Technology challenges in the area of pipeline protection are centered on the areas of corrosion detection and inhibition, remote monitoring and risk assessment, and inspecting unpiggable lines.
There are many issues to be addressed in pipeline inspection and integrity management, notes Andy Barden, division technical manager, BJ Process & Pipeline Services Co.”Although the detection of general corrosion in standard wall thickness pipe is generally well understood, with several different technologies available to detect this, there are many other issues that cause pipeline failure where solutions are not so readily available or the technology is not yet reliable enough” he says. “Stress corrosion cracking, corrosion around the weld area, and the interaction of corrosion and other defects with mechanical damage are all challenging areas requiring new development and better understanding.”
Barden also points out that in the offshore pipeline sector, the inspection of very heavy wall pipes using tools that have to be launched and received from subsea systems in ultradeep water “will provide a whole host of additional challenges over and above those we see in the onshore industry.”
In addition, “The inability to pig many pipelines is still a major issue, and new technologies that can address this problem are still required, whether this be multidiameter tools, tethered tools, crawling tools, or other, completely new technology.”
Cathodic protection
Industry is delivering innovations in the area of cathodic protection (CP), according to Steve Schroder, General Manager of Baker Hughes’s Pipeline Management Group (PMG).“Historically, pipeline operators have relied on aboveground surveys to validate the effectiveness of their cathodic protection systems,” he notes. “This year, Baker Hughes PMG is introducing a new technology that allows operators to measure the effectiveness of their cathodic protection systems from inside the pipeline with an inline inspection tool.
“This innovative technology–CPCM™ In-line inspection services–allows operators to gather actual CP current readings from the internal pipe surface and actually ‘see’ how it is being distributed.
“Making sure that your system design and operation is optimized, as well as identifying exactly where future monitoring should be performed, maximizes efficiency and lowers the overall cost of ownership. Since the CPCM™ tool travels through the pipeline, this innovative approach also removes the barrier of right-of-way access. This is a truly revolutionary technology that is a game-changer in the field of cathodic protection monitoring.”
“The inability to pig many pipelines is still a major issue, and new technologies that can address this problem are still required, whether this be multidiameter tools, tethered tools, crawling tools, or other, completely new technology.”
– Andy Barden, BJ Process & Pipeline Services
CP and coatings
John Muncaster, president, Polyguard Products Inc., takes issue with a common industry practice he considers an example of “basic corrosion principles being overlooked”: the widespread use of “shielding corrosion coatings” (solid polyethylene or polypropylene film backings) on pipelines with cathodic protection systems.
“It seems, frankly, stupid to invest large amounts of money in cathodic protection systems, then to use as the primary corrosion coating a solid film backed material that blocks–because of its high electrical resistance properties–the protective current supplied by the CP system,” he claims.
“It sounds stupid to do that, but it is being done worldwide, particularly outside of North America. Maybe it continues because nobody outside of authors in technical journals (until Polyguard) has tried to point out this contradiction.”
The basic nonshielding corrosion coating is fusion bonded epoxy (FBE), which is used worldwide for main line coating, Muncaster notes. “Polyguard has a product (RD-6) that is a nonshielding corrosion coating and that is a CP-compatible alternative to FBE for use on girth welds, rehabilitation, and repair areas of new or existing pipelines.”
Muncaster would like to see pipeline coatings that can truly resist high line operating temperatures: “Over the years, line operating temperatures have been rising as wells become deeper.”
“It seems, frankly, stupid to invest large amounts of money in cathodic protection systems, then to use as the primary corrosion coating a solid film backed material that blocks–because of its high electrical resistance properties–the protective current supplied by the CP system.”
– John Muncaster, Polyguard Products
His colleague at Polyguard, Richard Norsworthy, director, Lone Star Corrosion Services division of Polyguard Products Inc., sees a bright future for coatings that provide the end user with nonshielding properties if there is loss of adhesion, or disbondment.
“Disbonded coatings that shield cathodic protection from being effective is now the major cause of external corrosion on pipelines,” he contends.
Muncaster notes that “there are some quite good coatings, such as two-part epoxies, which are widely used on pipelines but have not yet proven that they do not shield cathodic protection.
“Once again, since almost all lines now receive cathodic protection, it follows that all corrosion coatings should be compatible with CP. This means ‘nonshielding.’ There is mixed evidence as to whether two-part epoxies are compatible with CP.
“Certainly, an agreed-upon industry standard for determining CP compatibility of corrosion coatings is needed.”
Norsworthy thinks that the most significant issue with cathodic protection will be the proposed revision of the NACE SP0169 document that covers external corrosion control of underground or submerged pipelines.
“If changed as proposed by some, the cost and implementation will be a significant cost for the industry, with very little gain in safety or corrosion control,” he contends. “Most are only concerned about the CP criteria and seem to forget the other sections of the document that cover coatings and electrical isolation.”
Muncaster adds, “It might be added that, because of Richard’s concern that the pipeline operating companies are not, for several possible reasons, making their voice heard on the SP0169 update, Polyguard is sponsoring a blog where all interested parties can come together on equal terms and debate the issues.”
The blog, at www.SP0169.com, was activated Mar. 17, in time for the National Association of Corrosion Engineers’ Corrosion 2008 conference and exhibition in New Orleans, Mar. 16–20.
Another major corrosion challenge, Muncaster notes, involves insulated pipelines: corrosion under insulation.
“Polyguard is introducing a cutting-edge answer to this in our RG2400 series of patented corrosion gel pipeline treatments,” he says. “‘Big Oil’ has already used these products on insulated arctic pipelines, and for other oil and gas corrosion applications.”
