MR. GOGLIA: I have one final question. It's probably off your area, but since you're not employed directly, you might know the answer, and it gets to the liability issue.
Since I've been at the Board, you know, we've had lots of pipeline problems that are caused byconstruction work nearby, and there's always a long latency between the time the damage was incurred and when the problem shows up.
Do either of you know, has the industry been able to reach back to the construction industry and identify those folks and hold them accountable?
DR. KIEFNER: I've seen a couple cases where they were, but more often than not, I think they probably failed to identify it because it's hard to tell the age of damage.
MR. DUCKWORTH: I've seen, like John, several situations, several serious situations where they were able to identify, but very seldom did they pursue recourse, and, you know, the real damage is not financial recourse here. It's to the people and to the environment, and I just have a hard time getting real sensitive to getting restitution. That's just not on my -- high on my priority list.
I want to avoid the issue rather than --
MR. GOGLIA: But you don't -- don't you think that if we held the contractors liable, and it was general knowledge in the industry that they would be pursued, that they might exercise a little more care and maybe report it when it happens?
MR. DUCKWORTH: That -- I think there's theissue right there. If -- you know, give them complete amnesty, if they will come forward now and tell you that you damaged the pipeline.
It's very inexpensive to repair an operating pipeline. You can do it with very little cash outlay, but when it fails, it can be a major financial issue. So, it would be in the best interests of the insurance companies and the operating pipeline companies if the individual backhoe operator could, with amnesty, come forward and say I hit your pipeline and not have to suffer consequences for doing it.
MR. GOGLIA: Okay. Thank you, Mr. Chairman. No further questions.
CHAIRMAN HALL: Member Hammerschmidt?
MR. HAMMERSCHMIDT: Okay. Thank you.
Following up on that last line of questioning, could either of you see a pipeline operator with a very proactive in-line inspection program using in-line inspection smart pig technology that would probably not be able to ascertain that a section of pipeline had, say, a longitudinal gouge on the top of the pipe?
MR. DUCKWORTH: Could we -- as I understand the question, would a prudent operator miss such a thing? Is that what you're really saying?
MR. HAMMERSCHMIDT: Right. Well, would you know of any operators that use smart pig technology now that use the type of technology that would miss that type of a defect?
MR. DUCKWORTH: I can't talk specifically about individual pipelines, but there's one that there was a picture of with a big fire on the wall here today that showed up on the log, but it was below the gradeable criteria.
Now, that's not the pipeline operator's fault. That's not the pigging company's fault. It's below the criteria. But it failed, and it failed catastrophically, and this is a situation where they were running many pigs, and in this case, the system didn't detect it adequate to bring it to their attention, and that's -- it's a simple fact.
DR. KIEFNER: I could add to that, that I think that I suspect knowing who the speakers are this afternoon, you're probably going to hear about the new technology for detecting mechanical damage.
We don't have a commercially-available tool today that specifically will locate gouges and dents. I think this morning, you actually saw some of the data that comes from the prototype tool in that respect, but it's not a commercially-available device yet.
So, right now, we're in the mode of looking for mechanical damage by looking for dents, and if they're on the top of the pipe, deciding then that there's a probability that something may be there, and that perhaps we ought to look at it, that's probably one of the more common things that's done.
It looks also like some of the other tools, like the transverse field tool, will also find things like cracks and dents, but it's fairly new at this point, but there is a specific effort going on to develop a mechanical damage tool, and I'm not going to try to tell you about that. I think somebody else will.
MR. HAMMERSCHMIDT: All right. Well, thank you very much.
Just one other question, and I believe that Mr. Duckworth made reference to talking with Stacey Gerard during the rulemaking process, this latest Pipeline Safety Final Rule that was finalized.
The rule says that an operator must complete the baseline integrity assessment within seven years after the rule's effective date, and then it goes on to say an operator is further required to assess at least 50 percent of the covered pipeline beginning with the highest-risk pipe within 3.5 years from the rule'seffective date, and that was touched on earlier this morning.
I'm curious to know if either of you have an opinion as to whether or not those time frames are appropriate or if you had thoughts that maybe they should be different.
MR. DUCKWORTH: I think that I would like to go back to what Ravi said. It's extremely difficult to specify a time for all pipelines because they're all different, and they all have different operating characteristics. They all have different design characteristics. They're all placed in various and sundry environments, and, so, they all aren't the same.
He mentioned in one case, you might need to run it every three years, and in another case, it might need to be only every 10 years, based on what you see, and based on what you know, and I think that philosophy is good, and to pick the seven and five as kind of across-the-states average, I can sympathize with it, but I could also argue for one a little longer and one a little bit shorter.
So, it's not one that -- there is no specific answer to that question, and they had to be specific, and, so, they did the best they could. That's my opinion.
DR. KIEFNER: I think what I could add to that would be that the industry is currently working on a standard which will give operators guidance to following the regulations now, and I picture that what will happen is people will all do risk assessments on their pipelines, and that they will identify the high-risk areas, and those will be dealt with in the first three and a half years for sure, and that as we go along, presumably even though it's taking more time, we're lowering the risk as we go, and that only those pipelines that are judged to be fairly low risk will be left to the seven-year period.
MR. HAMMERSCHMIDT: Thank you. That's all I have.
CHAIRMAN HALL: Well, thank you.
Mr. Duckworth, in your presentation, you said, I guess, in regard to pigging, that depending on how much do you want to pay for, and I guess my question is, how much does the public expect it should be paid?
MR. DUCKWORTH: Okay. What I intended to say there was if your need is small, then we have one --this was in deformation that we were talking about.
CHAIRMAN HALL: Right.
MR. DUCKWORTH: If your technical needs aresmall, the low-resolution, less-cost device could very well serve their needs, and, however, if you wanted greater definition, you were going to have to pay more money for it, and that greater definition is described in greater resolution, and the -- and especially the higher-resolution devices, coupled with INS data as well, becomes a more expensive endeavor.
CHAIRMAN HALL: Well, would you think --could you explain to me why the industry has not set standards in this area, so that there's a level playing field for everyone?
MR. DUCKWORTH: No, sir, I cannot.
CHAIRMAN HALL: Dr. Kiefner?
DR. KIEFNER: Well, I think there are some standards going on and evolving through the NACE International on pigging, but nothing has come forward that is universally accepted yet.
I don't think we're totally devoid of standards. People are working on it.
CHAIRMAN HALL: Dr. Kiefner, you have a very impressive resume and background in this area, and in your presentation, you mentioned that, I guess, the pipelines are designed initially with factors of safety against rupture and leakage, and you talked about materials, fabrication, anti-corrosion, and theinspection and hydrostatic testing.
Have any of those -- have the materials evolved over the years?
DR. KIEFNER: Yes.
CHAIRMAN HALL: What about the other factors? Have they evolved?
DR. KIEFNER: Yes. Coatings have gotten better. The science of cathodic protection, we understand better, I think, than what's required now than we did 50 years ago, and materials are certainly better now than they were 50 years ago.
CHAIRMAN HALL: And what year was it that we had our first federal regulations in this area?
DR. KIEFNER: I believe about 1970.
CHAIRMAN HALL: Do you know how much of the pipe is in the ground in this country pre-1970?
DR. KIEFNER: More than half of it, probably.
CHAIRMAN HALL: And that being the case, how often do you think we should, to use your words, "revalidate" pipeline integrity?
DR. KIEFNER: I believe it has to be based on the individual characteristics of the pipeline. There are some older pipelines which have had a very good track record because they were coated properly and cared for properly, and they were in the right place, Iguess, not to have been hit by somebody, I mean, just by luck.
But it's hard -- difficult, I think, to put a one-size-fits-all approach on it because of that. There are certainly older pipelines and some newer ones which will require more frequent monitoring than others.
CHAIRMAN HALL: Well, it's -- and, of course, this is more of an observation than a question, but the Board's experience in our work, of course, is many times, we see companies like TWA or SwissAir that may have one fatal aviation accident in a period of 25 years, but at the time those events occur, they are called upon by the public and the people to try to explain what has been done prior to that event to put in place a safety net and procedures to guarantee safety.
One of my greatest difficulties in dealing with the pipeline industry is it's very difficult to understand what has been done, either in federal regulation or in terms of industry standards.
I have observed some excellent operators, some companies with some outstanding safety cultures, and at the same time, we have had experience with accident investigations in which anomalies were found,and I believe it was Mr. Duckworth that said it's very inexpensive to repair an operating pipeline obviously compared to the expense of an accident.
But I'm hoping that this hearing will help advance both the federal involvement, but as importantly, if not more importantly, the industry's responsibility in coming forward and putting together some uniform standards in these areas.
I believe Member Goglia has a follow-up question, and then we will see if either one of you gentlemen have any closing comments.
MR. GOGLIA: I have one question. I don't know if you're aware of it or not, but the Board, the five of us, by statute, do not consider costs in our equations, but we don't operate in a vacuum, and we understand costs, and you piqued my interest, my curiosity on the cost issue.
Do you have a sense for just what does it cost per mile, per measurement, to run the pig? You know, a smart pig or a dumb pig, it's going to cost the same to run it through the pipe. So, the difference is going to be in the analysis side, how many manhours are spent going through it, but just a sense for us.
MR. DUCKWORTH: Just the contract cost to run an electronic pig?
MR. GOGLIA: Hm-hmm.
MR. DUCKWORTH: Varies from just a few hundred dollars a mile to tens of thousands a mile, depending on which system you choose. So, we have everything from soup to nuts, and there's no -- again, no clearcut answer to that. But I'm sure that you could get -- if you talk to some of the pigging companies, they'd be glad to supply you with specifics.
MR. GOGLIA: Okay. Thank you very much. No further questions.
CHAIRMAN HALL: Gentlemen, you've both been excellent witnesses as the previous panel. Is there anything that you would like to say in closing? Take an opportunity at this public forum to make any additional comments. Mr. Duckworth?
MR. DUCKWORTH: I think that I would like to say that this pigging issue, I made the statement, I think, three times, that there is no panacea, and in my simplistic mannerism, I would also like to say that pigging is hard work. It's not going to jump out and slap you in the face. It's an evolution. It's not an event.
You have to work at the data. You have to utilize it, and the intelligent utilizers of the data find that it serves them well, and those that aren'tworking hard and aren't utilizing it possibly as intelligently as they could aren't real happy with it.
So, that's my final statement.
CHAIRMAN HALL: Okay. Dr. Kiefner?
DR. KIEFNER: I don't think I have anything to add.
CHAIRMAN HALL: Well, thank you very much, both of you gentlemen, and I think we'll call then the next panel and take -- we'll just hold in place while the next panel -- if we'd ask the next panel to please come up. We do want to try to finish on a timely basis this afternoon.
So, we will take a break as soon as we conclude with this panel. If that's acceptable to you, Mr. Chipkevich.
MR. CHIPKEVICH: Yes, sir.
CHAIRMAN HALL: I think if everybody wants to take a stand-up stretch in place, and then we'll sit back down, that's certainly permissible, since my entire Board has stood up to stretch. Leaving. George is walking out.
(Pause)
CHAIRMAN HALL: I do think that I will exercise the prerogative of the Chair that since we have these -- we are now going to have fourpresentations, and I think with each one of these presenters having 15 minutes for their presentation, I think we will take a break at the end of the presentations rather than waiting until after the questioning.
Mr. Kris, if you would, please, introduce the panel.
MR. KRIS: Thank you, Mr. Chairman, and Members of the Board.
The next panel is the Pipeline Operators Panel. On this panel is Mr. Vic Yarborough from Colonial Pipeline, Mr. Rich Turley from Marathon Ashland Pipe Line, Mr. Andrew Drake from Duke Energy, and Mr. Elden Johnson from Alyeska Pipeline Service Company.
Panelists, I would like to remind you that you have 15 minutes to give your presentation. The yellow light in front of you will go on when you have two minutes remaining. The red light indicates that your time is up.
Mr. Chairman, staff is ready to hear from the panelists.
CHAIRMAN HALL: Well, gentlemen, welcome to each one of you. You certainly all represent very recognizable names to most Americans, and we lookforward to your participation.
Mr. Yarborough, I think you've made the mistake of sitting in the seat that seems to be the first call. So, we will ask you if you will proceed with your presentation, unless there's an order, Mr. Kris. If not, we'll just take Mr. Yarborough and move down the table then.
MR. YARBOROUGH: Thank you, Chairman Hall. May I have the PowerPoint, please?
I am Vic Yarborough. I'm Vice President of Technology and Operational Excellence for Colonial Pipeline Company.
Colonial Pipeline is a refined petroleum products pipeline. We move approximately 1,900,000 barrels a day of refined products from the Gulf Coast Refineries to the Eastern United States. That includes the Southeast and as far north as New York Harbor.
We're absolutely committed to delivering those 1,900,000 barrels a day safely without affecting the environment or the safety of the public or our people.
This map shows our operating area. We operate 5300 miles of pipelines. They range from six inches to 40 inches in diameter.
Mr. Chairman, I appreciate the opportunity to provide an overview today of the internal inspection program at Colonial Pipeline, provide some of the history, some of where we are today, and what we hope the future will hold for us.
I think our internal inspection program is an example of our commitment to pipeline safety. The program began initially in 1985. The objectives were fairly simple. We wanted to inspect all of our older main line pipelines and stub lines, 1962 to 1971 vintage. We're using first generation caliper tools and the standard resolution magnetic flux tools.
At the time, we anticipated the program would take approximately five years to complete, and I would say that 1985 was the beginning of a continuous learning process for Colonial Pipeline as far as internal inspections, as far as the tools and the capability and exactly what it took to get a tool through the system.
Our initial criteria for investigating anomalies for caliper tools, we were simply looking at buckles greater than six percent, and any anomaly that would restrict the passage of the corrosion tools that would follow, and with the standard resolution corrosion tools, we were looking at what we termed"severe corrosion". That's anything where there's an indication of 50 percent or greater wall loss, and also then moderate corrosion, where the wall loss indicated is between 30 and 50 percent.
We learned a lot of things in that first program. First of all, we did find buckles that had to be removed before we could run the corrosion tools. Some of those were in very difficult locations. We found that some of our traps were not long enough to accommodate some tools. On some of our shorter segments, we had to add traps in order to pig them.
The limited battery life of the early tools meant we had to use multiple runs on some of our longer pipeline segments, and corrosion tools were not initially available that would transfer the type fittings and elbows in our smaller stub lines. Later, that did become available, and we did utilize them.
