Pipeline Health Care |
July 2010 |
Integrity Management Specialists Help Owners Protect Assets
Compiled By NAP Staff
Pipeline integrity is critical in an industry that transports a vital commodity like oil or natural gas. During construction, coatings are applied to help protect the pipe throughout its life cycle. After the line is in the ground, inspection and remediation tools help maintain the system for the long haul.
Corrosion is the biggest culprit in pipeline degradation. North American Oil & Gas Pipelines spoke with two professionals in the field of pipeline integrity management to better understand how to protect pipelines.
James A. Huggins is president of CRTS, which provides robotic internal field joint coating, external field joint coating and rebar coating plant equipment for the pipeline industry.
“While the field joint is a small percentage of the overall pipeline surface area, by its nature the coating must be applied in the ‘field’ rather the controlled environment of coating plant facility near town,” Huggins says. “Processes are available that replicate the high quality and varied materials available in the plant based facilities, delivered in some of the most remote places on Earth.”
Charles Hall is director of business development for MESA, an engineering, construction and manufacturing firm that supplies materials and services to meet the corrosion control needs of the pipeline industry.
“The first line of defense in pipeline corrosion control is a perfect coating. Since that rarely happens, and degradation occurs with age, the services and products that MESA provides are intended to assist in the battle to remediate corrosion,” Hall says. “While a large part of our business is cathodic protection, there are other corrosion control requirements that we support through our fence to fence program in terminals and refineries, from assessment preparation to remediation planning and implementation in transmission, gathering, and distribution systems.”
North American Oil & Gas Pipelines: What are the necessary steps in creating and maintaining a pipeline integrity management program?
James A. Huggins: First and foremost, construct your pipeline with a thorough specification and make sure your quality control people are involved every step of the process. Contractors in North America do excellent work. It’s even better when your Q/A is present holding them to a well written specification. Trust but Verify…. In fact, I would argue that all field joint coating should be accomplished by a professional field joint coating applicator rather than the general pipeline construction companies. Specialist companies tend to retain their people and with the variety of processes and materials involved it is difficult for non-specialist companies to retain the know-how between jobs.
Charles Hall: Creating and maintaining a pipeline integrity program requires that the operator first set up the IMP program which utilizes the framework of Integrity Management. One example of what this requires can be found in the American Petroleum Institute document API 1160, Figure 5 – 1.
Pipeline operators need to identify the high consequence areas (HCA). For liquids, the HCA meaning is different than the population requirement of a natural gas transmission pipeline. Natural gas pipelines identify the potential impact radius surrounding the pipeline to define what the consequence of a failure would be and performing an assessment of what facilities or head count of people are with the consequence area. Liquids companies define what remediation planning is required in the event of a spill and utilize this information to plan for containment.
One of the most critical steps in the process is the initial data gathering, review, and integration. The types of data gathered are operational, maintenance, and surveillance practices, pipeline design, operating history, the specific failure modes and concerns that are unique for each pipeline system and segments within that system.
Each operator has to perform a risk assessment in a systematic and comprehensive search for possible threats to pipeline or facility integrity. The risk control and mitigation process involves, i.e., identification of risk-control options that lower the likelihood of a pipeline system incident, reduce the consequences or both, a systematic evaluation and comparison of those options and selection/implementation of the optimum strategy for risk control.
Each operator develops a baseline assessment plan to address the most significant risks while assessing the integrity of the pipeline system. This plan must be documented with the ILI, Hydrostatic Testing, ECDA or Other Technology that will be applied to assess the pipeline’s integrity. A schedule is established for conducting the assessments along with the justification for the integrity assessment method. The highest priority risks should be evaluated first.
From the baseline assessment, there are inspections performed and mitigation plans developed to remediate the results discovered. Once the inspection and mitigation plans are completed, a verification process should be developed to ensure the performance measurements and remediation success.
The baseline assessment and remediation results should be retained. The data should be incorporated through data integration into a data/information management system. This requires continuous updates, integration and review. As the process proceeds there will be additional system information that will require inclusion to that improves the quality of data management.
Each operator should then reassess the risk periodically to factor in the results and more recent information in defining the pipeline condition. The baseline assessment plan should be utilized to revise mitigation and inspection plans for the future.
Collection of performance information allows the operator to evaluate the success of the integrity assessment techniques, pipeline repairs and other preventative or mitigation activities that were perform. And oftentimes the most difficult task is communicating the changes that have occurred to personnel. A change management system is required to ensure the communication and programmatic updates are accomplished.
These steps are not a one-time requirement. Successful performance of an integrity management program requires constant maintenance and measurement from continuous improvement. The integrity management requirements help us meet regulatory requirements and ensures the pipeline’s safeness, including protecting the public and our environmental assets.
NAP: What new developments have there been in pipeline inspection and maintenance over the past five years?
Huggins: Earlier generations of our Internal Field joint coating process relied on visual quality control processes when the pipe was too small for man entry to verify coating thickness and perform holiday detection tests. In 2005 we patented an inspection Robot that can measure applied coating thickness and check for coating defect with high voltage holiday detection tool. We have recently completed two additional inspection devices, one that can inspect the entire length of pipe for internal holidays and the other that can inspect for holidays offshore.
