Subsea pipeline corrosion management

The harsh marine environment exposes pipelines to a range of severe climatic and chemical conditions, resulting in a range of corrosion challenges requiring mitigation.

At offshore oil and gas fields around the world, there are thousands of kilometres of subsea pipelines connecting drilling rigs and production platforms to wellheads and onshore facilities. These represent billions of dollars of investment by companies over many years.

Owners of these high-value assets must understand the cost implications of ignoring the effects of corrosion. There are many advantages of planning for corrosion control and mitigation, two of which are that the life of an asset can be extended and maintenance time and costs reduced.

The marine environment is a harsh one, and pipelines are exposed to a range of external physical, climatic and chemical effects that can cause corrosion and degradation to the outside of the pipes — not to mention that the fluids flowing through a pipeline are themselves 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 way of minimising corrosion is to employ appropriate protection technologies. Companies such as Deepwater Australasia (DWA), Carboline and Independent Maintenance Services (IMS) supply products and services that meet the varied challenges of offshore and deepwater oil and gas operations around the world.

To enhance the effectiveness of the work of companies like DWA, IMS and Carboline, the Australasian Corrosion Association (ACA) works with industry and academia to research all aspects of corrosion in order to provide an extensive knowledge base that supports best practice in corrosion management, thereby ensuring all impacts of corrosion are responsibly managed, the environment is protected, public safety is enhanced and economies are improved.

Most of the world’s shallow water oil and gas deposits have been found. As the demand for oil has increased, exploration companies have been looking at reservoirs in deeper and deeper waters. The cost of floating facilities and platforms over deepwater reservoirs is extremely high, so projects with equipment located on the sea floor are becoming common.

According to David Flanery, business development manager at DWA, the method of corrosion protection selected depends on the material that is used to construct offshore infrastructure. Pipelines are often epoxy- or concrete-encased, whereas a platform usually has large amounts of exposed steel. Subsea assets often require protective systems that include special coatings with a long-duration operational life, sacrificial cathodic protection systems or combinations of these.

Ricky Collins, sales manager Australasia at Altex Coatings, a regional Carboline supplier, stated that manufacturers have developed insulating products that have been designed to withstand the rigours of deepwater operations. The material used in these has been specifically engineered for use with subsea pipelines.

Surface coatings and other corrosion prevention methods are usually maintained by companies such as IMS. The scope of the work these companies carry out on offshore structures ranges from general maintenance work through to surface preparation and coating to spot blasting and painting.

According to Jan Sikora, operations manager at IMS, all of the work his company does to keep offshore structures in optimal condition is planned proactively by the 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 said.

There are a variety of methods for securing a pipeline while on the seabed. The depth of the water above the pipe determines whether it must be buried or weighted to keep it in place. In general, if the water depth is less than 50 m, most countries require that pipelines be laid in a trench.

The working and operating environment for equipment and pipelines in the deep ocean are vastly different to those of coastal activities. The temperature of seawater at depths of thousands of metres drops to around 2°C, while oil from deep wells can be as hot as 176°C. As the hot oil comes up from the well, it travels through the much colder pipeline and the fluid in the pipe can quickly cool down. At approximately 21°C, the water and gas mixtures in the pipe can form gas hydrates or paraffins. If the build-up of paraffins is too great, it can ultimately block the pipeline. Such blockages can be extremely costly to clear and, if a pipeline ruptures, can cause catastrophic damage to equipment and the environment.

It is therefore essential that appropriate insulating materials are applied to infrastructure in order to maintain or at least slow down the heat loss from the fluids being transported. Manufacturers of surface coatings have worked to develop suitable materials to handle the extreme conditions of deepwater activities.

“An offshore production field is a very complex system,” Flanery said. “Ideally, all the different components and their separate corrosion protection needs should be carefully planned at the design stage.”

For example, oil and gas flows from the reservoir, through the subsea tree and, typically, to a manifold or pipeline end termination (PLET) via a jumper pipe. Fluids pass along the pipelines to a production platform for processing before being sent to a tanker or onshore facility for further processing. (A jumper is a short flexible or rigid length of pipe that is used to connect a flow line to other components.)

