At offshore oil and gas fields around the world, there are thousands of kilometers of sub-a pipelines connecting drill-ing rigs and production platforms to well-heads and onshore facilities. These assets represent billions of dollars that companies have invested over many years. There are many advantages in planning corrosion control and mitigation for these high-value assets. Two advantages include extending 1 he lice of an asset and reducing maintenance time and costs. Conversely ignoring the effects of corrosion can result in cost repercussions.
The marine environment is a harsh one, which exposes the external surfaces of pipelines to a range of external physical, climatic, and chemical effects that can cause corrosion and degradation. Additionally, the fluids flowing through a pipeline are corrosive to the inside surfaces. Monitoring the impact of corrosion on subsea pipelines and offshore structures is a critical aspect of ensuring pipeline integrity. A key approach for minimizing corrosion is to employ appropriate protection technologies.
Fortunately, many companies supply products and services that meet the varied corrosion challenges of offshore and deepwater oil and gas operations around the world. To enhance the effectiveness of the work done by these companies. the Australasian Corrosion Association (ACA) (Kerrimuir. Victoria. Australia), NACE International, strategic partner that is involved in the fight against corrosion in Australia and New Zealand works with industry and academia to research all aspects of corrosion so an extensive knowledge base can be developed that supports best practices in corrosion management and helps ensure all impacts of corrosion are responsibly managed. the environment is protected public safety is enhanced and economies are improved.
According to David Flanery, business development manager at Deepwater Australasia Pty.. Ltd. (Perth. Western Australia), the method of corrosion protection selected depends on the material used to construct offshore infrastructure. An offshore production field is a very complex system, Flanery notes, ideally, all the different components and their separate corrosion protection needs should be carefully planned at the design stage: For example oil and gas typically flow from 1 he reservoir. through the subsea tree. and to a manifold or pipeline end termination (PLET) via a jumper pipe, which is a short flexible or rigid length of pipe used to connect a flowline to other components.
Fluids pass along the pipelines to a production platform for processing before being sent to a tanker or onshore facility for further processing. Pipelines are often epoxy coated or encased in concrete, whereas a platform usually has large amounts of exposed steel. Subsea assets often require protective systems that include special coatings with a long operational life, sacrificial cathodic protection (CP) systems, or combinations of these. “With an effective protection system and regular maintenance, an off-shore field should have an operational life of up to 40 years, he says.
At times there can be a design gap between the corrosion protection systems of two adjacent assets, such as a flowline and a manifold. This can occur because each specific component is manufactured by a specialist company and then installed on the seabed by different contractors. Communication between companies about the corrosion protection system for assets they provide is some-times overlooked, and the operator may not take a holistic view of the field. “You cannot just look at a pipeline in isolation” Flanery comments. “It is always part of a much larger system”.
Typical offshore pipelines are com-prised of 12-m lengths of pipe welded end-to-end on a pipe lay vessel. Each joint is covered with a factory-applied anticorrosion coating. except for -600 mm at each end. These areas are left bare to prevent the heat during welding operations from damaging the coating. Once the girth weld between the two joints is completed. an uncoated area of ~1.2 m remains. Most pipelines are designed to use a field-applied joint coating. typically in the form of a heat-shrinkable sleeve.
When protecting subsea pipelines with CP, the most common system uses bracelet anodes that are clamped onto the pipeline approximately every 10 joints. or 120 m. The anode is bonded to the pipeline via small wires, or bonding straps, fastened to studs welded directly to the pipeline. To ensure the corrosion control systems are operating as designed, and to certify there is no danger of a pipeline rupturing, regular inspections are required of any company operating an offshore oil field. For compliance. usually the entire length of the pipeline needs to be surveyed every five years.
One method of monitoring a pipeline, CP system is called electrode field gradient (EFG) measurement, where a remotely operated vehicle (ROV) or diver swims along the entire length of a pipeline to record the field gradient of the pipeline, CP system. Field gradient can be used as an indication of CP activity. The field gradient strength is a function of the distance between the reference electrode array and the pipeline. However, all pipe-line surveys must include periodic readings along its length with a stab probe to recalibrate the EFG readings.
“While towed or autonomous under-water vehicles can be used, you cannot really tell how good a pipeline is without contacting it”, Flanery adds.
One of the latest methods for survey-ing pipelines is to install CP test stations at regular, calculated intervals, similar to those for onshore buried pipelines. This enables a more rapid and accurate pipe-line survey using minimal survey equipment aboard a survey vessel. An ROV or diver is required to make contact readings at these test stations using a special stab probe. This method allows the survey vessel to plan stops along the pipeline corridor and drop a diver or ROV into the water only at those locations. The diver or ROV ‘stabs” the test station with the probe and this is correlated with the readings from an EFG probe to determine the integrity of the CP system at that point. Next, a nearby anode can be located and stab probed. During both contact measurements, the voltage gradient is recorded.
From these readings, the survey crew can use onboard pipeline CP attenuation modeling to determine the next appropriate survey site and report on what actions may need to be taken immediately or planned to maintain optimal operations.
To maintain surface coatings, asset owners typically use service companies such as Independent Maintenance Services Pty., Ltd. (IMS) (Dandenong, Victoria, Australia, The scope of the work these companies carry out on offshore structures ranges from general maintenance work through surface preparation and coating to nondestructive testing.
According to Jan Sikora, operations manager at IMS, all of the work his company does to keep offshore structures in optimal condition is proactively planned by t he asset owners.”Regular inspections are carried out to determine the condition of an offshore installation and then the asset owner plans the schedule and scope of works to be carried out by us: he adds.
Working on the structural cross members of an offshore platform requires a unique combination of skills, but also additional safety precautions. IMS staff members need to be good corrosion prevention technicians as well as proficient rope climbers (abseilers).
“Both of the skills are very important in our job and we emphasise the safety is observed in all aspects of our work, “Sikora says. “When we find the right person with the appropriate corrosion qualifications, we train them in rope access. To ensure the safety of our workers is not compromised, we also hire experienced Level 3 abseilers and then train them in corrosion prevention techniques.”
Comprehensive planning is a priority when dealing with the constraints and challenges of offshore corrosion control. “Once we get to an offshore site. if we for-get something it is hard to arrange delivery of more materials or tools,” Sikora adds. “You can’t just jump in your van and drive to the local hardware store.”
The weather and access can also have an impact on work at an offshore site. There is often limited space for the workers and all of their equipment on an off-shore platform, and sometimes the workers must travel on and off the platform every day, which restricts the actual working hours available. Fortunately, the latest polyurea and polyurethane coatings and primers have been developed to have rapid cure times so that structures can be covered quickly.
Source: Australasian Corrosion Association. Inc, corrosion.com.au p 14-16.