March 2009 Vol. 236 No. 3


Protecting Pipelines At Crossings: Are Casings Obsolete?

Tony Keane, executive director of NACE International, recently assembled a panel of NACE member pipeline corrosion control experts to answer a series of questions on the challenges involved with assessing and protecting pipelines at cased road and railway crossings.

“Corrosion professionals are charged with protecting pipelines and other structures in all types of environments and conditions, and under strict regulatory requirements,” Keane explained. “Cased pipeline crossings pose particular challenges, not only because the carrier pipes within the casings are vulnerable to corrosion, but because assessments are hampered by the difficulty and high cost of accessing these pipelines compared to those that are not cased.”

The five panelists have extensive experience with the regulations, standards, and procedures involved in assessing and monitoring cased crossings. They are Jeff Didas, corrosion project manager at Colonial Pipeline Company; Drew Hevle, principal corrosion engineer for El Paso Pipeline Group; David H. Kroon, executive vice president and chief engineer of Corrpro Companies, Inc.; Norman J. Moriber, chief corrosion engineer for MearsGroup, Inc.; and Jerry Rau, director of pipeline integrity at Panhandle Energy.

Keane: What are the benefits and drawbacks to using cased hazardous liquid and gas pipelines at roadway and railroad crossings when considering corrosion and other types of damage?

I believe that there are no benefits to cased crossings. The legacy reasoning was to provide the capability to remove or replace the carrier pipe without disturbing the roadway. In actual practice, this is not widely attempted. Greater strength or wall thickness, concrete coatings, and other methods provide protection to the pipe from mechanical damage and external loads. The downsides to these installations far outweigh any benefit.

However, having said this, there are no additional or unknown hazards to pipeline integrity because a casing exists. Like any pipeline installation or facility threats, their integrity can be managed.

Kroon: Casings have historically been used at road and railroad crossings to accommodate higher dead loads (overburden for deep pipe) and live loads (traffic). They also help prevent third-party damage, although at the greater depths of the crossings, this may have minimal benefit. From a corrosion point of view, casings should simply be avoided.

Hevle: The benefits to cased pipelines for third-party damage and overburden stresses are almost completely obviated by modern horizontal directional drilling construction techniques, and yet many agencies require casings nonetheless. The disadvantages from a pipeline corrosion point of view are many: additional design and construction costs, additional maintenance and monitoring of electrical isolation, and the problems associated with electrical shorts, including remediation, additional monitoring, and increased loads on the cathodic protection (CP) systems. Cased pipelines that require direct assessment (DA) incur much higher integrity assessment costs.

Moriber: There are several possible conditions related to casings that can affect corrosion activity. If an electrolyte environment becomes present inside the annular space between the pipe and casing, it is possible for corrosion to attack the pipe at coating flaws. While there is some evidence that CP current may distribute through the casing and electrolyte, there are possible corrosion mechanisms, including electrical shielding and crevice corrosion, associated with nonmetallic casing spacers.

There may also be deposits of mud or debris in contact with the pipe metal that do not provide a continuous path to the casing. Also, when a metallic contact exists between the pipe and casing, the casing behaves as a large coating flaw on the pipeline and will receive any available CP current. This local demand for CP current can disrupt effective CP at other locations along the pipeline.

Didas: Today we design road and railroad crossings to be uncased. Proper design and materials allow a safe installation and a long-term maintenance-free crossing. The problem with cased crossings is the casing itself. If third-party damage is a concern, most operators use concrete-coated pipe for damage protection and/or install the pipe deeper — with additional cover.

Keane: What are the key challenges facing industry and regulators in assessing cased pipelines in order to meet regulatory requirements?

Hevle: The key challenge in assessing cased pipelines is that conventional aboveground indirect inspection tools used in DA are not effective if there is no electrical path to the structure, such as with cased pipelines. Even if an electrolyte is introduced into the annulus, the casing acts as a shield, precluding meaningful results from most indirect inspection tools about the level of CP or coating condition. This is a much more significant issue for natural gas pipelines than for liquid pipelines, since DA is an indispensable tool for pipelines that cannot be assessed by pressure test or inline inspection (ILI).

Kroon: There is a need for an economic, effective pipeline integrity assessment technology that can be employed at cased crossings where ILI, pressure testing, or excavating the pipeline are either not possible or impractical. The technology needs to be minimally intrusive to limit disruption of pipeline operations and road and railroad use.

Moriber: Communication is always a critical issue between regulators and operators. With regard to the application of external corrosion direct assessment (ECDA) to cased piping, a particular instance of unclear wording in NACE Standard Practice SP0502, “Pipeline External Corrosion Direct Assessment Methodology,” led to misinterpretations that have been resolved only after considerable effort. We have had good results from ECDA protocols for cased gas transmission piping that are modified from the four-step process described in SP0502. This is a more important issue for non-piggable pipelines compared to a piggable line.