From the information we gathered from the results of the early tool runs, we decided to expand the pipeline inspection program to include all main lines and all stub lines no matter what vintage, no matter when they were constructed.
It took us 10 years to complete that initial inspection rather than five for some of the reasons I've stated earlier. We began the second roundinspections prior to completion of the first round, and today, internal inspection is a major component of Colonial's overall integrity management program.
Today, our program has changed quite a bit from the early days. For anomalies that we investigate for -- we've gone from using the caliper tools to the deformation tools, which provide more data about dents and buckles.
We're still looking for dents over six percent, any buckle, any dent or weld, whether it's a longitudinal or a girth weld, dents with metal loss indications, and you typically get that metal loss information from another tool, any top-side indication, and we define that as anything between the 9:00 and 3:00 position on the pipe that denotes possible third party damage, and any dents with a stress concentrator or unusual deformity. An example of that would be what we call a "double dent", where two dents have grown together.
As far as corrosion, we've gone to all high-resolution corrosion tools, either magnetic or ultrasonic, and we're looking for any anomaly with greater than six percent wall losses indicated, and with the information provided by these high-resolution tools, we can now calculate the remaining strength ofthe pipe.
We will investigate anything where the remaining strength is less than the initial internal design pressure of the pipe. We're looking for any unknown encirclements or attachments on the pipeline, and if we cannot positively identify an anomaly from the chart, then we'll go look at it.
Now, I'd like to talk a little bit about crack tool inspection and its history at Colonial. We've experienced six major spills attributed to railroad fatigue failure.
Now, railroad fatigue is a phenomena where small cracks can be initiated in large diameter pipe adjacent to the longitudinal seam during transportation. It's caused by a vibration on the rail car. We believe it's due to the improper loading.
Our experience has been only with two manufacturers of original main line pipe. The last failure occurred in 1989 in a 32-inch Number 4 main line in Virginia.
Now, subsequent to that failure, in 1990, we hydrotested a 144 miles of pipe. That hydrotest exposed one additional flaw as a result of the test pressure. We felt like at Colonial that it was imperative that we find another method to locate thesedefects in our pipeline.
Excuse me. Colonial and Provincial Pipeline of Canada, now known as Enbridge, joined together in a joint venture to find better technology. We talked to tool vendors in the U.S., Germany, and Great Britain, and we co-funded a project with British Gas Inspection Services, who today is PII.
They had on the shelf a tool that would locate stress corrosion cracking in gas pipelines. We worked out a contract with them to modify that tool to run in liquid pipelines, and it has proven to be a commercial success for us and for British Gas and Provincial.
In 1995 and 1996, we inspected that same 144 miles that had been hydrotested before. That inspection uncovered 13 additional fatigue defects. Now, all those that were found would have survived another hydrotest in either 1995 or 1996. We know this because we cut several of them out of the pipeline, and we pressured them up to failure. They all failed above normal hydrotest pressures.
All these cracks would have continued to grow in service and could only have been discovered by either additional multiple hydrotests, hydrotests, or eventual failure.
Today, we inspect all the main lines that have -- are suspect to this problem, and I think this crack tool inspection is a real success story for Colonial Pipeline and the industry and the tool vendors. It was truly an international effort between two pipelines, the one Canadian, the one U.S. and a vendor from Britain, and it was an example of applying new technology to solve a pipeline integrity issue, and for us, for this type of defect, in our pipelines, this technology has proven to be more cost efficient, less destructive, and more effective than hydrotesting.
We have now run over 20,000 miles of inspection tools in our 5000 mile pipeline. As I stated before, the program began in 1985, and to date, we have inspected some 20,498 miles of pipeline.
Over the years, we've also improved our processes for inspection and repair, and through 1999, we have actually investigated over 10,000 anomalies. Total cost is over a $115 million to date.
Now, to fast forward for internal inspection at Colonial, we will continue to run the current suite of tools, including the caliper and deformation tool, high-res corrosion tools and crack tools.
We base the frequency of those runs on calculated anomaly growth for corrosion, for example,or fatigue life, if it is suspected that there might be cracks remaining in the pipeline, and we also look at the risk profile for the pipeline segments when deciding how frequently the major runs.
We plan on incorporating new technology and improving our analytical approaches to improve our response time and our evaluation of these time-dependent defects.
We're going to expand the program to include what we call "delivery lines". These are low-pressure small-diameter lines that are typically very short. They run between our tank farms and our customers' terminals, and in 2001, we're going to trial the new transverse flux tool that you've heard about today in one of our pre-1970 ERW pipelines, and if that proves successful, we'll continue that program to include all of our pre-1970 ERW pipelines.
One of the things that we're doing is we're integrating all the data from our tools, from the various tools, along with data from our corrosion program. We're putting that into our GIS system, and it becomes part of our overall risk management program, and with that, we're able to map the risk profile of our pipelines.
This helps us focus our resources and ourattention on those areas that are more critical, such as ACAs.
Now, what would we like to see in the tools of the future? I think some of the vendors talked about some of this today. We'd like to see better resolution in discrimination and improved accuracy.
This is important to us. As I said earlier, we've dug up the pipeline some 10,000 times, but only a handful of those times did we discover something that was of immediate concern, that we had to lower the operating pressure of the pipeline.
Now, we found quite a bit of more than were of a concern, and we did either repair or recoat them, and we certainly wanted to get to those, but a lot of the things we dug up turned out not to be injurious defects. This is particularly true, as people have mentioned earlier, when you're looking for those top-side indications with a gouge that may be causing third party damage.
We'd like to see greater resolution discrimination and accuracy for two reasons. One, to make sure we don't miss anything that's critical, and, two, so we don't use the resources investigating something that's not injurious, when those resources could be applied to another facet of our overallintegrity management program.
We'd like the idea of multi-functional tools because that cuts down on the number of devices you have to run in your pipeline.
I put up here competitive pricing. What I should have said is competitive value. We encourage competition between the vendors, and by value, I'm talking about the things mentioned above, greater resolution, greater discrimination, greater accuracy, and also value-added items, such as the ability to direct report the information from tool runs into our GIS system. That would be of great benefit to us, particularly as you make multiple runs over the years, you build up a lot of data, and data management becomes a big issue in your overall program.
In summary, we are committed to spill-free, error-free operation, and effective management programs are a way to achieve this. The internal inspection program is a very critical part of our integrity management program.
However, it's only one element of a multi-faceted program. Proper design, installation and maintenance, operation by qualified personnel, and risk management are essential to achieving operational excellence in pipeline operations.
Thank you.
CHAIRMAN HALL: Thank you very much.
Mr. Turley?
MR. TURLEY: Go ahead and load it. Go ahead and load it.
Hello. My name is Rich Turley. I'm with the Technical Integrity Services Group of Marathon Ashland Pipe Line. I've been primarily involved in integrity and assessment verification for my entire career in the pipeline industry, and I wanted to share some comments and some general thoughts with you today regarding integrity and inspection.
To start with, Marathon Ashland Pipe Line operates approximately 5000 miles of crude oil and refined products pipelines, primarily in the Midwest, as well as in the Gulf Coast, and in Wyoming.
Some general comments about utilizing in-line inspection technology. First, it's very effective, but it's not quick, and it's not an exact science.
Inspection tools today provide a lot of data. Some of the data is valuable, and some of the data is not so valuable. With current technology, you'll get it all.
We typically spend on a specific pipeline four to five years per line segment conductinginspection and rehabilitation programs, in order to convince ourselves that we've looked at things from enough different angles to assure the long-term integrity of the pipeline, to the best of our ability.
It takes time to utilize this information to its fullest extent. Similar to Noel's comments earlier, typically less than 20 percent of the indications that in-line inspection tools sees actually warrant further investigation, and of that 20 percent, typically 30 percent or less actually require a repair once they're excavated.
Next comment. It's complex, time-consuming and requires a lot of judgment. One of the more important things here is that not every signal that a tool returns is going to be investigated typically.
An in-line inspection tool's accuracy, as was stated earlier today, is typically plus or minus 10 to 20 percent of the wall thickness. Allowing for that variation is a challenge to the prudent operator.
An in-line inspection tool isn't within its accuracy tolerance all the time. Allowing for that is also a challenge.
We have found that current state-of-the-art statistical methods, first pioneering by Alyeska, to be very beneficial in providing a high level of confidencethat we have been able to manage effectively the corrosion or metal loss on a pipeline.
These statistical methods allow us to incorporate the tool's variability into our inspection and rehabilitation program.
A significant number of anomalies identified by an in-line inspection tool were percent when the pipe left the mill. The dilemma the prudent operator faces is to assure that the large family of indications that appear to be non-injurious are not integrity concerns.
Some cannot be discriminated at this time with current technology from non-injurious anomalies very effectively, but it is improving greatly.
Users of in-line inspection technology, operators and regulators, must have realistic expectations and an understanding of what the data represents.
Each type of in-line inspection tool is designed to detect and characterize the specific type of anomaly. For example, geometry tools, as was talked about today, are used for dents and buckles, metal loss tools are used for typically corrosion, and crack tools are used for crevice-type corrosion or crack-like defects.
A number of different tools may be needed to ascertain what the true integrity concerns on the pipeline are. In short, using the technology to its maximum potential while recognizing the limitations is the challenge that we face today.
I now wanted to share some observations of some common pieces of a successful inspection and validation program. We feel we have a successful program at Marathon Ashland, and I like to consider this the three Cs, which are culture, commitment, and consistency.
To have a successful inspection and validation program first takes culture. That means a company whose culture rewards being proactive. We want to know. A culture that fosters an open relationship with regulators. A culture that views additional excavations, additional digs, as kind of an expectation. A culture that plans on disruptions because when an in-line inspection tool is run, and the information comes back, there most probably will be from time to time disruptions in the service to the customers, and it has to be planned for, and a culture that truly believes that zero leaks is attainable.
The next point is commitment. This type of activity needs dedicated resources. It's been ourexperience that continuity of personnel and experience is very, very important because again we are dealing with time-based analysis and technology that is improving and evolving as we speak.
You need to understand a system's history and/or personality and capture -- make sure you're capturing the inspection and rehabilitation information in such a manner that you'll be able to utilize it in the future, similar to the GIS information that was shown earlier today.
You need to ensure that the fix you apply as an operator won't create future problems. Don't be your own worst enemy is what we have found, whether it's the coating technique you choose, the repair technique you choose, similar things. Over time, we have seen that some things work better than others. Try to learn from that history.
You can't rely on the codes and regulations to address every conceivable solution and every conceivable situation. Engineering judgment is still going to be required into the future, and as an operator, you need to figure out and determine how best to manage the stress and anxiety involved in this type of work because it's not black and white typically. It is very -- there is a lot of soul-searching that goeson to feel comfortable that we are looking at everything we need to look at.
The last point is consistency. For a successful program, an operator needs a systematic and a consistent approach for several things. Identifying the potential failure mechanics, as Ravi mentioned earlier. identifying the appropriate type of inspection tool, actually performing the inspection. Reviewing and assessing the data itself. Developing a short-term response to that information and a long-term response as well as understanding how to utilize industry expertise when it's necessary to help with gray areas as well as a systematic approach to providing feedback to the vendors on what you found.
Kind of a look into the future is that what I'd like to say is that it is an evolving process that has proven very beneficial to us as an operator. Managing metal loss resulting from corrosion is very achievable. It's taken over 20 years to get where we are.
However, many operators are experiencing failures that are due to mechanisms that technology is just now being developed to identify, let alone characterize. Historically, corrosion tools have been the predominant inspection device because corrosion wasthe predominant failure mechanism.
With the evolution of corrosion inspection technology from low-resolution to high-resolution, as the tool became more sensitive, the amount of data produced by that tool increased exponentially as well as the amount of time it took to get that information returned.
We find that typically the amount of time it takes for that information to come back from a vendor is usually paralleled by the level of indications that the tool sees. Regardless of their injurious or non-injurious, the more indications, typically the longer it is to get that information returned.
The benefit of finding more potentially-injurious anomalies has also made the operator's task of sorting these anomalies much more difficult. We should expect the same as new technologies evolve.
As managing corrosion through in-line inspection is being addressed, other failure mechanisms are becoming relatively more important. Technology is being developed and tested in the field as we've spoken of today to detect these other failure mechanisms.
Each of these anomaly types has been detected, and some even characterized, using in-line inspection techniques in the past few years in certaindiameters of pipe.
With these types of anomalies, we are basically where we were 10 to 15 years ago with corrosion tools. Leading edge tools and technology are required to detect some of these anomalies. Others can be detected and characterized using proven technology, similar to what Noel said. Using what we have to its fullest extent is a challenge.
These new technologies only exist in specific diameters, and it may be years before they are available in all necessary diameter wall thickness combinations. In order to enhance integrity management, companies will need to expand their programs and investigations to anomalies maybe in general and not limit their inspection to failure mechanisms they've actually experienced.
An open dialogue needs to exist between the in-line inspection users themselves and the vendors to help with on-going data interpretation. It is critical that operators provide specific performance feedback to tool vendors to assist them in improving inspection tools they already have on the market.
If unexpected or unique anomalies are found in the course of normal excavations, this information needs to be relayed to the vendors and the rest of theindustry.
Additional similar data signal patterns may need to be excavated in order to verify that they represent -- to determine if they represent detrimental types of anomalies. This is a vital key to utilizing this technology fully.
As additional failure mechanisms emerge, technology will need to keep pace with their detection.
In summary, evaluating anomalies or indications from in-line inspection tools is not an exact science. However, a properly-managed program can provide for a pipeline's continued safe operation. It requires being proactive, being open with your communications, and continuing to improve the technology, both that which is on the market currently and that which is coming to the market in the future.
Thank you.
CHAIRMAN HALL: Thank you, Mr. Turley. Appreciate your presentation.
Mr. Drake?
MR. DRAKE: Good afternoon, Mr. Chairman, Members of the Board.
I appreciate the invitation you've extended me to speak today on this important issue.
I work with Duke Energy, and I'll wait for myslide.
MR. KRIS: Antoine, go to the other computer switch, please.
MR. DRAKE: There we are.
Duke Energy is a diversified multi-national energy company. Duke Energy Gas Transmission is comprised of four pipeline systems with an additional system currently being proposed. Our system is made up of approximately 12,000 miles of interstate natural gas pipelines.
We deliver gas from the Gulf Coast and Canadian supply areas to Midwest, Northeast and New England markets. Duke Energy Gas Transmission transports approximately eight percent of all the natural gas consumed in the United States.
As you can see, we're, you know, very diverse. We have separate companies, but we are typical of a natural gas pipeline company.