There can at times be a design gap between the corrosion protection systems of two adjacent assets, such as a flow line and a manifold. This can occur because each specialist company manufactures its specific component and different contractors lay them on the seabed. The corrosion protection system for each asset is sometimes not communicated between companies and often the operator may not take holistic oversight of the field. “You cannot just look at a pipeline in isolation,” Flanery said. “It is always part of a much larger system.”

Typical offshore pipelines are composed 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 approximately 60 cm at each end. These areas are left bare to prevent the heat from welding operations from damaging the coating. Once the girth weld is completed between the two joints, an uncoated area of approximately 1.2 m remains. Most pipelines are designed to use a field-applied joint coating, typically in the form of a heat-shrinkable sleeve.

Clamping an anode to an underwater pipeline.

Cathodic protection (CP) is a technique used to control the corrosion of a metal surface by making it the cathode of an electrochemical cell. A simple method of protection connects the metal to be protected to a more easily corroded ‘sacrificial metal’ to act as the anode. The sacrificial metal then corrodes instead of the protected metal.

The most common CP system for pipelines 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.

Regular inspections are a requirement of any company operating an offshore field and they must be able to certify that there is no danger of a pipeline rupturing. For compliance, usually the entire length of the pipeline needs to be surveyed every five years.

One method of monitoring a pipeline’s 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’s CP system. Field gradient can be used as an indication of cathodic protection activity, and the field gradient strength is a function of the distance between the reference electrode array and the pipeline. However, all pipeline surveys must include periodic ‘stabs’ along its length to recalibrate the EFG readings.

“While towed or autonomous underwater vehicles can be used, you cannot really tell how good a pipeline is without contacting it,” Flanery added.

One of the latest methods for surveying pipelines is to install CP test stations at a regular, calculated interval, similar to those for onshore buried pipelines. This enables a more rapid and accurate pipeline survey using minimal survey equipment aboard a survey vessel. An ROV or a diver is required to make contact readings at these test stations using a special 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 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 stabbed. During both contact measurements, the voltage gradient is recorded.

From these readings, the survey crew can use onboard pipeline CP attenuation modelling to determine the next appropriate survey site and report on what actions may need to be taken immediately or planned to maintain optimal operations.

Several deepwater pipeline coatings are premium-grade, tough, resilient glass syntactic polyurethane elastomers that provide the required thermal insulation properties and are 100% solids ‘cast in place’ material.

“The term ‘100% solids’ implies a coating in solid form, but this is misleading,” said Collins. “The term actually means that the coating contains no solvents or VOCs.”

Zero volatile organic component (VOC) coatings pose no fire hazard and only a low health risk while the coating is being applied. They are also very environment friendly, as hazardous organic solvent vapour is not generated and released into the air.

‘Syntactic foams’ contain the right combination of resins, pigments and glass spheres to provides the necessary properties to handle the environment and application parameters. Standard lightweight insulation is not suitable for the deepwater environment, as they cannot endure long-term water exposure and low temperature. More importantly, under the extreme pressures at these water depths (3000–6000 psi), most insulation materials will simply collapse and not survive the 25-year life expectancy of the equipment.

Collins added: “A product like Carboline’s Carbotherm 735 will handle all these conditions and yet is flexible enough to tolerate movement, bending and vibration during shipment, installation and operation.”

Working on the structural cross members of an offshore platform requires a unique combination of skills, but also additional safety precautions. IMS staff need to be good corrosion prevention technicians as well as proficient abseilers.

Technician abseiling down the support structure of an offshore rig.

“Both of the skills are very important in our job and we emphasise that safety is observed in all aspects of our work,” Sikora said. “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 the priority when dealing with the constraints and challenges of offshore corrosion control. “Once we get to an offshore site, if we forget something it is hard to arrange delivery of more materials or tools,” Sikora added. “You can’t just jump in your van and drive to the local hardware store.”

The weather and access can also impact on work at an offshore site. There is often limited space for the workers and all their equipment on an offshore 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.

“With an effective protection system and regular maintenance, an offshore field should have an operational life of up to 40 years,” said Flanery.