March 2016 National Resources Review

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 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 Pty Ltd (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 enhanced and economies 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 deep water reservoirs is extremely high, so projects with equipment located on the sea floor are becoming common.

There are a variety of methods for securing a pipeline while on the sea bed. 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 metres, 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. 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.

Subsea Flow Assurance is a term used in the offshore oil and gas industry to describe processes that ensure subsea pipelines and equipment maintain oil flow. 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 deep water activities.

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.

“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.11 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.


There can at times 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 specialist company manufactures its specific component and different contractors lay them on the sea bed. 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 metre lengths of pipe welded end-to-end on a pipe lay vessel. Each joint is covered with a factory applied anti-corrosion coating, except for approximately 60 centimetres 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 metres remains. Most pipelines are designed to use a field applied joint coating, typically in the form of a heat shrinkable sleeve.

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 metres. 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. 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 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.