Improving pipeline safety is a complex but achievable challenge. Overall, we believe the industry has a good safety record, but we can't rest on that, and in fact, we never have.
It is a good business and much more than that. To us, one accident is too many, and we can't rest until we've achieved that goal. We must continueto try to improve the safety level of this industry.
I think our safety record is a product of our commitment to improve. We have 50 years of voluntary research. We've spent hundreds of millions of dollars in the gas industry sponsoring research in an effort to try to improve our capabilities and ensure the public's integrity -- the pipeline's integrity to the public.
We've developed a pipeline simulation facility in Columbus, Ohio, with the gas industry sponsoring about $20 million worth of effort. It was developed as a forum to try to discuss technical issues, to experiment with pipeline inspection tools, and to develop those technology capabilities, to help us to share practical knowledge, and, more importantly, to help us apply what we learned. I think that's really where the rubber hits the road.
We must continue to try to improve. It's a never-ending road. It requires an honest evaluation of all of us, and we must accept that responsibility.
Managing pipeline integrity is our primary responsibility. I don't think we can duck that. I don't think we can look around for someone else to shoulder that responsibility. It is ours. It is a complex issue. We must be diligent and thorough in managing the risks that we face.
We must reach out and confirm the integrity of the pipeline, not just project it. There are no simple solutions. There is no easy way, no panacea. Someone said earlier, this is a mature industry. The simple solutions are gone. It's time for us to roll up our sleeves as we've done in history and push this forward.
To help illustrate the breadth of the integrity management challenge and the role of in-line inspection, I draw an analogy comparable to perhaps --comparing integrity management to a tree. At Duke Energy, we have five primary branches on that tree. We have Design and Construction Branch. We have Corrosion Control Branch, Damage Prevention Branch, Qualified Employees Branch, and Inspection and Maintenance Branch, which is the focus of today's discussion.
I think the point is here to try to provide a perspective that we cannot inspect in quality. We cannot inspect in integrity. It takes the whole package to make this product work.
Where is inspection -- in-line inspection on this tree? It is a leaf on this Inspection and Maintenance Branch, on that Integrity Management tree. It isn't the tree. It is a piece of the tree.
At Duke Energy Gas Transmission, we have over30 years of experience in in-line inspection. It is in fact part of our integrity program. Virtually all our main lines have been in-line inspected. Much of our system has been inspected multiple times, and we have had success in defining inspection intervals, particularly on corrosion issues.
We have experience with most vendors and have been actively involved in research from the very beginning. We have experience with standard magnetic flux leakage tools. We have worked with high-resolution magnetic flux. We've worked with transverse field. We've worked with ultrasonics. We've worked with EMATs. We've worked with geometry tools. We've worked with tandem technologies. We've worked with digital integration for multiple tools.
I think the thing that I would draw from this, having heard many, you know, speakers in front of me, there are a lot of different tools out there. I think that's a fact. They find different things. That also is a fact.
There are many trade-offs involved in which tools are used and what you -- the resultant knowledge that's gathered from those running of those tools, and there are very different levels of successes among those tools.
There's a significant difference between what they can detect and how reliably they can detect it. Those can't be used as excuses not to do this. They have to be conditions under which you do use them, so that you apply what you know and have learned correctly and in context and can move forward successfully.
Magnetic flux, probably the most prominent of -- most popular anyway of the in-line inspection tools, is effective at bulk metal loss detection, typical corrosion signatures. It is very good at that.
There are some technical limitations beyond corrosion detection that we have to understand to apply the tool appropriately. Acoustic-based tools, as we've heard many different times from the vendors in particular, do not work reliably in natural gas.
These tools work, the ultrasonic tools, in particular, work in liquids because of the couplant provided by the fluid. In natural gas, that couplant is not present, and it creates a technical problem for the acoustic transfer, a problem which we are still wrestling with how to solve, but it is a limitation we have to deal with.
In particular, that hurts our ability to locate cracks. I think that was well discussed prior to my presentation, about the limitations of thattechnology, and they have failed to find cracks. They rely on ultrasonics to find it. Unfortunately, that technology is limited in the gas environment.
Third party damage. We have to understand the signal that is created or the phenomena that is correlated -- accompanies third party damage, and that is, it is not a bulk metal loss issue, and magnetic flux tools are looking for a bulk metal loss event. That's why they don't find them reliably. It's a different element.
There are issues about deformation of the material in the form of a dent. There's metal loss perhaps associated with it. But as much as anything, there's a counter-balancing effect called "hardening" of the material, which creates a reverse influence on the magnetic flux, because of the increased magnetic permeability of a hardened material.
So, it sends the signal the other way. That's why it's so difficult for magnetic flux tools to find third party damage. It's a totally different metallurgical event, and that has to be understood when hunting that.
Millions of dollars have been spent in research trying to improve these tools. We don't stop saying, well, that's the limits of where we are. Wecan't go any further.
We began investing in that technology in 1968, when Texas Eastern, one of our subsidiaries, worked together with Battelle and a company that later became known as Tuboscope, to develop a tool to inspect our Ohio River crossing. That tool later became the magnetic flux vehicle, which is now commercially available to the industry.
Technically-reliable applications for in-line inspection will continue to emerge. We have to promote those. We have to push them. We can't say we're done, that's all we can do, and stop. But I think there are some things that we can do, and we've hit on them earlier here today.
We need to define what is a pig. Very fundamentally, that does not exist. We need to define what a pig is able to find. We need some sort of calibration and verification for those tools. That does not exist. It does exist, but it's not applied universally. I will say that. I'll restate that.
Qualification of those tools and their people are needed. We need standards for the qualification of their folks, just like we have in x-ray, just like we have in x-ray. We have qualification standards for x-ray technicians. I think we need the same for thesefolks, and we need some sort of performance guarantees.
Folks that have a lot of experience in this industry and a lot of experience with pigs understand how to apply what -- and keep in context what's being generated by those results. Those that don't need some sort of guarantee. They need a little bit more baseline to apply it in context.
It's incumbent upon all of us, in order to improve safety, we must understand the capabilities of these tools, we must understand the limitations, and we must use them where appropriate.
There is no silver bullet here. We've heard that many times. It would be great if there was. I think we'd love to just drop it in there and be done with this. It's not that simple. That doesn't mean we can stop. We cannot stop.
As much as we have pigged our system, portions of our system simply can't accommodate in-line inspection and probably never will be. That does not mean we can't inspect them. It means that we have --it's incumbent on us to find another way to ensure their integrity.
It is a fundamental difference between gas and liquids, this accessibility issue. Gas pipelines were fundamentally not designed to accommodate internalaccess, where I think liquid lines for the most part were. There -- they need to run cleaning pigs. They run batching. There are different reasons why they would need to access the inside of the pipeline.
Fundamentally, pipelines were designed prior to the arrival of in-line inspection for a great majority, and gas pipelines were not designed to put anything inside there.
There's the issue of compressible flow. The inside of the pipe does not -- did not need to be contiguous, consistent, homogenous, to get gas to go through it. Gas is compressible. That is a fundamental issue that must be dealt with.
There are issues we've heard about. Valves. There are other issues, such as headers, cross-overs, and direct sales laterals that are not trivial issues. Just because we want to make them piggable and pound out a rule that says we will does not mean it will happen. These are significant events, and they need to be respected.
While these are difficult, they're not trivial. They do not excuse us from our responsibility to continue to inspect and ensure the integrity of these pipelines. It does, however, require that we incorporate other inspection techniques.
Back to our tree. There are more than just the in-line inspection leaf on this tree. We need to use these other leaves, if you will, to provide the integrity of the system. Hydrostatic testing is a well-proven technology. It's been used extensively, primarily in post-construction. It is a physical strength test.
It physically establishes a safety margin, but like ILI, hydrostatic testing does have its limits, especially regarding service interruption and reliability, as we get close to the customer, because of things like dew point and freeze-off.
Again, that doesn't mean we stop there. We must continue to push. Direct assessment is available to us. This is a new name, and there's a lot of angst about this name, I think, possibly because of its ambiguity, but it is a collection of proven technologies and practices, and as the name implies, it incorporates a direct assessment of the pipeline, an excavation down to the pipeline, to physically assess its integrity.
It's used extensively within the industry and outside the industry. The EPA recognizes RMP as its primary sole source of inspection for chemical plants and refineries. It is not some kind of voodoo science. It is -- it does work, and it's out there, and I think we need to avail ourselves to that in order to provide the assurances that we need to.
The standards are under development, and they will enhance the consistency of its application, and I think that's a fundamental issue that has to be championed to effectuate improvement in pipeline safety.
Where you don't have standards, you get significant diversity in application. We need to make sure that the application is appropriate.
I think the bottom line is we must avoid a false sense of security that we may like to get out of an in-line inspection. It is where we -- you know, it's one of those old things. It's the snakes you don't see that are the ones that bite you.
It's when you feel safe, that's when you need to be the most nervous. We need to respect the complexity of integrity management, the diversity of the threats that are out there. We need to understand the technical capabilities and limitations of the tools that are available to us, and we have to address the physical constraints, some of which can be removed, and we need to own up to that responsibility and get them out of the way, some of which can't, but we can't stopthere. We must move forward. We have to move forward in confirming integrity.
In closing, in-line inspection is a valuable tool. It has been, and it will continue to be an ever-increasingly valuable tool, but it does have limitations.
We need multiple inspection techniques out there. We have to. We can't just say just because we can't pig it, we can't inspect it. We have to inspect it. We have to ensure integrity. We need to respect and embrace the challenge of risk management and make sure we have all the techniques available to us, that we define our capabilities and limitations, so we can apply them where they're appropriate, and I think we have to develop standards to ensure their consistent use.
Thank you.
CHAIRMAN HALL: Thank you very much.
We'll now turn to Mr. Johnson, and these have all been very interesting presentations, and, Mr. Johnson, we are looking forward to yours, having, I guess, served -- worked on the Alaska Pipeline since 1973.
MR. JOHNSON: Well, Chairman Hall, Members of the Board, Members of the Technical Panel, on behalf ofAlyeska, I certainly appreciate being here.
We have over 20 years of experience running smart pigs. So, I think we have a lot to share. We also have a lot to learn, and I have certainly learned quite a bit just listening to this discussion here today.
What I want to talk about is integrity management on the TransAlaska Pipeline System, talk a little bit about our inspection history, our current practice, results, and some lessons learned.
If you don't know, the TransAlaska Pipeline System is an 800-mile crude oil transmission system from Prudhoe Bay to Valdez, Alaska. It's a 48-inch diameter half-inch wall thickness pipe. 420 miles are constructed above ground, and it was constructed that way to avoid unstable permafrost which would settle if a warm pipeline were built in it.
The remaining 380 miles are below ground, and that's where the majority of our integrity concerns exist, in that 380 miles. We also have a 148 gas transmission -- 148-mile gas transmission pipeline from Prudhoe Bay to Pump Station 4, and the gas is transmitted to provide power for the turbines which drives the pipeline.
The pipeline system was started up in Augustof 1977. So, we've been in operation over 23 years, which is not long by United States standards, but we are seeing some effects of age.
We currently operate at one million barrels per day throughput. We have operated at 2.1 million barrels per day, and since start-up, we have transported over 13 billion barrels of crude.
TAPS is important to the oil industry. It provides the link from the North Slope to the market. It's significant from a national energy standpoint in that it now transports 17 percent of the domestic crude supply.
It's very important to the State of Alaska. 70 percent of the operating revenues of the state are generated by the oil that's transmitted in the pipeline.
Alyeska has a history of aggressive in-line inspection. We started annual inspections in 1979. We've conducted 57 smart pig runs since that time. So, that would average about two per year.
We have been involved in research and development. We've used the pipeline as a test bed for corrosion tools and curvature tools, and we apply what we believe to be the best available technology.
We've had good results. We've never had acorrosion leak on the main line or the fuel gas line, and the predominant risks that we are concerned about are corrosion, settlement and outside force damage, although outside force isn't as much of a concern with TAPS because of its remote location.
For corrosion, we have used both magnetic flux and ultrasonic tools, and it has given us an opportunity to compare both. Currently, we use a high-resolution ultrasonic tool, starting in 1989.
Before 1998, we ran a corrosion tool every year. Currently, we run once every three years. We also monitor for settlement using inertial guidance tools. We monitor that concern every three years, and we also monitor for outside force damage, dents or deformation. We run that tool every three years.
So, we have a rotation using these alternate technologies over a three-year cycle, and then we're able to use all three technologies.
I'd like to talk a little bit about integrity management on TAPS. Many of the other speakers have already talked about the need to integrate all of this information into a system or into a program.
Over the last five or seven years or so, Alyeska has developed what we call a "corrosion control management plan", and it's focused, first of all, onprevention, and that's the use of Impress current cathodic protection.
Our pipeline was built with a zinc anode system, and we've added Impress current now on the bulk of the buried pipeline. We also use the detailed in-line inspection, and then another area that we're looking at is the integration of those two strategies.
In some cases, your testing may say you have adequate CP, but your pig says that you've got corrosion. So, there's an obvious discrepancy there that you need to go to and look at a little bit harder.
Another important feature of the integrity management plan is a system, a management system, I would say, a management system that includes performance measures, includes procedures, includes accountable resources and feedback, and then an annual review of the procedures for continuous improvement. We believe that's a very important point in that we continue to learn.
Alyeska supports the DOT Integrity Management Initiative and the API Standards that are being developed. We believe that that will actually improve pipeline safety as a whole.
What we plan to do is to convert our corrosion control management plan into this integritymanagement plan and cover the broader aspects of the new regulations.
I'm going to skip this slide. I want to spend a little time here, as much time as I have, to talk about our experience, and other speakers have already said this. In-line inspection is an essential element of integrity management, and they've said in other ways. What I've said here is that the results contain uncertainty, and the performance is limited in some cases.
The data interpretation's not black and white. Engineering judgment is required. Data interpretation using preliminary vendor data may be unreliable, and some data interpretation takes time.
Lastly, pigs actually produce risk. They can damage the pipeline.
If you look at in-line inspection, just look at the transducer, the transducer -- if you take a transducer, put it in a laboratory on a piece of sheet metal and measure the thickness, you'll find that there's random error and there's bias.
When you put that transducer on a pig, you get other problems in equipment malfunction, spurious signals, false calls. When you put that pig in a pipeline and travel it down the pipeline three miles anhour in a rough dark environment, you add further interference to those measurements.
