Internal corrosion is a leading cause of pipeline failure -- and one of the most difficult to detect. Pipeline accidents have caused catastrophic injury and destruction, resulting in imposition of integrity management requirements on pipeline operators by the U.S. Dept of Transportation. To aid operator compliance, an efficient, reliable means of monitoring internal corrosion before it causes problems has been developed.
The Problem
Keeping pipelines safe from internal corrosion can be a challenging and expensive business; industry estimates run to several billion dollars annually in the U.S. alone. Panhandle Energy, a subsidiary of Southern Union, operates approximately 18,000 miles of interstate pipelines.
"In 2006, Panhandle will perform over 300 anomaly investigations," says David McQuilling, a Panhandle senior engineer. "On average, we budget $50,000 per investigation in rural areas, but if you''re in an urban area, $50,000 may not even cover permitting; I''ve heard of operators spending over $250,000 on a single dig."
Internal corrosion can occur when impurities are present within the natural gas, crude, and refined products being transported. Bill Shaw is an rngineering professor at the University of Calgary and director of the Pipeline Engineering Centre, which studies corrosion and monitoring. "Moisture is the big thing; if you had no moisture, for the most part, you''d be fine," he says. "It mainly mixes with salts, like chlorine, and sulphur compounds."
Corrosion can typically reduce a pipeline wall thickness at a rate of 2-3 mils/year, but it can happen much more quickly in the upstream area of operations.
"Gathering systems are really bad; you have large quantities of hydrogen sulphide and brine," says Shaw. Water can chemically react to form very corrosive liquids that collect in low-lying spots. Corrosion rates in these areas may reach several hundred mils per year.
What the Industry Is Doing
To mitigate the potential for incidents related to internal corrosion, the pipeline industry works assiduously to reduce risk. The U.S. Dept of Transport''s Pipeline & Hazardous Materials Safety Administration (PHMSA) notes that 258 natural gas and liquid pipeline accidents (14% of which were caused by internal corrosion) occurred in 2004.
"It is important to place natural gas pipeline safety data in perspective," says Don Santa, president of the Interstate Natural Gas Association of America. "INGAA''s members operate a network of approximately 200,000 miles of transmission pipeline, and this total does not include all of the intrastate transmission pipelines and LDC-owned pipelines that also are subject to the Dept of Transportation''s integrity management rules. Pipelines are one of the safest modes of transportation."
But when they do fail, they tend to get noticed. Early in the morning of Saturday, August 19, 2000, a natural gas line exploded in southeastern New Mexico near the Pecos River. Eleven nearby campers were killed by the blast and fire. The ensuing fireball was large enough to be seen in Carlsbad, NM, 20 miles to the north. Federal investigators determined that the cause was severe internal corrosion; over 70% of the wall had been eaten away near the rupture.
Pipeline Safety Improvement Act
Partly in response to the tragedy, the Bush Administration enacted the Pipeline Safety Improvement Act (PSIA) in 2002.
In order to comply, pipeline operators rely on a range of survey methods supplied by third parties. Prominent companies supplying internal corrosion monitoring equipment include Rohrback Cosasco of the US, Corrocean in Norway, Cormon in the UK, and Caproco in Canada. The international market for corrosion monitoring equipment is in the neighbourhood of $70 million annually, and is growing rapidly due to the fast pace of oil and gas developments, expansion of pipeline networks around the world, and the increasing stringency of regulation.
Monitoring Methods: Intrusive
Generally, internal corrosion monitoring & detection is broken down into three techniques, intrusive, In-Line Inspection (ILI) and non-intrusive. "Intrusive methods include electrical resistance probes and coupons," says Shaw. The coupon is the original form of intrusive corrosion monitoring. It consists of a strip of metal about 3 in. long and 1/8 in. thick, made of material similar to the pipeline. It is weighed, then inserted into an access point and left for at least six months. The operator then removes the coupon and weighs it again to see what percentage is missing.
The coupon is inexpensive and reliable, but several factors can outweigh the advantages. First and foremost is access above the area of concern.
"Corrosion often occurs at low spots, under roads or rivers," says McQuilling. "It''s often impossible to put a coupon in the location where the internal corrosion is occurring. If access to the area is possible, burial depths must be considered, as coupons are commonly installed and retrieved at line pressure. It is impractical to install coupons at pipe depths greater than 10-15 ft below grade. I''ve had situations where pipe was removed and replaced due to internal corrosion but a coupon was not considered due to safety concerns about insertion and extraction of a 27 ft long coupon/coupon staff assembly at 1,950 psig."
Second is the number of locations where coupons can potentially be installed. "With external pipeline corrosion protection, you''ve got a monitoring point every mile; that''s not a lot -- quite a few assumptions have to be made," says McQuilling. "With internal corrosion, you''ve got one every hundred miles if you''re lucky; it''s like getting eight pieces of a 1,000-piece jigsaw puzzle and asking what it looks like."
Third, because coupons are most commonly left in the pipeline over a 6 month period, the operator doesn''t know if the corrosion occurred slowly over the time period, or quickly over a few days due to an unusual event.