NAP: What kinds of problems lead to pipeline failure?
Hall: The greatest threat to pipelines is Third Party Damage. External Corrosion is the second greatest threat. External corrosion occurs when the system designed to prevent corrosion control fails. Depending on the pipeline operating pressure and design, external corrosion may result in a rupture or a leak.
As pipeline systems age, the first line of corrosion control defense is the pipeline coating. With age it degrades and becomes less effective in isolating the pipeline steel from the environment. As this aging process occurs there is more and more maintenance work required assessing and maintaining the quality of system performance.
Cathodic protection supplements the aging coating either with a galvanic or impressed current that provides protection to the steel where it is exposed to the environment. These two systems, coating and cathodic protection, need to be monitored in a more continuous condition to ensure the remaining life effectiveness. When these systems fail, the pipeline is at risk for corrosion damage.
Traditional monitoring of the pipeline by an annual survey obtained at electrical test leads spaced typically at one mile or ½ mile intervals. As the coating degrades, those test stations (when read) represent less than .1% of the pipeline. With age this sample of the pipeline is insufficient and requires non-traditional monitoring.
Non-traditional methods of assessing the condition of the cathodic protection systems are utilized, i.e., close interval survey, direct current voltage gradient, alternating current voltage gradient, etc. Each tool applied has limitations. In the close interval survey example, small anomalies are often not recognized in the data profile obtained. This would suggest that a supporting tool should be applied. An example of a complementary tool could be Direct Current Voltage Gradient (DCVG). DCVG identifies where cathodic protection currents are being applied to the coating holidays or anomalies where the steel is exposed to the environment. DCVG limitation is that it will find the largest area of cathodic protection being picked up and may mask smaller anomalies directly adjacent. This is why complementary tools are required to access the pipeline conditions.
As the pipeline coating ages and supplemental CP systems struggle to prevent corrosion, it may become necessary to replace the pipeline coating. While this is very expensive, ensuring the integrity of the pipeline and preventing corrosion becomes a necessary step in the process. Alternatives to replacing the coating and reducing the gas throughput due to this maintenance activity are pipeline replacements.
NAP: How do you mitigate those problems?
Hall: MESA assists the operator in assessing, remediating, and maintaining the pipeline system integrity through the prevention of corrosion with the materials, engineering, construction and services required to support improvements to the pipeline integrity. As a turnkey service provider, our objective is to provide the varying level of service that each operator may require, with service driven and quality focused support.
What new developments have there been in pipeline inspection and maintenance over the past five years?
Robotics in smart pig applications is probably the most exciting development at this time. There continues to be emerging technologies in response to the increased regulatory oversight and integrity management requirements. Cased crossing requirements will drive the next round of improvements to be developed.
NAP: What challenges does the pipeline industry face today in regards to maintaining a reliable system?
Huggins: Pipelines built with appropriate design specifications, pipe manufactured to the same, pipe coated by professional coating companies, installed by qualified installation contractors and inspected as the pipe is laid in the ground will give the pipe owner the best return on its investment with the least amount of future liability. How you measure the value of those things in today’s dollars is what separates companies.
Hall: With aging pipeline systems and facilities, the cost of health care of these facilities will continue to increase. Our gas and liquid operating companies will be continuously challenged to pass through the cost of remediation as their maintenance costs increase to operate the aging systems. Rate case struggles will challenge pipeline operators to remain viable while implementing these large costs of remediation, especially as more and more oversight regulations are implemented.
The greatest challenge is to remain focused on continuous improvement of these facilities. Justifying large recoating projects is economically difficult for pipeline operators to do. In the past, repair expenditures tended to be more cyclical. With the pipeline systems having long exceeded the original life expectancy, the pipeline maintenance costs increase with age.
Replacing the failed coating systems can be so costly that the replacement cost and capitalization is more attractive.
With the Pipeline Safety Reauthorization Act being debated currently in Congress, as well as the idea of extending the IMP requirements across the entire length of the pipeline, operators will have to reassess the baseline assessments and make adjustments if Congress is successful in implementing further IMP requirements.
NAP: Can you describe the process of internal field joint inspection? How often should a pipeline be inspected?
Huggins: Internal field joint inspection involves sending a remotely controlled inspection robot (no umbilical) into a pipe string that has been coated. The robot has real time video feedback and will be guided to a coated field joint. The robot operator will line up on the field joint and trigger the robot to inspect. The robot will check the coating thickness in 4 places ninety degrees apart around the full circumference. The machine will then automatically begin the high voltage holiday inspection test. A conductive holiday test brush will extend out to the pipe surface and begin to circumnavigate 360 degrees.
If the brush senses a defect in the applied coating, the high voltage will jump through the defect and make a sound (commonly referred to as a “Jeep” in pipe coating inspection terminology). The operator will also see a “Holiday Detected” alarm written in text across his monitor letting him know of the discovery. He will make a note of the thickness readings and the holiday inspection results pertinent to that specific field joint (butt weld) before moving on to inspect the next joint. This whole process is recorded for a permanent client and CRTS record.