What we've found is the performance depends upon the ratio of the defect size and the resolution of the tool. That's where the importance of high-resolution tools. The probability of detection that others have talked about, we see a range of 72 to 100 percent, depending upon the size of the defect, and I've given a range there of 50 to 250 mils.
The accuracy that we've seen in depth measurements of 10 percent nominal wall thickness is consistent with what others have said.
So, with the uncertainty in the measurements, you need to be conservative in your assessment procedures. Alyeska has been conservative. In the last seven years, we've dug up the pipeline a 180 times. Only four of those times have we found the need to actually repair the pipeline, which is consistent with other operators.
The interpretation takes trained expertise. We couldn't do it without very trained people. It also takes cooperation and coordination with the vendors and interaction of that data.
We've already talked about some of the reasons that in-line performance is limited. Weldscause roughness. A slack line means that you haven't got a full pipeline. So, you've got lack of liquid couplant. Sharp bends, high-speed, dents in the pipeline or waxing, that we've talked about.
The data interpretation requires engineering judgment. What we do is look at what we call a maintenance triage, which puts the data or the defects into three classes, the good, the bad and the ugly, if you want to call it that way, but the good certainly are the obvious -- there's no data. So, that's a no-brainer.
The bad, you've got a severe defect. You have to go to that immediately. But a very significant number fall in the middle, in the uncertain or gray zone. You may have conflicting data. You may have insufficient evidence. You may -- and the action depends upon risk.
Regarding risk, you always have to balance the risk that you're trying to mitigate with the risk that you take and the cost that you spend in going to explore that defect.
In Alaska, we have some special problems because of our remoteness. Pipe examination costs 300,000 to 3 million each. There's certainly an excavation risk when you dig up the pipeline. Industry-wide, the risk is one in 10,000 that you'll damage the pipe just digging it up, and certainly if you're in the river or difficult environmental area, you have disrupted the environment with that excavation.
So, data interpretation using preliminary data may be unreliable. The API Standard 1160 and the DOT regulations require a rapid response from the vendor. Currently, we receive our reports from our vendors in about a 120 days, depending. The new requirements are that a preliminary report come out in 30 days. That's going to stress us. We're going to have to work quickly, and there's the opportunity of making a mistake. So, that's a concern.
We don't really see the need for that. I've talked about our two percent repair rate before. So, we're very conservative. Also, the main corrosion mechanism for us is slow. So, we believe we don't have to, let's say, create an emergency out of every situation.
Some data interpretation may take time. Other operators have talked about that, and the reason for that, since we have run pigs every year, we rely on past data. We use our database to look at what's happening, what's changing.
So, if a current pig run gives you an indication that's not quite there yet, you look at the past data, and you look at data from future runs, and another concern that's already been raised is the need for more than one technology.
When you're exploring dents with metal loss, you really need two different tools, and also in the case of the interaction between curvature and corrosion, and, lastly, pigs produce operating risk.
We've damaged our pipeline a number of times running pigs. Just this summer, we received a pig in Valdez with a 500 pound ring from a check valve wrapped around it. The problem, of course, is that check valve isn't going to operate properly now. So, we had to figure out which one it was. We had to cut the check valve out, and we had to replace it, and that certainly is a risky operation in itself.
We've had pigs stuck in valves. We've lost large pieces from pigs, and we've had to figure out where those large pieces are in the pipeline. So, pigs are not the answer to every condition. We really need to make sure that the risks you're reducing exceed the risks you're producing.
So, in summary, again this has been said, in-line inspection is an essential tool for pipelinesafety, but it has limits. The regulations should acknowledge the uncertainty and the risk. The regulations should also encourage technology development.
Alyeska supports the DOT/API Integrity Management Rules. It's a good start. We believe it's going to improve the level of pipeline safety. Also, it acknowledges that every pipeline faces a little bit different situation, different risks.
We certainly urge a balance between prescriptive and performance regulations. We understand the arguments there. One concern that I have is that overly-prescriptive or punitive regulations can be counterproductive. They may result in technology stagnation.
Companies may be reluctant to try new things if they're not exactly sure what the outcome's going to be and what the reaction of the regulatory bodies will be when they run such a tool.
The punitive and prescriptive regulations may also result in what I call "suboptimization", and in meeting the letter of the law rather than the intent. So, lastly, in closing, I really want to say that pipeline transportation has been shown by the GAO to be the safest and most efficient means of hydro-carbon transportation available. It certainly has provided a great good for society.
Our record on TAPS, no corrosion leaks from any piggable section of the pipeline, certainly demonstrates that pigging can be effective. We haven't got a long history yet, but it shows. We don't want to rest on our record, as Andy says, but we certainly want to make sure that we keep that record whole.
Thank you very much.
CHAIRMAN HALL: Thank you very much, Mr. Johnson.
I think before we get into the questions, it's time for a break, and we'll come back at 4:00. We'll stand in recess.
(Recess)
CHAIRMAN HALL: We will turn then to our panel, and, Mr. Zimmerman, if you will then proceed with the questions, please.
We'll try to not be repetitive, so that we can move through the questioning, so the last panel will have an opportunity for some time before it gets too late.
MR. ZIMMERMAN: Thank you, Mr. Chairman.
As two different in-line inspections will need to be considered --
CHAIRMAN HALL: Is your microphone on there?
MR. ZIMMERMAN: I don't know. How's this?
CHAIRMAN HALL: Okay. Good. Just get a little closer, please.
MR. ZIMMERMAN: Okay. As two in-line inspections will need to be considered by the new integrity standard for high-consequence areas, and then your own risk management needs, I'd like to get a sampling from each company on the following question.
Has any of your companies been given an indication that tool availability will be limited to do the pigging that will be necessary?
I'll start with Mr. Yarborough.
MR. YARBOROUGH: We have not gotten any indications from the vendors about tool availability. We are somewhat concerned about that, but we have no way of quantifying it at this time.
MR. ZIMMERMAN: Okay.
MR. TURLEY: We have no indication -- we've gotten no indications either from the vendors primarily because it's so new, and we think, also, typically, they can't judge availability until they know the requirements of the customers, and that hasn't been given to them yet.
MR. ZIMMERMAN: Okay. Mr. Drake?
MR. DRAKE: I would agree with Rich on that. I think it may be a little early at this point.
MR. ZIMMERMAN: Okay. Mr. Johnson?
MR. JOHNSON: No indication from us as well.
MR. ZIMMERMAN: Okay. One more question then. I'll start this one with Mr. Johnson and come the other way.
Earlier, it was mentioned that there's many inspection techniques available besides in-line inspection, and I was wondering if you might be able to shed some light on any traditional inspection methods, coupled with any other monitoring that could be used to find internal corrosion, short of using an in-line inspection.
MR. JOHNSON: Well, I guess regarding internal corrosion, that's not been a big concern for us on the main line pipeline, because as long as we keep the fluid moving, we don't see much in the way of internal corrosion risk.
We do have internal corrosion concerns in the pump stations, and one traditional means of monitoring is just random digs at the low spots because the fluid drops out in the low spots. You go to those low spots. You dig up the pipeline. You do a UT measurement, and then you may come back a couple years later and checkit again. I think that's what Andy was referring to on the gas lines as a traditional means of monitoring.
MR. ZIMMERMAN: Okay. Mr. Drake, would you like to add to that?
MR. DRAKE: I would agree. I think that internal corrosion in gas pipelines, even with -- you know, typically, you have gas quality controls or gas quality monitoring, and you can use coupons and things like that, but even over time, with acceptable gas quality or good line quality gas, there are issues.
Internal corrosion typically is connected with liquids in the pipe or fluid collection, which is typically a gravity issue. So, you look for low points, and if you can understand to find those low points in the system and do inspections in there, excavate the pipeline and physically inspect the pipeline using ultrasonics or x-ray, I think you can get good conclusions about the risk susceptibility that you have at that.
CHAIRMAN HALL: Okay. Thank you.
Mr. Turley?
MR. TURLEY: We really haven't had a whole lot of risk with internal corrosion problems on our trunk lines.
We have had the occasion, though, that wehave utilized kind of a direct assessment technique to see if there was a potential for internal corrosion occurring, but in that case, it also comes down to what is a manageable number of locations to investigate at, and in our specific case, we felt that that was the number that was so large, that it was more prudent for us to internally inspect the line.
MR. ZIMMERMAN: Okay. Mr. Yarborough?
MR. YARBOROUGH: Having just refined products in our pipeline, and requiring our shippers to have corrosion inhibitors in their product, we have very few instances of internal corrosion.
We have had a case of a certain manufacturer of a valve had a piece of auxiliary pipe, called a "dead leg". We had some bacterial corrosion, but we have a program of examining all those valves. Other than that, it's really not a problem at Colonial.
MR. ZIMMERMAN: Okay. Thanks. Mr. Dyck?
MR. DYCK: Yes. Dr. Kiefner earlier mentioned that Mr. Drake might have some figures on the amount of pipeline that is piggable, and I'd also like to -- if any of the other panelists have any figures to add to that, that would be appreciated as well.
MR. DRAKE: Yes. The industry used a consultant to do a technical assessment of thepipeline, the operating conditions and the situations, physical constraints on the pipeline and broke the system -- characterized it into four basic groups, and that was readily piggable, either currently piggable or piggable without much effort, and then not much additional work, typically launchers or receivers needing to be installed, and then a third category being very, very difficult to make piggable, and then the fourth was physically impossible.
The breakdowns that I have here, easily piggable is roughly about 30 percent, not much additional work would be required was about 24 percent or 25 percent, very difficult in that fundamental system design would not accommodate pigs was 42 percent, and then impossible to pig, you know, never say never, but it was about two percent, and that's a consultant's opinion of the system.
MR. DYCK: And those are gas transmission lines?
MR. DRAKE: That's correct.
MR. DYCK: Okay. Are there different categories of gas transmission lines that break that out differently? Are there any other characteristics of different types of transmission lines?
MR. DRAKE: Yes, there are. Certainlythere's inter, intra, you know. There are folks here representing the American Gas Association, the LDCs, that are much closer typically to the customers, and they have a whole plethora of different issues than typical long line transmission companies do.
But, yes, there is -- these numbers represent a very wide spectrum of the industry.
MR. DYCK: Okay. Any of the other panelists want to answer that?
MR. JOHNSON: Our experience is pretty much limited to TAPS. All of our gas transmission line and our main line pipeline is piggable. We can't pig the facilities piping. So, that's a limitation.
MR. DYCK: I was wondering if Mr. Drake or anyone else could elaborate on this direct assessment, what a good direct assessment program would consist of.
MR. DRAKE: Direct assessment, as I said, is a collection of technologies, and it's just a name that's been applied to try to house a whole host of issues -- whole host of technologies.
Direct assessment, I think, for external corrosion, for which standards are currently being, you know, developed by NACE, basically incorporates electrical -- aboveground electrical techniques that are coupled with physical verification of pipe based onconditional issues or characterization of pipe, for example. It's coating, soil type, electrical continuity, things like that.
Other standards would -- you know, are being considered, particularly for the application of internal corrosion, which would incorporate system characterization issues, such as elevation, presence of liquids, type of gas, and then couple that with inspections of a different nature, which would typically be ultrasonics or x-ray or something, to measure the inside of the pipe.
MR. ZIMMERMAN: Mr. Wildey?
MR. WILDEY: Yes. Just one question area.
Mr. Johnson, you mentioned that you have, I believe, a two-percent rate of finds when you do digs. Do the areas you dig, and you find there's nothing wrong, does that represent a false positive or does it represent just your company's conservative approach to evaluating indications?
MR. JOHNSON: I think it's the latter. Most of the time, we find a defect which, if left to its own devices, will become a problem. We certainly don't want to practice what we call "just in time" corrosion engineering.
So, we want to make -- we actually are happythat we find these things ahead of time, and we can recoat the pipeline and put that one to bed, and we don't have to worry about that one.
MR. WILDEY: And I guess I would like to ask the rest of the panelists to -- if your companies' experiences are the same in the percentage of finds when you go and dig an area.
MR. YARBOROUGH: I don't have the statistics off the top of my head, but I'd say they're very similar. I mean, we make very few repairs. We take into account the inaccuracies of the tool that is specified by the tool vendor, and whatever the call is, we'll add to the depth or add to the length, and then make a judgment on whether or not to investigate that anomaly.
MR. TURLEY: Similar to what Elden had mentioned. We have seen probably around a five- to six- percent repair rate, but when we say repair, that's usually something more than a recoat.
In a lot of ways, we also look at a recoat as a repair because we're leaving the pipe typically better than the way we found it. I don't think that --similar to what Elden had mentioned, we are finding --there is usually something there.
Depending on the depth and severity of theanomaly, you can take that into account, and we do, and I think that's where we use the probablistic kind of techniques to help us feel comfortable that we've not left anything out there that would be injurious to the pipeline.
MR. DRAKE: I would agree that on our -- you know, on first generation runs and those involving standard magnetic flux level tools, leakage tools, that you're going to probably encounter more what we would call "recoat and backfills" than repair and replace-type anomalies.
I don't have the statistics off the top of my head, but I think as you move into the higher-resolution magnetic flux tools, and as you move into second and third generation in-line inspection, you have the capability of having a better analysis of the pipe, and as Noel Duckworth said earlier, you're looking for change, and if you've already inspected that pipe once, and you reinspect it again, there isn't the need to go and review some of those anomalies again if they haven't indicated any delta, if there's no change.
But I think the key element here is that, you know, one of them being the standard-resolution MFL and high-resolution MFL doesn't really differentiate in itsability to detect anomalies.
It typically differentiates in its ability to characterize the anomaly and size it very accurately. It's not whether it will see it or not. It's whether how accurately it will size it or not, and I think that's a key issue.
So, as you are working with MFL of a standard resolution nature, you need to be excavating a little bit more to make sure you're conservative in your sizing, but as you work to higher resolution, you can work a little bit more confidently because of the tool's ability to size is a little better.
MR. TURLEY: I guess one thing I would also add is part of the discussion or the reasoning probably behind that two to six percent number is typically, operators use a very, very conservative assessment equation in using the pig data that comes back in determining what to go dig.
But the assessment technique we use in the field, which relies on much more detailed measurement techniques in the field, will usually result in a better, I guess, characterization of the anomaly's ability to retain pressure.
MR. WILDEY: Thank you. That's all I had.
MR. CHIPKEVICH: Just a couple of questions.
Mr. Yarborough, you all at Colonial run a variety of different tools through the pipeline. Are you aware of any development or efforts to develop a multi-use or a multi-purpose tool that could do all the examinations with one tool instead of having to launch three different pigs through a line?