Monitoring Methods: In-Line Inspection
In-Line Inspection (ILI) tools, or smart pigs, are intelligent sensing devices that are introduced into the line at a specialized entry point and most commonly conveyed by product flow along the length of the pipe.
"Pigs have great sensitivity, but there''s a lot of piping that cannot be pigged easily," says McQuilling. "It was common to telescope vintage pipelines from 24-18 in. Also, you can have a vintage 36 in. pipeline with 24 in. valves; you saved a considerable amount of money during construction and the flow restrictions due to undersized valves are negligible, but a pig won''t go through -- it''s expensive to make some lines piggable."
"The preferred methodology is inline inspection with a pig, but certain sections can''t use a pig due to age and configuration," agrees Santa. "You then have to dig up and visually inspect them, or hydrostatically test them, which from a practical standpoint is not all that convenient and potentially destructive."
External sensors help avoid such expensive intervention; various devices measure the physical properties of the pipeline through secondary techniques. "You can use acoustics to measure wall thickness or listen to the noise of corrosion," says Shaw. "Vacuum foil techniques measure hydrogen permeation."
Monitoring Methods: Non-Intrusive
The most common non-intrusive device is the ultrasonic monitor. To conduct a survey, the pipeline is dug up, then a portable device is held against the metal. Inside the device, voltage is applied across a piezoelectric crystal to generate an ultrasonic sound wave that propagates through the metal. The time it takes to travel through the metal and back to the transducer is directly proportional to its thickness.
The devices are quick, easy to use and inexpensive, and operators do not have to shut off flow or risk breeching the pipeline in order to take a reading. On the other hand, they still have to expend thousands of dollars digging up the pipeline each time they run a test. Also, traditional ultrasonic monitors have a sensitivity range in the order of 5-10 mils accuracy, so if the corrosion is only 3 mils/y, it takes three years to start to see it in a statistically significant manner.
Rohrback Cosasco Systems, based in California, is a pioneer in the measurement of corrosion by way of electrical resistance and ultrasound. The company has over 80 employees and 50 representative companies around the world (75% of their business is in the international O & G sector), with annual sales of over $20 million. "We saw the potential for a high-speed, high sensitivity device that could be permanently installed, and began to focus on development in 2003," says CEO Brent Ford.
Another Alternative
The company devised the UltraCorr® wall thickness monitor, a combination of permanently mounted transducers and a portable datalogger.
With a permanently installed system, internal corrosion surveys can be incorporated into normal maintenance practice; most pipeline companies have field technicians patrolling the right-of-way on a frequent basis to check cathodic protection systems.
"The technician takes an UltraCorr Corrosion Data Logger, a handheld device, and loads the transducer information from the test post," says Ford. "It''s easy to use, and only takes seconds per reading." Readings stored on the portable datalogging unit can be uploaded to a PC, where proprietary software is used to organize, store, and graphically display data. Simple plots of thickness versus time are augmented with a cursor-driven corrosion rate calculator permitting detailed event analysis. "Operators know with confidence the condition of their pipe."
Costs for UltraCorr are reasonable. "Depending on the number of transducers required, our device might be $8-$12,000 per dig to install, but you only have to do it once," says Ford. "The handheld device is around $6,500; you only need one per field area."
Right from the beginning, Panhandle Energy has been interested in the system. "It''s simple, clean and cheap; you don''t have to blow down the pipe, which really gets expensive, or do a hot tap," says McQuilling. "You just buff off a spot on the pipe and attach it with epoxy, then backfill and set up a post for the transducer wires, and you''re done."
Since the majority of Panhandle''s system handles clean, dry gas, there is little corrosion along mainlines.
"Panhandle has numerous locations where we believe the UltraCorr will be beneficial," says McQuilling. "Historically, most of our internal corrosion issues occur at our underground gas storage fields. Panhandle operates six gas storage fields which are depleted gas reservoirs used to store gas. We inject clean, dry, pipeline quality gas, but it often comes back up wet and potentially corrosive. A typical storage field has 30-40 miles of pipe and 70-80 wells, creating numerous opportunities for internal corrosion monitoring."
Although McQuilling is enthusiastic about the system, he is well aware that others may not be so. "Lots of readers will be skeptical; some operators put earlier versions of UltraCorr into operation and the epoxy failed within months," he notes.
"We had an early prototype with reliability issues," acknowledges Ford. "We spent over a year and $1 million improving reliability and sensitivity before starting field tests. We are confident that the new system will meet expectations."
"They''ve put the latest epoxy through torture to improve it," notes McQuilling. "We''ve had the latest UltraCorr probes in service since October 2005, and so far, it''s worked and worked well. We''ve stuck with them because there''s great potential for a low-cost monitoring system that may eliminate the need for future excavations. With this system, when the Office of Pipeline Safety comes in after seven years and says ''You''ve got to re-inspect that portion of pipeline,'' we hope to say ''We''ve done real-time monitoring; here''s the data.''"
For industry observers, a permanent, non-invasive system could improve safety. "The best safety program is damage prevention, and if you can address corrosion before it is an incident, that is the best way to deal with the issue," says INGAA''s Don Santa.
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