A significant number of the offshore gas projects planned for the North West shelf of Australia present corrosion and flow assurance challenges (paraffin wax, hydrates and scale). Temperatures at the wellhead may be as high as 140°C, which combined with carbon dioxide levels of 10–20 mol % could lead to aggressive, acidic gas corrosion of the infrastructure and pipelines. The water depth, temperature and operating conditions of these pipelines may result in hydrate formation and subsequent blockages (particularly during shutdowns). Many of the projects have a base case specifying the use Mono Ethylene Glycol (MEG) to suppress hydrate formation in the pipelines. In the majority of these systems, the MEG is regenerated either at satellite platforms or onshore processing plants after which it is resupplied to the injection point offshore (i.e. a re-circulating glycol system). This basis of design requires a different approach towards chemical selection than a once through system due to the possible impact of the corrosion inhibitor (and other chemicals) on the glycol regeneration system. This paper details the corrosion challenges of these systems and describes the testing required to: Develop corrosion inhibitors that will reduce the potential for severe corrosion; and, Meet the requirements for use in re-circulating glycol systems.

Continous injection scale inhibitors are routinely used to control the formation of mineral scales, such as calcium carbonate and barium sulfate, within topside or subsea applications. The development of chemical injection systems to deploy scale inhibitors deep into production wells presents further challenges due to the higher temperature of the injection point. While phosphate esters, phosphonates and polymers constitute the major types of scale inhibitors applied to control scale in oilfield applications, all are known to be corrosive to Low Alloy Steels (LAS). This paper will detail the development of low corrosivity scale inhibitors for downhole systems containing LAS components within the scale inhibitor's flow path. A number of subsea fields have been developed in recent years with wellhead trees containing LAS components, in particular F22 carbon steel. F22 carbon steel has been found to be very susceptible to corrosion attack by scale inhibitors typically used in the oil field. To quantify the problem and work towards a solution, existing products covering all major generic types of inhibitors were evaluated using static immersion corrosion tests at test temperatures ranging from 180°F to 300°F; these tests revealed corrosion rates in excess of 30 mpy for these inhibitors against F22 carbon steel. Initial work involved changes to inhibitor formulations by adjustment of pH or changes to neutralization agents. Unfortunately these changes failed to reduce the corrosion rate to acceptable values. Based on the initial screening work new formulations were developed resulting in very low corrosion rates (<1-4 mpy) in the presence of LAS such as F22, AISI8630 and 1018 carbon steel. Data will be shared which shows that the new scale inhibitor formulations have very similar performance compared to a typical, more corrosive subsea applied scale inhibitor. The new formulations have been qualified for downhole chemical injection through an umbilical and are currently being applied or approved for use at Gulf of Mexico and West Africa fields. Development of these low corrosivity scale inhibitors will allow operators to prevent scale issues in subsea fields without impacting the material integrity of delivery systems containing LAS components.