MR. YARBOROUGH: Well, we're aware that Becko is working on a multi-functional tool, and they showed us that earlier today. Obviously they have not rolled that out yet. So, that's not commercially viable at this point. That would be one of our ideal tools of the future.
MR. CHIPKEVICH: Okay. Thank you.
And, Mr. Turley, I understand that after an accident on one of your pipelines, that Marathon has done extensive testing with the new crack detection tool, and I wonder if you found that tool to be very helpful or if it's a new tool, and if it's really starting to identify cracks that other tools maybe wouldn't have found.
MR. TURLEY: Yeah. The anomaly that we're interested in there is a dent with a fatigue crack in it, and before earlier this year, that phenomena was kind of new to a lot of people.
We are utilizing and developing with PII thetransverse flux tool and really not necessarily developing it. We're just proving out if the tool works, to see that type of an anomaly, and we've been very successful with it to date.
I guess one of the things I would add, though, about the multi-tool, if you do not have the kind of anomalies that, say, a conventional or a high-resolution MFL tool would be blind to, you know, we're finding that we will get a full body inspection for corrosion just like a regular metal loss tool from the transverse field tool, also.
MR. CHIPKEVICH: Okay. Thank you very much.
CHAIRMAN HALL: Thank you.
We'll now move up to the Board Members, and we have all decided to limit ourselves in the interest of the last panel to one question each, and we'll begin with Member Carmody.
MS. CARMODY: Thank you.
This is for Mr. Yarborough. You had said you started your inspection in 1985 of your vintage pipes from '62 to '71, and your corrosion criteria for severe was 50 percent or greater and moderate was 30 to 50.
My question is this. Was there any relationship that emerged between the age of the pipe and the degree of corrosion? Is there any pattern orcorrelation?
MR. YARBOROUGH: Each pipeline is different. I think in general, you'll find that the older the pipe, the more likely you are to find corrosion, but in some of those pipelines, we found segments with very little corrosion, and we found others where there was never millions of hits, but there was a significant difference in the amount of corrosion we found.
A lot of factors figure into the equation. It's not just how old it is, it's what kind of coating. It's not just what kind of coating, it's how well it's applied, and then how soon did you get your cathodic protection system up, and how effective is it?
In Texas and Louisiana, the soils are very conductive, and it's fairly easy to drive current a long ways down there, and in Georgia and South Carolina, the soils are very high resistance, have a lot of high resistivity, and it's difficult to drive the proper amount of current to all parts of your pipeline. So, age is a factor but only one factor.
MS. CARMODY: So, no pattern, in other words?
MR. YARBOROUGH: Right.
MS. CARMODY: Thank you.
CHAIRMAN HALL: Member Black?
MR. BLACK: Yes, sir. Thank you.
Really to any of the operators. My question has to do with aerial inspection of lines, and how often you do it, and whether you really feel this is an effective way to avoid, as I used to call them, universal pipe locator damage, backhoe damage, to lines.
Mr. Yarborough, since you're from Georgia Tech.
MR. YARBOROUGH: Okay. We do use air patrol. A few years ago, we decided to bring that capability in house rather than contract it. So, we have our own planes, our own pilots. We try to patrol our pipeline once a week.
MR. BLACK: Once a week.
MR. YARBOROUGH: And with properly-trained pilots, it can be very effective. What you're looking for is not just a backhoe but any signs that they've been there or it's a development that's coming your way, people clearing forests or soil's been disturbed on your right-of-way. It helps.
MR. BLACK: Erosion damage and that sort of thing, too, I imagine?
MR. YARBOROUGH: Not -- there are no benefits as far as the corrosion issues are concerned.
MR. BLACK: Erosion.
MR. YARBOROUGH: Oh, erosion. I'm sorry. Yes.
MR. BLACK: Wash-outs, in other words.
MR. YARBOROUGH: Hm-hmm. Right.
MR. BLACK: Thank you.
Others, the same. We don't -- I don't know that we need -- once a week?
MR. TURLEY: My comments would be similar to Vic's.
MR. BLACK: Once a week, though?
MR. TURLEY: Yeah. Once a week to once every two weeks.
MR. BLACK: Thank you, Mr. Chairman.
CHAIRMAN HALL: Any other comments?
MR. DRAKE: In some of the congested areas, we fly up to two or three times a week, and we have found it to be very effective. You know, where you've got a lot of activity, you almost need to be out there very regularly, and that provides us and affords us an opportunity to keep an eye on those activities.
CHAIRMAN HALL: Mr. Johnson?
MR. JOHNSON: I would say because our pipeline is remote, it certainly does represent a way of keeping track of what's going on. Floods, landslides, and anything of that would be noticedwithin a week.
It's also kind of a last-ditch leak detection method. We have had a couple of leaks on our pipeline, and they were discovered by the over-flight. So, the damage was limited because we discovered it earlier than we would have otherwise. So, I think it's a good technique.
CHAIRMAN HALL: Okay. Member Goglia?
MR. GOGLIA: Just one quick question to all of you. Your data analysis. Mr. Yarborough, you can start it. In-house or out -- or contracted out?
MR. YARBOROUGH: The analysis is -- comes as part of the package of the tool. It's tool run. We get the analysis from the vendor, but in house, we have people that look over their shoulders.
We'll take our people, and we send them to the vendor shop for training for two or three weeks, if they're new to our program, internal people new to our program, and they have the advantage that they not only see what the chart says, but they get out in the field and see what we actually find, and in a lot of cases, I think they have -- are about as skillful as some of the contract vendors at identifying the anomalies and classifying them.
MR. GOGLIA: Mr. Turley?
MR. TURLEY: We tend to rely on the vendors themselves for that data analysis. I think we emphasize on our side internally actually the checks and balances of ensuring that the data was sorted correctly and laid down correctly, and I think we emphasize the overlaying of the other data structures in house. That's when we apply the close internal survey information, the topography information. That's predominantly what our in-house folks do versus the data analysis.
With a lot of the higher-resolution tools, the ability to view and manage the raw data itself is pretty problematic, and we've let the vendor do that.
MR. GOGLIA: Mr. Drake?
MR. DRAKE: We require the vendors to provide us a first review, first assessment of the data, because of some of the uniquenesses of each of their formats, but then we sit down shoulder-to-shoulder with them and walk through the log explicitly.
MR. GOGLIA: Mr. Johnson?
MR. JOHNSON: We have a similar experience. We rely on the data for the first cut -- the vendor, excuse me, for a first cut. He provides us with a listing. We then rely on our own engineers to make an assessment, to evaluate and make a decision based onrisk, and then there's really a third piece of the puzzle as well, in integrating all of the data.
We've spent quite a bit of time. We employ computer professionals who actually maintain our database, so that we can integrate information back and forth through the various pig techniques and keep track of construction data, design data for each joint of pipe, and then be able to draw up that data over time, I mean, to look back, if you will.
So, the data integration is another very important piece of the puzzle.
MR. GOGLIA: Okay. Thank you, gentlemen. No further questions.
CHAIRMAN HALL: Member Hammerschmidt?
MR. HAMMERSCHMIDT: Okay. Thank you.
The one main question I was going to ask is the question really that Jim Wildey asked previously, but I do have this question for Mr. Johnson about part of your presentation.
When you -- just to make sure I have it right in my mind, you mentioned that in the portion of the Alyeska pipeline that is underground, that due to internal inspection information, that you have excavated a 180 times. Was that basically what you said?
MR. JOHNSON: Yes, and actually, we have excavated a lot more than that. We've -- since -- we actually discovered corrosion in 1989, and it led to possibly an over-reaction, but we looked very aggressively.
So, we have actually dug up the pipeline about 800 times or more than five miles, based on pig calls, if you added it up end-to-end, but the data that I was referencing was over the last seven years, and we've only excavated the pipe a 180 times in the last seven years, and the assessment technology has developed quite a bit.
We use the RSTRENG technology now. It's a little less conservative than it used to be. In the past, we had a large number of excavations using the B31G criteria from ASME. Now, we rely on the RSTRENG criteria. So, it actually points to less locations to dig up.
MR. HAMMERSCHMIDT: Okay. And of that 180 times, you referenced four times that necessitated a repair to the pipe, --
MR. JOHNSON: Yes, sir.
MR. HAMMERSCHMIDT: -- is that correct?
MR. JOHNSON: Yes. Yes, sir.
MR. HAMMERSCHMIDT: And not to be repetitive,but what was done to the pipe in the other 176 times?
MR. JOHNSON: When I talk about repair, we assess the strength of the pipe, and it's not capable of supporting the operating pressure. So, what we do in those cases is we put a full encirclement sleeve around the pipe, so that we actually reinforce the corroded area. So, that's four times out of a 180.
The other times, we recoat the pipe, we install cathodic protection and restore it hopefully better than it was before.
MR. HAMMERSCHMIDT: Okay. Well, that was more or less my understanding of --
MR. JOHNSON: Yeah.
MR. HAMMERSCHMIDT: -- your answer to Mr. Wildey's question.
MR. JOHNSON: Okay.
MR. HAMMERSCHMIDT: And the last question is, is it your estimate that each time you do an excavation, the cost is somewhere between $300,000 and $3 million?
MR. JOHNSON: Yes, sir.
MR. HAMMERSCHMIDT: Okay.
MR. JOHNSON: It depends. We've had a couple of very extreme costly excavations. One case where we had 40 feet of cover on a very steep slope, and itnecessitated a very highly-specialized excavation method, and, of course, if we ever had to dig under a river, you know, you'd have to pick your time. You'd have to probably come up with a coffer dam-type approach. So, it can vary to that level.
MR. HAMMERSCHMIDT: Okay. Thank you, sir.
MR. JOHNSON: Thank you.
MR. HAMMERSCHMIDT: I want to thank all panelists for their presentations.
CHAIRMAN HALL: Well, my question is for Mr. Johnson.
Mr. Johnson, while the other three operators that are on the panel with you, the companies are very well known in the regions they serve, I'm sure you take great comfort and delight in knowing that your pipeline is probably known by almost all Americans, and if there's a problem with it, almost all Americans will hear about it, and you have been there since the beginning, is that correct?
MR. JOHNSON: Yes, sir.
CHAIRMAN HALL: Since there were no standards we've identified that the industry has or government has in this area, how did your company go about determining standards for internal inspections?
MR. JOHNSON: Well, I believe there are anumber of standards. ASME certainly has their B314 standards for evaluating defects.
Now, we use the same standards applied to inspection data, pig data. So, I think there has been standards that have been out there that have given us some guidance. API has had standards.
We have actually had to develop our own standards. I talked about our --
CHAIRMAN HALL: Would you say that you meet or exceed those standards you mentioned?
MR. JOHNSON: I believe we meet or exceed, yes.
CHAIRMAN HALL: I thought people from Alaska were supposed to be straightforward.
MR. JOHNSON: How much more straightforward can you get?
CHAIRMAN HALL: No. That's fine. Go ahead.
MR. JOHNSON: No. I think what I was going to say is we've taken the standards that were there, and we've applied our own engineering judgment in a lot of cases, and we've had to develop our own procedures.
I talked about our continuous improvement program, and we write our procedures down, and we follow our procedures, and then, at the end of the year, we evaluate those. Are they working for us? Arewe getting feedback from our results that are telling us that we're not being conservative enough or that there are new risks out there? There are new opportunities out there.
So, it gives us an annual opportunity to improve the procedures, and then all the time, the regulations are changing, the standards are changing. Guidance which we used before that we developed ourselves are being superseded by industry standards.
So, you just have to be adaptable. You have to be flexible.
CHAIRMAN HALL: Well, I'd like to thank the panel and offer you an opportunity for any closing comments. Mr. Yarborough?
MR. YARBOROUGH: I would just like to say, as I mentioned in my presentation, it's been a continuous learning experience for Colonial as far as internal inspection. It's been continual improvement in the capability of the tools and continuous improvement in our knowledge about what we're finding, what causes accidents, and we just feel like our program has improved tremendously. There's still a lot of work left, we're still working hard, and it will take more than just pigging pipelines to prevent accidents. It's just one facet of an integrity management program.
Another area where a lot of work still needs to be done is prevention of third party damage.
CHAIRMAN HALL: Thank you. Mr. Turley?
MR. TURLEY: I have no closing remarks.
CHAIRMAN HALL: Mr. Drake?
MR. DRAKE: I appreciate the opportunity to talk with you, Mr. Chairman and the Board, and address this issue. I think that this kind of dialogue is going to be essential to resolving this issue. It isn't going to be resolved quickly or with one quick write of some rule or one quick tool. It's going to take a complete understanding of the complexity of the issue, the limitations we face, and it's going to take a significant effort to develop the standards around which we were going to try to perform this effort.
Thank you.
CHAIRMAN HALL: Mr. Johnson?
MR. JOHNSON: Thank you, sir. I really have no further comments, other than to say thank you very much for this opportunity to participate in this panel. I have learned quite a bit. I appreciate it.
CHAIRMAN HALL: Well, I hope it's useful, and we appreciate the very proactive approach that you all have described that your companies take to safety of the environment and the individuals.
We will excuse this panel, and we can all do a stand-up break for two minutes while we seat the last panel of the day.
(Pause)
CHAIRMAN HALL: I would like to start with one brief announcement.
We are going to have a box -- where is that going to be located, Bob? A box in the entrance. If you would like to leave your business card in that box or to put your name and address on a piece of paper and place it in that box, we will be glad to write you and inform you when this transcript will appear on the web page as well as information on any additional events the Board has upcoming in this area.
Mr. Kris, we look forward to the next -- to our last panel of the day, and would you please introduce the panel for their presentation?
MR. KRIS: Yes, sir, Mr. Chairman.
The final panel of the day is the Researchers Panel. On this panel is Dr. Brian Leis and Dr. Tom Bubenik from Battelle, and Mr. Al Crouch from the Southwest Research Institute.
Panelists, I would like to remind you that you have 15 minutes to give your presentation. The yellow light in front of you will go on when you havetwo minutes remaining. The red light indicates that your time is up.
Mr. Chairman, staff is ready to hear from the panelists.
CHAIRMAN HALL: Well, I am ready to hear from the panelists, and I welcome each one of you here, and I have to say parochially I welcome the folks from Battelle because you all just took over operations at the Oak Ridge National Laboratory. So, please proceed.
DR. LEIS: Thank you very much, Mr. Chairman.
Let me begin by expressing my thanks for the opportunity to address you this afternoon in terms of research.
