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Corrosion Cost and Impact – Australasian Review
Causes and Management of Corrosion
Corrosion is an issue which is encountered in many stages of the oil and gas industries, including oil and gas pipelines, refineries, and petrochemical plants. Corrosion in oil and gas industry is usually caused by water, carbon dioxide (CO2) and hydrogen sulphide (H2S). It can be aggravated by microbiological activity.
Pipelines used in oil and gas processing operate in an environment that differs significantly from pipes in water and wastewater environments. The flow regimes of multiphase fluids greatly influence the corrosion rate. When the flow rate is high, flow-induced corrosion and erosion-corrosion may occur, while when the rate is low, pitting corrosion is more common, and corrosion is generally related to the amount and nature of sediments. High-velocity flow is likely to flush sediments from the pipeline, while low velocity allows sediments to settle at the bottom, providing sites for pitting corrosion.
One issue that adds complexity to management and maintenance of oil and gas infrastructure is the need to ensure corrosion is managed in various environments. As oil and gas extraction industries move into more extreme environments, the complexities of infrastructure development, and corrosion-mitigation of that infrastructure increase. Various environments include seawater, fresh water, air, and soil. Seawater extraction may be in shallow water, deep water, or ultra-deep water, which affects the pressure and temperature requirements of the infrastructure. Extraction may occur in tropical, temperate, or arctic conditions. Each of these environments introduces different chemicals to the pipe infrastructure, and requires various corrosion management initiatives. Where pipes cross environmental boundaries such as shorelines, the complexity of corrosion management increases.
Management of corrosion in oil and gas pipes is commonly conducted using corrosion inhibitors. There are three general categories, being anodic, cathodic and mixed corrosion inhibitors; and can also be categorised as organic or inorganic. Many of the inhibitors are unique mixtures that may contain surfactants, film enhancers, demulsifies, and/ or oxygen scavengers.
Techniques such as managing casing of pipelines across environmental boundaries are being developed. Willis et al. note that it can be complex to predict the exact current flow of the cathodic protection system onto the pipeline. Environmental transitions may result in variable resistivity due to factors such as tidal wetting and drying, groundwater movements or captured run-off. Additional complexity is caused by the coating insulation resistance being likely to become variable across the electrolyte over time. This can lead to coating defects being unevenly scattered, and exposed steel having an uneven covering of calcareous film.Finally, the crude product may be ‘sweet’ or ‘sour’. A sweet field will be free from H2S, while a sour field will have measurable amounts of H2S. Both sweet and sour fields may have a significant proportion of other chemicals such as CO2, chlorides and water. The result of this complex mix is a wide range of pH of the crude, which in turn has an impact on corrosion.
Offshore drilling platforms are built over the water and supported by beam piles driven into the ocean floor. Each beam is surrounded by a pipe casing for protection. The structure of the towers is subject to a range of corrosive factors both above and below the waterline. A range of corrosion prevention methods are used in these structures, including:
- Adding inhibitors to the stagnant seawater between beams and casings
- Cathodic protection, with sacrificial anodes or impressed currents, of underwater structures
- Paints and other organic coatings to protect exposed structures above the splash zone
- Monel sheathing at the casing splash zone. This portion of offshore structures is the most susceptible to rapid corrosion.
Transport, Storage and Refining
There are also corrosion issues in oil and gas transportation and storage. The primary factor is the water that is present in tanks. Corrosion in the refining operations is caused by several chemical reactions, based on the presence of water, Co2, H2S, salt, nitrogen and a range of other compounds.
Costs of Corrosion
While various costs can be identified, there is minimal data in the literature that measures the costs to the economies of Australia or New Zealand. The UK’s Energy Institute ranks corrosion as the second most frequent cause in initiating loss of hydrocarbon containment in offshore platforms.
The costs associated with corrosion in the oil and gas industry can be loosely grouped into several areas:
- The loss of the oil or gas product
- Direct costs; including designing structures to minimise the impact of corrosion, costs of inputs such as corrosion inhibitors
- Indirect costs; including the cost of shutting down the relevant infrastructure (i.e. pipeline, refinery, etc.) for maintenance and corrosion prevention and associated labour costs
- Remediation costs in situations of infrastructure failure, including the labour costs involved in remediation, the material costs of restoring the infrastructure, and the environmental costs of any leak as a result of a rupture that escapes the containment
Calculation of the costs of any of these components is complex.
For example, the cost of corrosion inhibitors is inherently complex. The cost of installation and maintenance of injection equipment, inhibitor chemical(s), monitoring inhibitor concentration(s), system changes to accommodate the inhibitor, system cleaning, waste disposal and personnel safety equipment, must be factored into any economic evaluation of the use of corrosion inhibitors.
The cost of designing structures to minimise corrosion includes appropriate selection of pipeline materials. Iannuzzi et al (2017) note that high strength materials, including low-alloy steel (LAS) and corrosion resistant alloy (PH-CRA), are essential to overcome the materials hurdles associated with the production of hydrocarbons from unconventional reservoirs. Two forms of corrosion are identified, being local degradation and environmentally assisted cracking. As infrastructure is being utilised in extreme environments, management of both factors is crucial.
Fortunately, there have been relatively few instances of corrosion leading to environmental damage in Australia and New Zealand. In 2015, corrosion of an oil pipe in Tauranga Harbour, New Zealand led to an oil spill. In this incident, heavy fuel oil spilled from a ship bunkering at the Port of Tauranga. The outcome was described as a boiling black mess” on the harbour’s inner waterways.
At least three birds were found oiled and treated at a bird sanctuary following the spill. From a global perspective there have been many other instances of oil infrastructure failure. One well-studied incident was the Deep Horizon oil spill in 2010. The cost of the clean-up has been identified as over $US14 billion. Potential catastrophic failures caused by corrosion in the Australasian Oil and Gas industry could result in costs of this magnitude.
New techniques are being developed to monitor the infrastructure for early detection of localised corrosion. An example is a multiple ring pair electrical resistance sensor (RPERS) array. This concept was presented at Corrosion Prevention 2019. In addition, a whole-of-life, holistic approach can be implemented that takes account of construction and projected maintenance costs of a project. Using such an approach, it may be possible to incorporate materials and processes into a design that leads to reapplying surface coatings every 15 years instead of 10, with significant savings.
An example of a holistic approach is the Gorgon Project in Western Australia. This incorporates the 130Km Jansz-Io subsea pipeline. It is expected that the plant will produce 15.6 million tonnes of LNG annually; as well as feeding a domestic gas plant with the capacity to supply 300 terajoules of gas each day. The holistic approach includes maintenance plans for the estimated 50-year life of the project.
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