Risk-Based Pipeline Inspections Begin
by Bill Kunkel
|Thursday, August 21, 2003
Abstract: Gas and liquid pipeline operators will soon begin to use new, federally mandated inspection protocols called risk-based assessments. They are designed to reduce chances of blowouts and spills where damage could be greatest.
Analysis: New rules for inspecting interstate gas and liquid pipelines companies are going into effect now. The rules, set out by the Office of Pipeline Safety (OPS) of RSPA, the Research and Special Projects arm of the Federal Department of Transportation (DOT), provide for more intense inspection of pipeline regions where a mishap could cause the most damage.
Pipeline companies must now develop risk-based pipeline integrity programs for areas where significant damage can occur. This involves first identifying the locations along the pipelines which represent High Consequence Areas. HCAs are places where a pipeline lies within or close to cities and towns with high populations, and to churches, schools, and stadiums with occasional high populations. The rule also requires programs for pipelines within 650 feet of unusually sensitive areas (USAs) such as navigable waterways and environmentally vulnerable areas--any place a leak carries the possibility of ecological damage.
New regulations for liquid pipelines went into full effect the end of 2002. DOT is formulating very similar final rules for gas transmission lines and has said it hopes to publish those rules by the end of this year.
Why New Rules?
Until recently, pipeline regulations have descended from the Natural Gas Pipeline Safety Act of 1968. DOT established Federal Safety standards for pipelines and issued a rule--Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards.
The 1968 rule worked well. Over the years it was modified to deal with operations and maintenance, transportation of hazardous liquids, system maintenance and inspections, and other needed improvements.
Pipelines proved themselves inherently safer than other forms of transportation.
But then a series of high-profile accidents occurred. In 1996, Colonial Pipeline’s major line from Port Arthur, Texas, to Linden, New Jersey, spilled more than 950,000 gallons of diesel fuel into the Reedy River in South Carolina. The spill dispersed more than 34 miles downstream and killed an estimated 35,000 fish and other wildlife. The government alleged that spill and seven others totaled 1.45 million gallons. In a consent decree, Colonial agreed to upgrade environmental protection on its pipeline at a cost estimated at $30 million and pay a $34 million fine, the largest civil penalty a company has paid in EPA history.
In June 1999, a rupture on the Olympic pipeline in Bellingham, Washington, spilled more than 250,000 gallons of gasoline along a mile-and-a-half stretch of Hanna and Whatcom Creeks. The gasoline ignited, burned over the length of the spill, and killed three people, injured eight, and burned several buildings.
In Carlsbad, New Mexico, in July of 2000, an El Paso natural gas pipeline exploded and ignited, killing 12 campers in the area.
These incidents inspired DOT to write new safety regulations to provide extra protection in highly populated areas, environmentally sensitive areas, and waterways. The new rules require pipeline companies to develop risk-based pipeline integrity programs for such areas.
Developing the integrity program involves first defining regions along their lines that are HCAs. As stated, these are cities and towns with high populations, and churches, schools, and stadiums with occasional high population. The act also requires programs for USAs such as navigable waterways and environmentally sensitive areas. The risk basis focuses attention on any region along the pipeline that carries the possibility of widespread damage.
The regulations will include inspection intervals defined by the Pipeline Safety Improvement Act of 2002. This act, signed late last year, sets up initial inspection intervals for hazardous gas and liquid pipelines at five years or 10 years to assess pipeline integrity and define a baseline for reinspections, which are required every seven years.
The first order of business for pipeline operators will be developing an accurate map showing the high-risk segments of their pipelines. DOT has prepared maps of the pipelines. Operators can use these and overlay surveys of cities, towns, rivers, and so forth, to determine HCAs. This is no small job. Many areas of the U.S. have undergone substantial growth. Many communities may be close enough to create an HCA where there was not one only a few months ago. And growth may force new surveys periodically.
Soon OPS will issue the rules for periodic testing of gas pipelines in HCAs. The rules, which are already drafted, will define three acceptable methods of inspection: inline inspection, hydrostatic testing, and what’s called external corrosion direct assessment or ECDA.
Inline inspection. This is by far the preferred method. It involves an instrumented pig launched through the line. The pig carries within it instruments that measure corrosion, wear, and damage such as cracks and pits. These flaws are recorded and can be coordinated with a position along the line. Pigging is the least expensive and most accurate way of gauging the condition of the pipe wall, and it can be done with the pipeline in service. Sadly, many lines, especially older gas lines, cannot accommodate pigging. Sometimes the valves along the line are smaller than the pipe so the pig can’t pass through them. In other lines, pipe bends are so sharp that the pig can’t pass through.
Hydrostatic Testing. In this method, a segment of the pipeline is isolated, filled with water, and pressurized for a period of time. In addition to requiring that the line be removed from service, hydrostatic testing requires lengthy periods to prepare the line and to dry it after the test. It also requires disposal of very large volumes of water after the test and careful disposal of grease and oil that may be picked up by the water.
Direct Assessment. The last candidate is external corrosion direct assessment (ECDA). It is the method of last resort, existing only because there has to be some way to test a pipeline where the pig won’t work or the line cannot be shut down for hydrostatic testing. Several methods and procedures are available for use in this category. Testing would likely be engineered specifically for the particular line and conditions.
The Size of the Job
Impact of the rules on pipeline operators is likely to be quite heavy. There are close to 2 million miles of pipeline in the United States. Various sources estimate the totals, but as of the end of 2001, DOT lists 155,000 miles of hazardous liquids, mostly crude oils but including refined products; 307,524 miles of gas transmission lines; and 1.14 million miles of gas distribution lines. Other sources show larger total miles, but don’t change the general impression that making the required surveys is a very big job.
What costs pipeliners may encounter are now largely a matter of guesswork. Take gas transmission lines, for example. DOT has estimated that about 20,440 miles of interstate gas transmission pipelines will end up in the HCA category. This amounts to about seven percent of the total 307,524 miles.
Retesting every seven years as required by the Pipeline Safety Improvement Act of 2002 would place 2,920 miles of pipeline under testing annually. Again, estimating, DOT feels that testing methods will turn out to be roughly equal: About 35 percent of these lines are piggable, 30 percent could be hydrostatically tested, and 35% would require direct assessment.
It is possible also that mapping will turn up short and widely separated HCA line segments that require testing. One industry analyst, anticipating this, feels that management may face a considerable planning challenge in testing HCA segments at reasonable costs. On the other hand, inspection, testing, and maintenance of the entire pipeline can’t be neglected, so HCA inspections might become variations on regular procedures. Providers of maintenance services--those companies that coat pipelines, install cathodic protection, and monitor and test line conditions--will also be challenged. But those issues lie ahead. As operators gain experience, it will be interesting to see what develops.