I'm going to begin by talking about research from an integrity perspective, and Tom will take over and talk about research at the level of in-line inspection, and then Al will bore down just a little further and talk about some details regarding in-line inspection.
With that as background, I guess I'd like to begin by pointing out that incidents still occur. It's been an unfortunate aspect of what reality is of late. That incidents still occur indicates that the leading practices that we have for the management of integrityare either not widely available, they're inconsistently or improperly implemented, or they're due to circumstances for which the practices still need to be improved or developed.
In regard to the first two, John Kiefner has pointed out developments of standards that will help to address concerns for these issues in regard to liquid lines. Andy Drake addressed issues in regard to direct assessment for the gas industry, and I'll point out that there are also standards being developed for the other integrity assessment practices within the gas industry. So, those two aspects are being dealt with in the context of the development, the on-going development of standards.
Research tends to pick up and address circumstances for which there's still problems. In addition to the concern for incidents, I think it's fair to say that research is occurring in the gas industry because good business simply dictates it's a wise investment, because incidents cost money, and I won't go any further than to make that statement.
If you look at the previous slide in a little more detail, you can see external drivers for the research that's gone on. Those external drivers include considerations in regard to materials.
There was a question earlier about materials development. That's one of the key drivers for the research that's going on. There are developments in allied technologies, whether they're in, for example, computers or communications, satellites, in regard to communications. That was mentioned earlier.
There are a number of allied technologies that are being, if you will, adapted or built into the gas industry and its ability to deal with integrity problems, and, finally, business issues, whether they be market-related, regulatory-related, as for example, concerns that have us here today, or public opinion.
Let's talk now for a few moments about who is spending the money on research before we talk about what research involves.
There are non-competitive issues that tend to be addressed in a research context by industry groups. Those industry groups include, for example, the PRCI, and by way of example for the amounts of money that are being spent, PRCI's budget over the last 15 years has been on the order of five million a year.
GTI or formerly Gas Research Institute has an even more significant budget, the portion of which, when pooled with PRCI, currently dealing with line pipe problems or pipeline systems problems, is on the orderof 10 million a year.
Other organizations that are actively involved, European Pipeline Research Community, API and others. Generally safety issues and economic considerations drive this because at that level, they tend to be non-competitive concerns.
There are joint industry programs that involve pooled funds, and those are largely targeted at safety concerns, although economic drivers exist as well, and, finally, there's obviously government money involved, and that's often in a cost-shared framework and very directly focused on safety considerations.
The other side of it is competitive issues. Individual pipeline companies are involved here, and it's usually focused on safety issues, although economic drivers play into this as well. Vendors and suppliers are also involved heavily, and we talk about those in a little detail. Time permits those to be downloaded from the website to read the details.
The bottom line is that integrity R&D is a major focus for all of this.
Let's talk now about integrity management and the related research and development. A number of people today have talked about what constitutes an integrity management program. So, I'm not going to getinto the details.
I'll simply point out that from a hydro- or proof-testing perspective, it's largely mature technology. That technology, as the others are, is driven at the objective of ensuring firm deliveries in a value-based operation with safety as a major consideration.
Inspection plays into this, and R&D currently is quite heavily involved, as Tom and Al will discuss in regard to in-line inspection. Direct assessment is a means to periodically assess condition, and I list other equivalent here as a potential research opportunity, although it's a very ill-defined area.
Once one's assessed condition, we have to do maintenance, and here we have pre-programmed or routine work which is largely mature, and we also have what I would call "fitness for service" base, and this is a major hotbed for research and development.
What types of research are underway? Well, there's basic research, and I have to point out here, I list biggest risk and potential increment. I want to define what risk is here.
Risk is not risk of failure in the pipeline context. This is risk of investing in research and failing in making a wise investment. So, not allresearch pays off, in other words.
The increment means how much you learn or gain in understanding and ultimately, when implemented, move safety forward. Tends to be directed at longer-term needs. Market share aspects do play into it.
There's developmental and adaptive, and in this context, the pipeline industry is no different than any other industry. There's basic developmental work and applied work going on. The developmental work tends to be more near-term. Competitive aspects figure into it. It's often safety dominated, though.
Applied technology. There's obviously limited risk here. The increment in knowledge is smaller, but the increment in safety is often very large because these applied programs are often focused on very specific safety concerns within the company.
So, while not much knowledge is gained, large increments in safety occur as a result of the risk reduction that accrues to the work. Unfortunately, the results tend to be generally held within the companies because they're company-specific concerns.
We talked, I think, enough about drivers, and the time is limited. So, I'll put this up here. Those that choose to download can see the drivers in detail and explore them as they have time.
Let's talk about basic research and what opportunities exist. I list here two that are associated with materials issues. Activities where, if these were pursued, there could be major improvements in the steels and in the technologies in building or constructing new pipelines. It doesn't address the issues of older pipelines, but it does speak to avoiding future problems.
I list another group here, which relate to inspection, either pre-service inspection, ensuring quality products going into the ground and quality construction, as opposed to in-service inspection involving, for example, in-line inspection.
I also list in-the-ditch sizing, because it is part of the reality. We don't have the tools as Tom will point out. We don't have the tools that we need to get necessarily all the details about cracks, and in-the-ditch technologies are being developed.
There's another group of technologies that are associated with monitoring and assessing. Finally, there's a group of technologies that are associated with operations in maintenance, and I again list these here. Time is not on my side to discuss programs like this in detail, but one could lay out research for every one of these line items.
Let's talk a little more about developmental and adaptive activities. There are drivers listed here, and more specific activities. The one I want to pick on or the two I want to pick on on this slide are the second one, that's practical contact and encroachment detection, along with response and decision management.
Third party damage has been talked about a lot in terms of a potential cause. Pigs will find existing damage, but you can inspect tomorrow and have third party damage cause an immediate failure the next day.
So, clearly, there's a class of problems out there that in-line inspection won't address, and other research is needed, and other developments are required in order to simply avoid the problem, and this particular line item would deal with avoidance of contact through encroachment detection and actually catching the guy before he gets a chance to dig, and in the event that he does get in there, contact monitoring would let you know that he's been there, whether he wants to let you know or not.
The other one I want to point out is smart pipelines and an opportunity that they present to improve the management of integrity and systems ingeneral, and I guess I would argue that this has benefits both from the point of view of safety and operations efficiency.
It has the potential as well to avoid bottleneck problems and other things like that. So, activities, such as development of smart pipeline as a package of technologies integrating in many ways what already exists is out there. It's kind of a plum waiting to be picked.
Let's talk very briefly now about applied technology. My time is winding down, and I need to begin focusing on the last three slides.
Applied technology, the drivers here are very straightforward. They're avoiding incidents. They're increasing operations and maintenance efficiency, and in a lot of ways, what does -- one gives rise to the other. These tend to be very situation-specific problem-solving, process improvement and so on, and I list some examples there for those that again choose to download and have the time to read this at their leisure.
I want to now turn my attention to where I see the opportunities, and I had a pocketful of money, and I was very benevolent and sufficiently rich to afford to be that benevolent. These are where I wouldtend to put the money.
I've got a total of six areas, four of which are here and two of which are on the next chart. Improved public safety in terms of reducing risk, improved environmental safety in terms of reducing risk. These are being dealt with in the context of risk reduction, integrity management programs.
They're largely targeted to high-consequence areas because that's where the biggest risk reduction's going to occur. There are supply issues, and in some respects, as supply in current basins is exhausted, you're going to see opportunities, for example, on the North Slope. There's discussion of a pipeline coming from the North Slope. Very cold, pristine environment. Offers a whole new class of problems in comparison to a lot of what gas pipeline industry has faced.
There's drivers for higher pressure there, and with that also the opportunity that you're going to find rich gases, potentially corrosive product streams, and here, what we can do is enhance fracture arrest technology. We can do things like develop better materials.
So, there are responses that need to be in place before we get to these issues, and we need to be moving there before it's too late.
We need to focus on expanding high-consequence areas. In a lot of ways, this looks like the first one, but it isn't. This is more the concern for encroachment on pipelines, and I've mentioned already contact encroachment and detection. These should be commercialized and moved into a practical setting. That's the only place research has value, is when you put it into practice.
There's market share considerations that I list here, and I bring up the question of smart pipelines in that context.
Improving O&M performance and efficiency are concerns that research is directed at, and there's some other important topics, and I want to pick on one of these. It relates to distributed generation which is going to come in the power generation game, and with distributed generation and particularly in piquing applications, you're going to see large pressure cycles put on gas pipelines.
Large pressure cycles in gas pipelines have not been a common occurrence together, and it presents a whole new class of potential problems and failure mechanisms that we need to be aware of.
By way of conclusion, a lot's been done to supply clean, efficiency energy. It's been done inmany ways at minimal risk. More importantly, though, things are changing, and I point out that Noel indicates change is a big driver. This is change different than he talked about change but, nevertheless, a key driver, and with those two, we need research, some of which we've discussed, some of which we haven't.
This needs to be done to continue to move us toward safer pipeline systems, and with that, I'll turn the table over to Tom.
CHAIRMAN HALL: Well, thank you, Doctor, and we will -- oh, there we are. Tom's already loaded and up.
DR. BUBENIK: Can we have the computer screen back, please? Okay. Here we go. Thank you very much.
As Brian mentioned, I'm Tom Bubenik, and I'm also at Battelle. I've been there for about 10 years, and I've worked in the pipeline industry now for about 20 years.
What I'd like to do today is I'd like to give you a little overview of who Battelle is. I think that I'm glad to hear that you were aware of who we were, Mr. Hall, but I'd also like to let the other Board Members know as well as some of the audience folks.
I'm going to give you some examples ofresearch and development in the inspection area. I'm going to give you an overview of how inspection technologies evolve, and I think this is important as you look at and you think about how you might develop rules for pigging in the future.
I'm going to talk about where those technologies are today, where they're going, and where they might go, and then I'm going to give you a set of conclusions and recommendations.
First off, Battelle is a large, what we call, technology development company. We've been around since around the 1930s. We do work for governments, and we do work for industries throughout the world.
We've worked on pipeline-related issues continuously since the 1950s. After World War II, when the liquid -- a lot of the liquid infrastructure was converted to natural gas, we began our involvement, and many of the technologies that you'll see used and talked about by pipeline companies today were developed at Battelle.
You've heard about different corrosion assessment techniques, B31G or RSTRENG. Well, those were methods that we developed. Hydrotesting, in-line inspection, while we didn't develop those, we developed guidelines for many of them.
To give you an idea of who we work for in the pipeline area, I've broken down into five main areas, and what you can see from here is that we do work for industry, we do work for government, and we do testing work as well for the inspection vendors.
So, I have the unique opportunity to anger everyone with what I say at one time or perhaps to make you all happy.
I'd like to give you my view or our view of where we think pipeline technology is, and I think this won't come as a surprise after what you've heard and seen. There are many things that can degrade the performance of a pipeline system, just like anything else in the world.
There are ranges of tools we've seen today that detect and sort and size the problems that are out there, and there are techniques that Brian talked about for assessing the defects and anomalies and repairing them.
In the research and development arena, we look for holes in those areas, and holes that we might be able to solve and fix, and holes exist there. They exist there everywhere, just like they do in any other industry, if you look hard enough.
Now, Brian mentioned where research anddevelopment was funded by different organizations. Again, I'll mention the same thing. I will note that the efforts can be either short- or long-term, longer-term being the more basic work that Brian talked about and short being more of the developmental or applied.
In the inspection area, the efforts have become more short-term because there is a direct push for more immediate impact. What we'll see is work that's being done not only by industry consortia and the government but by suppliers or inspection vendors like you heard earlier today and by individual companies.
As an example of some of the prior inspection-related developments that were done, historically the pipeline industry's been active in sponsoring work in the inspection arena for at least the last about 15 years or so.
There are several reports that are being written by different groups that you can access, and I'm sure that there are folks here that can tell you where to get those to summarize the prior events.
Some specific programs I'd like to mention is one is a pipeline simulation facility. That's a test facility that actually Battelle has the opportunity and honor to operate, and it's for developing and testinginspection tools.
There are also programs underway to develop new technologies for finding and sizing selected types of defects or to extend the range of currently-existing tools to different diameters or more difficult inspection.
Oftentimes, when you're getting into those latter two, those are the difficult problems. As you heard once or twice before already today, the easy things have been done. All right. Now, as we try to improve inspections or as we move inspections from, say, corrosion to mechanical damage and cracks, we're getting more and more into the difficult problems.
Currently, some of the current programs that are underway that I'm familiar with is programs to commercialize existing technologies and use them in more powerful manners.
PII was here and talked a little bit more about their wheeled ultrasonic pig this morning. There are efforts underway to build more of those. There are efforts underway with Tuboscope to build multi-technology tools. I heard questions about those already. Can we build tools to do more than one type of defect? And again, there's development of inspection methodologies for defects that are hard tofind.
Mechanical damage is one of those that's an area that Battelle is working on a lot. Mechanical damage, when we're trying to define what is a problem we're looking at, we need to think about what we're trying to find, and how we're trying to find it.
Mechanical damage maybe causes 30 or 40 percent of the incidents, but most of those incidents occur right away. So, what we want to do is find those pieces of damage that can be left in the pipeline and might cause an incident five years down the line or 10 years down the line, and to be honest, I'm not going to look for those that will form an incident 30 days down the line because the changes of pigging for those are really not too great.
I mentioned that I'm going to talk about evolution of inspection technologies, and I want to do this to put research and development in perspective. When I think about inspection technologies, especially for pipelines, I seem them going through four distinct stages.
First off, we look for methods to detect things. Can you find a crack? Can you find corrosion? Can you find mechanical damage? And we heard talk about some of those today. People were building newtransverse flux tools to find cracks.
After you find them, we get to a process where we try to sort or estimate their severity, try to make certain that they're not something else, and want to know is this a little bit there, medium-size or a big problem, something we should address right away, or something we don't know when we're going to address it?
After that, we evolve into an area where we're sizing some of the defects, and we're doing a better and better job of that. MFL tools today, I'll talk about in a minute, size certain defects very well, and eventually you move to a point where you size all defects or all of a particular class of defects, and you try to do them all accurately.
One of the things you've also heard today is that most of the pigs that are out there today have been designed to find and size one type of defect. We've heard talk earlier about missed calls. Well, something that was called -- was not called mechanical damage, and I'll note that these were corrosion inspections, and what I think that's telling me is that inspections were doing a pretty good job of calling the corrosion, they just weren't doing a good job of calling the mechanical damage. They weren't looking for them in the first place. That's something thatneeds to be looked at in the future.