Inline inspection
Assessing the physical properties of the pipeline by way of inline inspection surveys will continue to evolve, notes Schroder.
“At this time, it is usually the most efficient means to collect metal-loss data,” he says.“As with the CPCM™ technology…it is quite possible that measurements made from within the pipeline will be extended to include other data sets, which should assist the operator’s ability to proactively detect possible threats to pipeline integrity other than metal loss.
Schroder also believes that while collecting metal loss data will remain a key requirement to assess pipeline integrity, the industry will begin to move toward monitoring changes to pipeline properties over time.
“Products such as corrosion growth studies will improve the effectiveness of mitigation activities for both internal and external threats,” he says.
Barden thinks that a reliable tool for stress corrosion cracking monitoring will have a big impact on the market, especially in North America.
“Although several tools are available to detect this, none has achieved the level of accuracy and reliability required by the industry,” he points out. “In addition, analytical models that can look at the interaction of many different features and issues–be they corrosion, cracking, geometric, or the operating parameters of the pipeline–could have a significant impact on reducing pipeline failures.”
Smart pigs will be critical in locating areas of internal and external pipeline corrosion and stress corrosion cracking to help meet more-stringent regulations and for enhanced public safety, contends Norsworthy.
“These tools, along with the proper use of cathodic protection and coatings, will be critical in saving the existing infrastructures and preserving the new systems,” he says. “These tools will also show us the results of the coating decisions we made in the past and are making today and confirm if that decision was correct or not.”
Remote monitoring
Remote monitoring via sensors is another key area of technology innovation in the business of protecting pipelines.
CC Technologies (CCT), a DNV company, has partnered with Southwest Research Institute, Aginova, pipeline operators, and the US government to research sensors that will flow in the gas stream and detect the location of water, allowing for proper treatment at proper areas without the need for costly inspections and unnecessary treatment programs. The sensors are small spheres with wireless microcomputer and memory storage. A prototype of this sensor is in the development phase.
“Remote monitoring combined with risk assessment will also have great impact,” contends Narasi Sridhar, director of DNV Research & Innovation USA. “As wireless technologies advance and sensors are becoming common, it is inevitable that remote monitoring will be used more and more in all phases of pipeline operations and maintenance.
However, remote monitoring by itself is insufficient, Sridhar points out, because the results of monitoring need to be converted to actionable decisions.
“Risk assessment is performed practically routinely these days, and risk assessment/management tools of various flavors are widely available to the industry,” he says. “However, risk assessment alone is insufficient since there are often too many assumptions and uncertainties that go into risk assessment.
“Furthermore, many risk assessment techniques, especially risk-ranking techniques, cannot anticipate new failures since they are based on experiences of previous failures. The combined technologies of remote monitoring and risk assessment can overcome these difficulties.
“Along the same lines, we believe that inline inspection tools will have more sensors and different types of sensors, allowing for the integration of different types of data to help detect the condition of and thereby protect the pipeline.”
Other innovations
Service and supply companies catering to the pipeline protection needs of operators cite other areas of technology innovation on the horizon.
Currently, CCT says it is leading research in several pipeline protection areas that it believes is cutting-edge and will have great future impact. One area of research for the company is the development of more environmentally friendly corrosion inhibitors that will help protect the pipeline while still meeting environmental regulations and garnering public approval.
Keith O’Connor, vice-president, Weatherford’s Pipeline & Specialty Services group, cites as the frontier of pipeline protection those technologies that enable pipeline owners to identify anomalies and the effect they have on pipeline integrity.
“Weatherford is producing a direct stress measure tool, MAPS, that will not only allow the pipeline owners to see anomalies in the pipeline but to see stress caused by these anomalies,” he says. “Today, such stresses cannot be detected by inline inspection tools.”
Weatherford promotes running baselines for all new pipeline construction projects. “These types of inspections can provide the necessary ‘as-is’ condition overview of the pipeline as-laid and thus be a check on the pipeline contractor, but more importantly, they can be the foundation for any Integrity Management Plan.
“They can prove to be invaluable when comparing future inspections runs to each other so that anomalies that were pre-extant can be distinguished from those that are new; thus the anomaly classification and characterization process benefits greatly, creating a much better pipeline integrity picture.”
While collecting metal loss data through inline inspection will remain a key requirement to assess pipeline integrity, the industry will begin to move toward monitoring changes to pipeline properties over time: “Products such as corrosion growth studies will improve the effectiveness of mitigation activities for both internal and external threats.”
– Steve Schroder, Baker Hughes Pipeline Management Group
One of the most significant technical challenges facing providers of pipeline protection services is integrating the massive amounts of data, much of which has uncertainties, created from inspection and assessment programs and interpreting it in a useful fashion, according to Tom Bubenik, CCT director of pipeline integrity.
“We need to be able to manipulate and learn from this data in order to be able to predict future performance and design appropriate integrity management programs,” he contends.
Another area of concern that has long bedeviled pipeline operators, detection and prevention of third-party damage, has become more important as the public increasingly encroaches on pipelines originally located in remote areas, says Sridhar.
“In fact, this has become such a concern that CCT/DNV is currently completing a study for the Pipeline Research Council International on possible prevention strategies for third-party damage,” he points out. “Combining this issue with the fact that not all pipelines can be pigged and excavations are increasingly difficult means that various tools and techniques have to be developed to protect the pipeline and the public.
“Such technologies are being developed by CCT/DNV and others, including mobile sensors for locating water drop-out locations and fiber optic sensors to detect third-party damage or corrosion. But none of these tools are yet widely implemented.
“The various direct assessment methods address unpiggable pipelines, but they alone are insufficient. Sensors and monitoring methods are needed to confirm direct assessment.”