Another major challenge involves collecting enough information on construction practices that were used for older casings. Records are often incomplete, facilities may have been acquired from other operators without records, and there may no longer be personnel with direct knowledge of the pipeline history. In addition, the widening or relocation of roadways may destroy casing vents or other test access.

Rau: Truly the biggest challenge is convincing the public and regulators that threats can be managed safely as we do routinely on any other pipeline segment or facility.

Keane: What technologies, tools, and methods are typically used to assess cased pipelines, and how do they work?

Didas: Assessing a cased pipeline crossing varies with the casing condition and the purpose of the assessment. The assessment can be as simple as conducting a potential survey to verify the status, or running a Panhandle Eastern test to verify if the casing is clear or shorted. Assessment can also be as complicated as excavating the pipeline at the casing and running a guided wave ultrasonic test (GWUT). Using internal inspection ILI data is a very reliable and accurate method.

Hevle: Pressure testing, ILI, or DA are the tools explicitly provided for in the U.S. pipeline safety regulations for assessing the threats of external corrosion, internal corrosion, and stress corrosion cracking (SCC). Pressure testing and ILI are little different in assessing cased pipelines than uncased pipelines. DA of cased pipelines usually requires long-range UT, and the technology has practical limits as well as high cost.

Kroon: ILI tools using magnetic flux leakage or UT to detect metal loss are in widespread use for pipelines that can be pigged on-stream with the product being transported. Pressure testing is also being used, but to a lesser degree. Technologies under development include GWUT and electromagnetic wave inspection, but the pipe must be excavated for attachment of the equipment used to propagate the inspection signal along the pipeline in the casing. ECDA methods are being used by some pipeline operators, although more research and testing need to be performed to improve and standardize the process.

Moriber: Our experience has shown that alternating current voltage gradient (ACVG) and AC attenuation are especially valuable because they do not require electrical contact with the pipe or casing in the test area (just at the signal generator). While just about all of the testing methods are very reliable at identifying metallic contacts, the ACVG method appears to be the most accurate at identifying electrolytic paths.

Keane: What standards are available to provide guidelines on cased pipeline assessment? Are additional standards development, revisions to current standards, or research and development needed to address certain issues?

Hevle: For cased pipeline practices relating to corrosion, NACE SP0200, “Steel-Cased Pipeline Practices,” provides guidance on design, installation, maintenance, repair, and monitoring. Assessing cased pipelines by pressure test or ILI is covered by standards such as ASME B31.8S, “Managing System Integrity of Gas Pipelines,” and API Standard 1163, “Managing System Integrity for Hazardous Liquid Pipelines.” Right now, there are no standards that provide detailed procedures for assessing cased pipelines using DA.

Didas: The NACE ECDA and casing standards SP0502 and SP0200 provide some guidelines and methods used to assess cased crossings. Both of these standards are in revision and will be enhanced to include additional assessment methods. The Pipeline Research Council International and several industry partners have performed research and have ongoing projects on casings. These have verified several assessment methods and hopefully will assist in developing additional methods.

Keane: What steps are needed to improve oil and gas pipeline integrity and safety?

Rau: My mantra continues to be “support research which develops new technology and enhances existing methodologies; utilize the results of this research to support writing new standards; and finally, rely on these standards for use by the regulatory community to verify that operators are protecting the public good and enhancing public safety.”

Didas: Develop new or improved inspection methods for nonpiggable lines. Keep converting nonpiggable lines to piggable and find more creative ways to pay for these conversions. Keep training personnel in integrity management, corrosion control, and system integrity. Keep improving our integrity management programs and systems in operating companies.

Moriber: Existing pipeline integrity management systems based on U.S. Department of Transportation (DOT) Part 192, Subpart O, and ASME B31.8S provide a sound foundation, and ECDA was a major practical addition, especially for gas transmission pipelines. ILI devices (smart pigs) often were not a feasible alternative for gas piping because of the presence of sharp bends and sudden changes in diameter. In contrast, most oil pipelines were originally designed to accommodate scouring pigs, including facilities for launching and retrieval.

ECDA is a relatively young approach and we need to continue increasing its reliability through provisions for continuous improvement. This could lead to adjustments in regulatory requirements and, ultimately, the most efficient use of available resources. Accurate root cause analysis is critical in developing remediation plans that address the correct issues at the correct locations.

Recent and historical results have shown that cased pipelines present a very low but not negligible risk of corrosion failure, and therefore should be addressed in some fashion. The dilemma is that the costs associated with assessing cased pipelines far outweigh the costs of assessing other areas on a pipeline, by several orders of magnitude, when the risk of corrosion is often lower.