I'll also make a comment with regard to the inspection tools that are out there, and that is, when you make a change, let's say we go to transverse MFL from axial MFL, we've heard a lot of good things about what it does, and what often happens as well is that we get a reduction in another area.
We find a pig that does a better job of finding seam weld problems, and it does a worse job of sizing general corrosion. We find a pig that perhaps can go through tighter and tighter bends, but it doesn't do as good a job inspecting the pipe it does, or maybe pigs that go through tighter, smaller and smaller valves, they don't do as good a job detecting and sizing some of the other defects. So, you need to keep that in mind as we go along.
I want to give you an example of that development in metal loss pigs. You've heard earlier that the pigs were first introduced around the 1960s. What they did is detect or find corrosion on the bottom half of the pipe. That was their job.
Circumference and sorting capabilities arose in the late 1960s and '70s. Defects were called low, medium and high. The over-50-percent criteria that you heard earlier, that was the general definition of a bigdefect. The 30-to-50-percent, well, that was the general definition of a medium defect.
Low-resolution pigs still exist and have good detection capabilities and pretty good sorting capabilities. Someone asked a question of whether or not we would ever get rid of low-resolution pigs. That asks a question, why do we want to?
In certain applications, low-resolution pigs are very good. Why? Because they do a very good job of detecting problems. Don't have a lot of problems on a pipeline. You can use a low-resolution pig to find what's there and excavate.
Accurate sizing began around the 1980s, and it continues to improve today, but there is no pig out today, and you've heard some talk about what the accuracies are, but there's no pig out there today that will accurately, very accurately size all types of metal loss defects.
I'm going to give you my assessment of current in-line inspection capabilities, and I'll put them in the same general categories as detect and sort and size some and size all, and I've grouped defects into three broad categories, metal loss, mechanical damage and cracks.
In the very dark colors, those are where Ithink things are excellent. I think that MFL tools today are excellent at detecting and sorting defects. They're pretty good at sizing some of the defects, and they're good at sizing all, but they don't do an excellent job there.
With regard to mechanical damage, things are a little bit less developed, and it's going to take a little while for them to move in as we fill in this matrix from the upper left to the lower right.
What do I mean by some of those things? Metal loss, you heard today. Most inspection vendors will claim an accuracy of plus or minus 10 percent of the wall thickness 80 percent of the time.
You were asked in the question, what did that mean? Well, it means if I have a hundred defects that are called as 30 percent, 80 of them or somewhere between 20 percent and 40 percent, 20 of them are not. 10 of them are probably greater than 40 percent, 10 of them are probably less than 20 percent. Okay. That's a kind of accuracy that's quite good for metal loss corrosion as exists today.
Exceptions. Which are the ones that really cause a problem there? We've heard this already. Long, narrow defects or very small defects are the ones that do. I mentioned those two in particular becauselong, narrow ones are the ones that can cause ruptures, and small defects are often the ones that cause leaks.
With mechanical damage, we've heard talk about what they can do. They've got improved detection and sorting. Caliper pigs are out there. A good job of finding dents, particularly those with dents greater than several percent.
We've heard code allowances of six percent or things that people want to repair, six percent or more. What about those that are less than those? A lot of times, mechanical damage from a backhoe is far less than six percent, far less than three percent, can be less than one percent, can be very, very small, and that's why folks right now are looking at these different opportunities to look at the top half of the pipe, hoping to be able to narrow the list of where they're finding defects to find those that are most significant.
Is this the only answer? No. In fact, you can always find situations that are not quite like that. We'll find a situation where there are some damage on the lower half of the pipe that's mechanical damage from a backhoe.
I'd like to tell you a little bit about where I see the programs today, and I've put on here fiveprograms that I'm aware of, just to give you a general idea.
Generally, the research and development that's underway in industry is aimed at moving again this dark area at the upper left down and to the right. There's a joint program between the Department of Transportation and the Gas Research Institute or GTI today, and it's really looking at mechanical damage. It's looking at extending its ability to detect, sort and size.
We've got some pipeline research committees under national or PRCI programs that are looking at cracks. There are programs with the vendors, often in co-funding with industry, to develop multi-tech pigs and transverse flux pigs, and that shows basically where they go.
What else can you do, though? We've talked a little bit about where these things are. We've talked a little bit about what's being done, and I think I've got another couple of minutes here, and I'll tell you where I think we could go as well.
One of the things we've heard a lot of talk about is why aren't there some standards or specifications for smart pigs out there today? We've seen them around. People have been using them.
I think one of the reasons that there have not been standards in the past -- I'm not a real strong supporter of standards in that I believe it tends to set a lowest common denominator. This is -- everybody has to do no worse than this, and I'd really prefer people do as good as possible.
What I'd like to do, though, rather than see standards, to see standardized ways of measuring accuracies. Why? Because then pipeline companies and pig companies can know exactly what these pigs can do, and they can use them in their integrity management plans. This can be done today. It can be done relatively easily. It should be based on statistically-significant amounts of data.
There have been some programs that have been looking at that. So, that's one of my things that I suggest can be done.
In addition, this is not going to come as a surprise to any of you, most of the current developments were aimed at using single technologies. I think we ought to be looking at multiple technologies.
Why was this not done before? A lot of it had to do with the computer capabilities and the ability to handle these massive amounts of data.
We heard today earlier talk about a pig that was going to be able to take 4000 channels of data once every tenth of an inch along the pipeline. That's a lot of data, but combining and using those existing technologies, something we call "data fusion", can help improve everything that we're doing.
It requires a different mindset. It's not as easy as you think to use them all together. It's a process of really overlaying and understanding when various things happen at concurrent times.
So, here are my conclusions. I think pigs have an important role in overall integrity management programs. I'll agree with what others have said. They're not the panacea, but they're -- they can be and should be an important part of these programs.
They have strengths. They reliably detect a number of different types of corrosion and metal loss. They detect some mechanical damage, some cracks, and they do a reasonably good job of sizing some of those defects.
They can't be used in all pipelines. Well, we know that. So, that's where we need to be aware and look for other opportunities to demonstrate the integrity of a pipeline, and there are still some types of defects that they're not doing a very good job offinding, and those are areas for possible future research.
So, my recommendations. We've got one tool for evaluating pipeline integrity. Like other tools, we should keep it in perspective. We should start measuring and accounting for accuracies. I think that's possible now. I think it's recommended.
In addition, I think we should continue to look at extending selected pig capabilities, especially with regard to some of those defects that have caused problems in the past, mechanical damage and cracks, using existing combinations of technologies to better size and better detect a larger population of defects.
Thank you very much.
CHAIRMAN HALL: Thank you very much, Doctor, and I guess we'll now turn to Al.
MR. CROUCH: All right. Thank you very much.
I'd like to express my thanks for having the opportunity to be on this panel.
My name is Al Crouch. I'm a staff engineer at Southwest Research Institute in San Antonio.
Our organization is very much like Battelle as it was described to you. We've been very vigorous competitors in the past, and more recently, we're more likely to be collaborators and team mates on a givenproject.
I'm going to be a little more specific and talk about some actual projects, take you into the lab and show you some of the things that we've been doing, and some of the results that have come out, and then maybe make some blue sky guesses as to what things could be done in the future, all to the benefit of pipeline integrity.
One of the roles for an R&D organization is to do studies, to do surveys, and to do technology assessments that bring information to the public or at least to the client.
We've been involved with some of those. I'd like to mention several. One is a topical report on in-line inspection. We did this back in 1993 for GRI. This was an attempt to bring some technology descriptions for in-line pigging to an audience that may not have been familiar with that technology, with no pipeline background.
It was one of several reports that GRI did fund. I think all of those are still available and can be purchased from GTI, probably available through their website.
Second is an assessment of technologies to be used in the detection and characterization of stresscorrosion cracking.
What we did was looked at all of the technologies used in other industries for crack detection and tried to rate them as for their applicability to the pipeline environment and the likelihood that they would be effective in detecting stress corrosion cracks in pipelines.
Our conclusion was that ultrasonic technology was the most likely to be fruitful and accurate in detecting and sizing these defects. I think that later developments in hardware and systems have borne out that assessment.
A third report, done for the PRCI, was a survey of NTD needs for pipeline integrity assurance. In 1986, Battelle produced the first of these reports, and that served as a guideline for R&D in the pipeline integrity area for the nearly 10 years, up until 1996, when we did our survey.
Theirs recommended, for example, that there should be a center of excellence, a pipeline facility, which now has been realized in the pipeline simulation facility in Ohio.
Our survey revisited those needs in the light of changes in technology and changes in the available systems that were available in the industry.
I think the recommendations that came out of our report, many of those have already been borne out by vendors introducing new technology to the market.
And, finally, a survey of unpiggable pipelines. This was an attempt to examine existing pipeline systems and the existing vendor capabilities of the time, and this would have been in 1995, to determine, first of all, why are pipelines unpiggable? What characteristics of the lines make them unpiggable? How difficult would it be to make them piggable, and then what do vendors have to offer that relates to this?
In other words, if a bend radius is a limitation, what can the vendors offer in terms of tighter bend radius capability?
That report, even though it's several years old, I think it's still a usable snapshot of the state of the pipeline system, and it's been corroborated by subsequent surveys by consultants.
You heard some numbers from Andy Drake. Those numbers are essentially the same as what we produced in our report.
Now, continuing with the idea of unpiggable pipelines, and this goes to answer Mr. Dyck's question of several people earlier, what makes a pipelineunpiggable? I have four bullet items here. There are at least that many more that we could add.
First and historically foremost was the lack of launch and retrieve facilities. Launch traps and retrieve traps.
Pipelines, most of them that are in service, were designed and built before there were in-line inspection tools. There may have been pigging. There may have been cleaning pigs. There may have been batching pigs. Those did not require as long a launch trap to introduce into the line or to take out, and, so, many of them had to be upgraded to make them handle in-line inspection vehicles.
This is not really a show-stopper, I'll say, in being able to pig a pipeline because there are temporary traps that can be attached to a line to make the run and then removed and moved to another location later.
Now, the second item, bend radius less than 1.5-D, which would be a radius of one and a half pipe diameters. In the early days of in-line inspection, pigs were typically able to make a 3-D bend but were not able to pass through anything tighter than that.
Now, I think in most every pipe size, there are in-line inspection tools available that can gothrough 1.5-D bends. Unfortunately, there are some bends that are tighter than that. Some combinations of bends that still are not piggable.
There are a few mitre bends which are almost instantaneous angle changes in the pipeline. Those are -- if they exceed a certain number of degrees, are not piggable.
Diameter change greater than one pipe size. One pipe size is generally considered to be two inches. So, a change from, let's say, 24-inch to a 26-inch line would be one pipe size change, and pigs can typically handle that without any problem.
There are so-called "telescope" pipelines, I think, in service, where they were built with more than one pipe size, and it exceeds the range that pigs can accommodate. They may be able to pass through the line. Some more recent designs can go through smaller diameter valves, for example, and smaller diameter lines, but to do an adequate inspection would exceed their capability.
Next, reduce port valves. By this, I mean any valve that has a throughput size smaller than the pipe size, that once was a complete restriction to pigging. Some newer pig designs, for example, 30-inch pigs that can go through 24-inch valves, or 36-inchpigs that can go through 30-inch valves, have been designed.
There is one type of valve, however, that's going to be considered forever unpiggable, and that's the plug valve. Here are two samples of plug valves made by the Nordstrom Company.
If you note, there is the plug which is vertical in these valves, and the hole through it is generally rectangular, and, so, you go through a transition from a circular pipe to a rectangular hole, and no existing pigs can pass through a plug valve. It's hard to imagine any kind of modification to the piston-type pig that will let it go through a plug valve.
So, lines that have plug valves, if you're trying to pig through those valves, would be considered absolutely unpiggable. That's not to say that we couldn't conceive of a vehicle design that could go through a plug valve.
Blue sky sections always turn up ideas for things that can do the seemingly impossible, and there are a number of ideas floating around for vehicle concept that could go through a plug valve. There hasn't been any funding coming forth to pursue feasibility on those yet, though.
I want to talk about three projects that we have on-going at the present time. First, detection characterization and assessment of mechanical damage. Second, couplant of ultrasound through high-pressure gas, and, third, measuring pipeline stress through comparison of MFL signals.
These are projects that are in the early stages, directed towards solving some particular problems in in-line inspection. The first, you've heard mechanical damage mentioned. At SWRI, we've been working with some technology that allows us to define areas of plastic strain in steel and particularly in pipe walls.
We call this non-linear harmonic technology, and I've shown three scans here from three different areas on pipe coupons, and imagine that the blue is, I'll call it, a cool background which doesn't represent any significant anomaly. That left-hand -- left-most slide shows an undisturbed section of a pipe. There are only the random variations that you expect in magnetic properties.
The center one is from a gouge. There's a gouge on the outside of the pipe, and we're scanning inside. That gouge is not accompanied by any dent. It was put in with a back-up plate, so that the pipeoutside surface was gouged, but there was no denting, and yet there is a metallurgically-affected area on the inside where the magnetic properties have changed, and we were able to get an indication.
The right-hand slide is from a dent without a gouge. This is a six-percent dent, and you can see the extensive area of plastically-deformed region.
You've heard quite a bit about ultrasonic inspection, and several times, you've heard the comment that ultrasound requires a liquid couplant, and therefore is not effective in gas pipelines, and this has been known for a long time.
It is true, however, that the ultrasonic method offers the opportunity to have a very accurate measure of, for example, remaining wall thickness, and it's the method of choice in many industries for crack detection and crack sizing.
So, it would be very helpful and very valuable if we could bring ultrasonic inspection technology conveniently to the gas pipeline environment.
We did at SWRI some basic work a few years ago with the National Institute of Standards and Technology Lab in Boulder on couplant ultrasound through high-pressure gas, and it was proven feasibleto do that.
It has its problems in that it's a very critical application, requiring a very specific transducer design and interface electronics to get a good enough signal to noise ratio to be effective.
We're carrying on that work now at our facility, looking at how practical it will be, and what you're seeing in the slide is a pressure chamber where we can, with computer control manipulators, we can move a transducer in a high-pressure environment of either nitrogen or natural gas.
Right now, we're evaluating some prototype transducers. The project is still looking good. We don't have the final answer yet as to whether we'll end up with a practical system, but this would allow us to do a more conventional ultrasonic inspection inside gas pipelines without the liquid couplant.