As our process only considers inspection of the pipeline during construction we do not see any requirements for our type of inspection services later on in the life of the pipeline.
NAP: What kinds of things does regular inspection help prevent?
Huggins: Our inspection process increases delivered quality, improves pre-coating preparation processes and identifies welding practices that affect the field joint coating process and the resulting quality. This process is only utilized during new pipeline construction and is not appropriate for inspection on pipelines after they have been put in service.
NAP: Can you describe the process of inspecting a pipeline (in-line, robotic, etc.)? How often should a pipeline be inspected?
Hall: For an operator to perform in-line inspection (smart pig), the pipeline must be piggable. An initial inventory of the pipeline is required. This would include, at a minimum, determining the following: if the valves are full opening, if a collapsible pig can pass through the valve in place, if there are bars on the tees, if there are taps on the pipeline system that will require excavation and the tap is retracted far enough to not damage the pig as it passes, what the presence of pig launchers and receivers is, if there is sufficient gas flow to pass the pig at controlled speed requirements and not get hung up, if the radius of the bends are too tight to allow the pig to pass, etc. This initial data collection and evaluation process is necessary to define the scope of work required to be performed to prepare the pipeline for pigging.
Once remedial action is completed and the pipeline has been made piggable, several preparation pig runs are necessary. A gauging plate pig is passed to ensure that the smart pig will be able to pass through. This gauging tool will identify dents or unknown components in the pipeline that may result in damage to the tool or prevent the pig from arriving at the receiver. The pipeline will have foam pigs running through the pipeline to a more aggressive brush pig that cleans the pipeline prior to running the smart pig.
Gas control will guide the process by scheduling the smart pig run in conjunction with customer flow requirements. Conditions in the gas flow will need to be administered to maintain the right speed of travel of the smart pig to ensure the best data possible. Above ground markers will be established at some prescribed intervals and these markers will be surveyed by either sub-meter or sub-centimeter GPS for data integration and pig tracking requirements. Prior to the ILI run, a dummy pig run may be performed, with the support team, that will track and monitor the pig. Depending on where the pipeline traverses, speciality air boats maybe required to track the pig run.
As with any data collection process, surprises happen. The best laid plans require adjusting to the conditions for when the pig run is launched. Inclusion of a tracking device on the pig enables the operator to find the pig when an upset condition occurs. Redundancy in pig tracking tools may be a wise expenditure.
NAP: What kinds of things does regular inspection help prevent?
Hall: Regular inspections help to identify problems before they become irreversible or catastrophic along with reducing the cost of repairs or remediation. Just as checking the oil in a car helps prevent that expensive engine replacement, assessing the pipeline condition on a regular basis prevents more costly repair or replacement needs later. Failure to perform regular inspections may result in loss of life or operational safety at critical times. Regular inspections and maintenance extend the life of the asset and is a good asset management process.
NAP: What benefits do robotics provide in the field of pipeline inspection?
Huggins: Our field joint coating allows owners and engineers trying to design around extremely aggressive corrosion environments a new tool in building a pipeline that will reach its design life with no or at least fewer maintenance problems. Not every pipeline is a candidate for internal lining and field joint coating. Clean dry gas and refined products are not very corrosive. The most corrosive agent in most pipelines is water. Any pipeline that has water or has a flow media contaminated with water are appropriate applications of this technology.
NAP: Can you describe the process of how MESA creates a data analysis solution? How often should this be done? Why is it necessary?
Hall: Depending upon the data problem being considered, customized data analysis solutions may need to be designed. There is the data that has been collected and the data that already resides in the client system, which, when combined and analyzed together, offer a view of the big picture. Each field data collection stream has pre-defined analysis parameters from which problems areas are defined. MESA’s exclusive software also allows our data specialists to write customized analysis parameters for inclusion and implementation. The software allows the problem areas to be sorted and reported, which is the concept of Management by Exception.
For the data collected, the data streams are imported, matched, and quality control checked prior to the analysis being performed. A similar process is utilized to integrate the collected and historical data streams together for final analysis. Data gets converted and analyzed and then becomes meaningful information that helps realize remedial solutions.
Computerization in the corrosion industry has created the opportunity for reams of hard copy data to become the basis for information management. This volume of data requires conversion, integration, automation, and analysis. The platforms today allow flexibility of simple customization that was not possible in the past.
Presentation of the managed by exception data by a visual display identifies the problem areas by color code. Before this concept was possible, it was the function of an individual to find the way to communicate verbally or in writing what tons of hard copy data was saying and took weeks to review/prepare.
The key to managing by exception is the ability to integrate multiple years to determine remediation success or analyze the aging trend on the pipeline being reviewed. Visual presentation of these trends with color coding simplifies the ability to manage, analyze, review, administer, and remediate miles of data.
Other data streams that are stored in a database format, i.e., annual surveys, rectifier data, etc., can be integrated into a Pipeline Analysis Graph Evaluation report. Managing the data into an output than can provide the information necessary is key to assessing the most cost effective measures of performing integrity management. Finding the right remedial solution is a function of mining the answer from the data analysis process and learning through continuous improvement.