Kroon: Persuade all public and private agencies to eliminate the requirement to case new road and railroad crossings. For existing casings, develop an ECDA methodology for carrier pipes inside casings.

Keane: Do you have any other comments you would like to offer?

Didas: Avoid using casings. However, if you do have to case, use the latest standards and technologies, especially as they pertain to the coating system of the carrier pipe. Because the pipeline will be in atmospheric and/or immersion service, the coating is not only the first line of defense but sometimes is the only line of defense.

Rau: Casings have been safely in service in the pipeline industry for many decades. However, we know the challenges they present and most certainly don’t want to continue to install them. As is true in all aspects of pipeline integrity, the operator must understand the nature of the facility, the threats that the pipeline segment is susceptible to, the assessments designed to address those threats, and the mitigation and prevention activities necessary for the continued safe operation of the facility.

Kroon: As one of the original developers of computerized close interval pipe-to-soil potential survey technology in the mid-1970s, I have seen the industry consistently employ more diligent and more frequent pipeline integrity assessments. Today, most pipeline operators have established programs for regular CP and protective coating testing and evaluation.

Moriber: Regulators and industry need a general understanding that while significant improvements in safe operation are possible with sound risk assessment and pipeline integrity management programs, no approach or combination of approaches can be perfect. It is important to strike a balance between the ideal situation and what is practical. We have a good start in that direction, and the continuous improvement process will get us closer to our objectives as our technology and understanding progress.

The Moderator and Panelists

Tony Keane is the executive director of NACE International, the technical society for corrosion professionals. Founded in 1943 by 11 pipeline engineers, NACE now has nearly 21,000 members in 100 countries and is involved in every industry and area of corrosion prevention and control. With a mission to protect people, assets, and the environment from the effects of corrosion, NACE offers technical training and certification programs, sponsors conferences, and produces industry standards, reports, publications, and software. For more information, please visit

Jeff Didas is a corrosion project manager at Colonial Pipeline Company in Richmond, VA. He has more than 34 years of professional experience in corrosion control. A NACE member since 1975, Didas is a NACE-certified Corrosion Specialist, CP Specialist, Senior Corrosion Technologist, Corrosion Technician, Protective Coating Specialist, Chemical Treatment Specialist, Coating Inspector, and Marine Coating Specialist, and a SSPC Protective Coating Specialist. Didas has an AS degree in electronics technology and a BS degree in electrical engineering.

Drew Hevle is a principal corrosion engineer for El Paso Pipeline Group in Houston, TX. He is a NACE-certified Corrosion Specialist and Coating Inspector and is a NACE instructor in the CP, Internal Corrosion, Pipeline Integrity Management, and Coatings in Conjunction with CP training programs. He chairs several NACE technical committees and task groups related to CP, coatings, internal corrosion, and pipeline integrity. Hevle has a BS degree in mechanical engineering from Louisiana Tech University.

David H. Kroon is executive vice president and chief engineer of Corrpro Companies, Inc. in Houston, TX. He has 38 years of experience in corrosion prevention, including material selection, protective coatings, pipeline integrity, CP, and AC/DC interference mitigation. Over his entire career he has been actively engaged in solving corrosion problems for the pipeline industry. In recent years, he has contributed to the development of DA standards and to the execution of numerous ECDA and SCCDA projects. Kroon has a BS degree in chemistry from Yale University and is a registered professional engineer in eight states.

Norman J. Moriber is chief corrosion engineer for MearsGroup, Inc., Pipeline Integrity Group, in San Ramon, CA. His responsibilities include the engineering analysis by ECDA for hundreds of sections of cased gas transmission piping. He has worked in corrosion control since 1973, specializing in the design and evaluation of CP systems throughout the United States. Moriber has an MS degree in mechanical engineering from the Massachusetts Institute of Technology and is a registered professional engineer in corrosion in California. He is a former director of the NACE Western Region and presently serves as a member of the Materials Performance Editorial Advisory Board.

Jerry Rau is the director of pipeline integrity for Panhandle Energy in Houston, TX. He has more than 35 years of experience in energy-related businesses, primarily oil and gas production and natural gas transmission. He specializes in CP, chemical inhibitors, coatings, and materials selection, including corrosion-resistant alloy materials. He has been heavily involved in the development of corrosion control and integrity management industry standards. He has directed research activities for the pipeline industry and developed and implemented threat assessment and risk management programs. He manages a multi-disciplinary engineering staff of pipeline experts in code compliance, corrosion control, pipeline technical services, and data analysis and integration. Rau has a BS degree in mechanical engineering from Marquette University.


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