The third project I want to describe has to do with an effect on MFL signals from pipe wall stress. It's been known for at least 15 years, almost as long as the MFL inspection has been popular, that stress in some circumstances will affect the response of an MFL system.
It turns out that this is very true when you have low excitation magnetic field. Fortunately, forthe accuracy of conventional inspection systems, their field strength is generally very high, and if you see the two traces on the left-hand graph, they overlay each other, and they show the effects of the stress is almost zero when you have a high field.
On the other hand, with low field strength, there's a significant difference. The red curve is a case where there's a strong compressive stress applied to the pipe wall. The blue curve is for a tensile stress, and, so, there's a significant effect at those field strengths.
We have discovered that the ratio of the response at low field to high field is indicative of the axial minus hoop stress in the pipe. All of this is leading to a more accurate assessment routine that might be applicable to pipelines that have bi-axial loading.
For example, in unstable soils, where the pipe may move, you can get significant axial or bending stresses. Thermal stresses show up as axial loads on the pipe, and we see an opportunity to evaluate those by comparison of the MFL signals.
Now, very quickly, I'd like to mention a few opportunities for future research that we think will be coming. Prior to 1970, you've heard of the pre-1970ERW, electric resistance welded pipe. The mill inspection systems of the day and the welding process allowed certain defects to get into the ground in this pipe.
They were not -- some of these defects are very difficult to detect. Most of them have performed quite well. Occasionally, due to cyclic stresses or other loads, some of those have failed. This is a very difficult inspection challenge. R&D could be applied to look at new ultrasonic techniques, for example, to inspect those.
Some work is being done with transverse or circumferential field that has been promising, and stress corrosion cracking has been mentioned. It's a problem that has not yet been solved, and I think additional work is on-going with electromagnetic acoustics and a transverse field. Ultrasonics, we have concluded, is the appropriate method.
Just to close, I'll make a pitch for one of my favorite topics, which is vehicle design. The unpiggable pipelines that are in service today, we think, potentially could be made piggable with the proper vehicle, and it's not going to be easy. It's not going to be quick, and it's not going to be cheap, but it's an area that fully deserves some R&Dattention.
So, with that, I'll close, and thank you.
CHAIRMAN HALL: Thank you very much, Al, for a very informative presentation. All the presentations were excellent.
We'll now turn to the Technical Staff for your questions. Mr. Zimmerman?
MR. ZIMMERMAN: Thank you, Mr. Chairman.
I'd like to throw this question out to both organizations. Perhaps maybe Battelle could take a shot at it first.
What determinations have you made regarding what level of mechanical damage is detrimental to pipeline integrity, and specifically maybe you can tie it into how it relates to the criteria that's currently used in the ASME codes?
DR. LEIS: I've been voted to answer the question from Battelle's perspective.
You pose a difficult question from the point of view of, first of all, putting into perspective the fact that resistance to mechanical damage often involves the growth of defects, cracks, and crack resistance is determined by a parameter called "toughness", and the toughness varies, depending on who made the steel, when the steel was made, and so on.
So, if you were to take and impose on, let's say, for example, a modern X-70 high toughness line pipe, given level of mechanical damage, gouge and dent, you would find it could survive very readily first test, well past anything that would be imposed in a hydrotest.
On the other hand, if you were to take a look at, unfortunately, some of the lower toughness that's present in the early vintage line pipe, it might be found to be more problematic.
So, what level? We found quite small levels of dents have been problematic in low toughness steels. The Code says six percent deep, but it doesn't speak about the length over which that six percent exists.
So, from a mechanic's perspective, you say is that six percent relevant, and under what circumstances is it relevant?
I guess my response tends to hedge against giving a definitive answer because I don't believe there is one. I believe it's operation-specific, steel-specific and many other issues-specific.
I know you probably don't like that hedge but that's reality.
MR. ZIMMERMAN: Yeah. I would like to understand the Code was conservative enough at thispoint, but you're not ready to commit to that now.
DR. LEIS: I think the issue of six percent over a relatively small length gives rise to a significant local curvature, and when that local curvature rerounds and tension develops on the outside of the pipe where that rerounding occurs, you get a very, very focused strength, in spite of the fact that it's a six-percent deep dent.
That same dent over much larger distance gives rise to a much, much smaller strength and differing ability to sustain the damage. So, is the Code safe, and under what circumstances is it safe? Unfortunately, I have to hedge on that one, too.
MR. ZIMMERMAN: Thank you.
DR. BUBENIK: I have a comment or two, if I may?
MR. ZIMMERMAN: Yeah. Go ahead.
DR. BUBENIK: And I think that Brian alluded to a situation where there's perhaps a difference between dents that reround and dents that do not or dents that contain a gouge and dents that do not.
Oftentimes when we speak about rock dents, they're generally larger, and they don't have the rerounding aspect of them, and six percent has been a Code-accepted criteria for those sorts of dents formany years.
When a piece of pipe is hit by a backhoe, as we've talked about, there's denting, and there's removal of metal, and one of the points that was alluded to earlier is a damage to the micro-structure, damage to the steel itself, that's not a metal removal. It's merely a smearing out of the metal that reduces its toughness even further.
In those situations, it's possible to initiate cracking on much, much smaller dents. So, perhaps it's a challenge to industry to look at maybe a two or more tiered approach to what is an acceptance criteria and differentiate between those defects that reround and those that do not, and between those defects that have a gouge or that were created by some external construction equipment and those that were not.
MR. ZIMMERMAN: Thank you.
MR. CROUCH: Oh, I might add that there is an on-going program, it's funded by GTI and the DOT, where Battelle and Southwest are both involved. We are looking at a number of mechanical damage defects.
Battelle has a facility for making those with different degrees of gouging and denting. We will be scanning those with our non-linear harmonic techniquethat I showed you and under pressure and then testing them to failure.
So, we're starting to develop a better understanding of the relationship between response to those defects, and then, along with some finite element modeling of the same defects, we'll begin to understand perhaps what parameters of the defect are really more important and how soon it fails.
MR. ZIMMERMAN: Okay. Thank you all. Mr. Dyck?
MR. DYCK: Address the entire panel. I was wondering if you have a view on what type of time frame we're looking at for any kind of major improvements in capability to detect mechanical damage in sharp cracks.
DR. BUBENIK: The question is whether or not we have a time frame for our major improvements on mechanical damage and cracks, and I guess I'm going to give you a researcher's answer, and the researcher's answer is it depends upon how much money is spent to develop the technologies.
There are programs that are underway today that are looking at, for example, combinations of axial and circumferential MFL, and I'm convinced that those will produce much better sizing accuracy for metal loss defects across the board within the next one to twoyears.
In terms of mechanical damage, there's a number of things that need to be done. There has been some basic research and development that was done at Battelle and Southwest that developed some techniques that appear to be quite sensitive to the types of damage that are important. Rerounding, for example.
The application and success of those techniques will require several things. It requires building a prototype equivalent by the inspection vendors, and it requires testing not only in controlled environments but testing out in the field, and the reason for that is that we know the techniques work for the things that we've created in the lab.
We don't know if there are other situations that produce the same type of signals. We want to make sure that we don't get into trouble with misinterpreting the wrong things as if they're defects.
My guess is that a mechanical damage tool initially will be available again in the one-to-two-year time frame, but for commercial acceptance and success, I think you're still talking, you know, a total of four or five years from now.
Crack detection. There are crack detection tools that are out there now, and they detect cracks. One of the questions that begs to be answered is do they miss cracks?
It's often one thing to talk about an inspection technology as the smallest thing you can find, and I always ask what's the biggest thing that you can miss?
Are false positives the problem or are false negatives the problem? I'm concerned more with an inspection technology that misses a defect.
What we're learning and what we're seeing as inspection companies have built equipment and have brought them out in the field is that there's a process that takes a long time to gain experience and data, to gain this sort of understanding that's going to help you learn when these tools effectively work, and when they have a problem.
That's been underway for a number of years. The wheeled ultrasonic tool has been tested probably for the last 10 years or so. The EMAT tool that people have talked about has been tested for the past several years. The liquid couplant or the shear wave ultrasonic that was mentioned has been tested for the last several years.
That's going to be a slow evolution. It's not something that you can expect a year from now ortwo years from now. The technologies that are out there five years from now are going to be better than they are today, but you're going to be sitting over there saying they still haven't done everything we want, and that's probably the same that's going to be true 10 years from now.
Did you want to add anything on that, Al?
MR. CROUCH: I trust your numbers, Tom.
DR. LEIS: I'd like to have a go at it from the point of view of an alternative technology.
Mechanical damage that does metal removal to the pipe generally removes coating, and where coating is removed, there is a major difference in the CP circumstances locally.
So, the direct assessment methodology that was talked about as an alternative to in-line inspection is very, very well-focused at today being capable of going out and identifying areas where that coating has been damaged, and it may be the easiest short-term fix or find for it.
MR. ZIMMERMAN: Thank you, Mr. Chairman.
CHAIRMAN HALL: Member Carmody?
MS. CARMODY: Thank you to the panel. I have no questions. I feel very well informed, and I've learned a lot. Mr. Dyck addressed my question. Thankyou.
CHAIRMAN HALL: Member Black?
MR. BLACK: No questions, Mr. Chairman.
CHAIRMAN HALL: Member Hammerschmidt?
MR. HAMMERSCHMIDT: No questions.
CHAIRMAN HALL: I just have one question. I guess that is, you're talking about the future, but we've got a lot of old pipe in the ground.
Have you done any research on the age, aging, on the pipe, and how long it can be in the ground? Is it indefinitely or do we have a problem out there in terms of this pipe that we can't internally inspect?
DR. BUBENIK: There have been -- and I'll let Brian add on this one as well.
There have been studies that looked at the --whether or not the properties of pipe seals change with time, and those efforts generally show that the basic properties that you want steel to have, its strength and its toughness, remain relatively unchanged with time.
There are some circumstances that can reduce them, and it's important to understand what those might be, but for the most cases, that doesn't happen.
Coatings. There's a question of whether or not a coating will degrade with time, and, if so,whether or not the pipeline can continue to be protected by cathodic protection systems.
In general, research work has shown that a cathodic protection system that's well-designed can keep up with potential for corrosion on pipelines. So, then you're left with situations like mechanical damage. Are you in an area where construction activity might take place for some of the unusual forms of cracking that might occur?
Fatigue cracking. We heard discussions earlier of rail fatigue. That's what initiated those cracks, and pressure cycling fatigue is what grew them. Are those situations that might occur?
The good news and the bad news. The bad news is it can make it worse. The good news is after awhile, they're gone.
Brian, would you like to add?
DR. LEIS: Yeah. I think I would like to comment a little bit here.
I think it's important to put into perspective the fact that failures in pipelines as failures in any structure tend to occur as a result of a localized process. Focusing metal loss occurs, cracks develop.
It happens in airplanes. Airplanes use verydirect assessment technologies in areas where they know the damage is occurring. They know the hot spots. They go in and inspect for it, and in many ways, in-line inspection is one approach to find where that damage is focusing in pipelines.
In regard to mechanical damage, I made the point about direct assessment as an alternative. Hydrotesting is an alternative. I think we need to pick up and effectively use all of the tools, and in situations where lines can't be inspected internally, there are other ways to, first of all, identify where those hot spots are and go out and look for damage in those areas, recognizing how the line's operated, and what its history's been.
So, you can use operating experience on that line, operating experience and incident histories on other lines, and bring together, if you will, the information that's available to you and effectively utilize it to focus on where failures occur.
If you think about a pipeline, a failure occurs where a very, very focused process was occurring. The design factor was the same everywhere in the line to start with. The design factor is the same a foot away from where it failed. It failed where it did because of some localized process, and if youcan go out and find those areas, use the best means you have available to you to identify likely spots that you should be looking at and go out and check them out, there is no effective reason why a pipeline needs to be retired any differently than, for example, an air frame gets retired. They go and make replacements. They do inspections. They make changes, and the same can be true of pipelines. But you have to do the condition assessment, and you have to make the right choices as a result of the condition assessment.
CHAIRMAN HALL: Thank you very much.
Let me offer this -- first of all, let me observe that it's very nice to see that such thoughtful and capable people are involved in research in this area, and I'd like to offer to this panel the same opportunity as the others if you have any closing comments.
Doctor?
DR. LEIS: Can't resist. A good deal of money gets spent on research, and I guess the plea I would make would be to make sure that what we learn gets implemented, finds its way into practice.
Lots of times, we write reports that are far too complicated to be understood, and the industry, people throw their hands up in the air and say what theheck is he saying?
I'm guilty of it, as I'm sure most others are, because we're dealing with a relatively complex problem. Maybe what we have to do as researchers is try and focus on how to communicate better, and maybe there has to be an opportunity taken periodically to just sit down and sort through it all with people that have that kind of concern.
Meetings like this provide a forum that starts that, and I guess I'd like to be -- I'd like to express my thanks for being invited to participate and encourage the use of research.
CHAIRMAN HALL: Thank you very much. Tom?
DR. BUBENIK: Well, first, again I'd like to thank you as well for the opportunity to speak with you all here today.
This is a critical point, I think, in terms of the pipeline industry. It's critical in a couple of ways. It's critical because the regulations are changing. The environment under which the pipelines operate is changing.
It's critical because there's been a number of mergers and changes in the companies over the past several years, and in situations like this, sometimes, and this is a self-serving comment, sometimes researchand development or longer-term efforts are put on the back burner.
You're putting pressure on industry, and industry's putting pressure on itself not to do that. There are opportunities out there. I think it's important for all of us to take a good hard look at what we're seeing and to make certain that we don't let things fall by the roadside, and I'd like to encourage industry and the rest of us to keep that in mind as we move forward.
Thank you.
CHAIRMAN HALL: Thank you. Al?
MR. CROUCH: I have no other closing comments.
CHAIRMAN HALL: Very well. Well, I would, first, like to thank the audience. i think we kept a good number of people here present. I appreciate the courtesies that you've extended to all of us, and the fact that none of you have gone into court to enjoin this hearing. Well, it is late. Can't even get a -- I guess that's -- Carol says that's a political joke. You all wouldn't get it. So.
But we will start -- I think we had an excellent discussion today on Inspection and Integrity Verification.
Tomorrow, we will focus on leak detection and response, and we will begin again at 9:30 a.m. in this room, and until that time, we stand adjourned.
(Whereupon, at 5:41 p.m., the hearing was adjourned, to reconvene tomorrow morning, Thursday, November 16th, 2000, at 9:30 a.m.)
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