Transportation of hydrocarbons and water in long subsea flow lines from satellite fields to a platform or to an onshore facility presents new challenges in the control of gas hydrates, corrosion, and mineral scale. Gas hydrates form at high pressure and low temperature and are a common problem in offshore wet gas pipelines due to low seabed temperatures and elevated pressures in these remote subsea developments. Monoethylene glycol (MEG) is widely used as a thermodynamic hydrate inhibitor in these developments to manage the risk of hydrate formation during production and transportation of multiphase fluids from subsea wells. Due to large amounts of MEG required for effective hydrate control, it is necessary to recycle and re-use it. The main processes for recycling of MEG are regeneration and reclamation. Typical conditions of regeneration and reclamation processes are ambient to vacuum pressures and temperatures in the range of 120°C −150°C1. In addition to the use of MEG for hydrate control, corrosion inhibitors are also applied for corrosion control in the subsea pipelines and infrastructure. These corrosion inhibitors must be able to perform under high shear and highly corrosive environments without losing their effectiveness after having been subjected to the system conditions present in the MEG regeneration process. Inappropriate selection of corrosion inhibitors for MEG based applications can lead to severe fouling/formation of solids, emulsion and foaming issues in the receiving facilities. The corrosion inhibitors developed for use in facilities operating with glycol regeneration systems should remain active after multiple MEG Regeneration Unit (MRU) cycles without causing fouling/formation of solids, emulsion and foaming. The current paper presents MRU compatible corrosion inhibitors developed based on the stringent testing methods adopted from real time MRU process.

Kinetic hydrate inhibitors (KHIs) offer an alternative to traditional thermodynamic hydrate inhibitors (THIs) for the prevention of gas hydrates. KHIs have several advantages over THIs, such as lower required volumes, easier logistics and reduced CAPEX. However, KHIs are once through chemicals leading to increased OPEX, are mostly non-biodegradable and therefore cannot be discharged to sea or disposal wells in fear of aquifer pollution. KHIs can also lead to fouling of process equipment, especially at elevated temperatures. To resolve these issues, a new KHI polymer removal method using a solvent extraction-based technique has been developed. In this approach, an immiscible extraction fluid is mixed into the KHI containing aqueous phase where the KHI polymer partitions into the extraction fluid, which can then be separated from the aqueous phase. In some cases, the KHI separated this way can be re-used. This process has the potential to solve problems with KHI produced water treatment/disposal, including where KHI is used in combination with MEG, reducing the costs and process fouling and protecting the environment. A new joint industry project (JIP) is underway with the aim of developing the concept into a commercial process for removal and possible re-use of KHIs upstream of PW treatment or MEG Regeneration systems. The first phase of this project is lab scale evaluation of the solvent extraction method for simulated removal and re-use of two commercial KHI formulations for a real gas-condensate field case. Both the removal efficiency and hydrate inhibition performance of 4 cycles of re-injected/re-used KHI has been successfully demonstrated. Removal of KHI from a real MEG system case was also successfully demonstrated. In the second phase of the JIP, lab scale tests were used to screen extraction and separation equipment and identify optimum process conditions. The upcoming third phase of this JIP is dedicated to demonstrating the selected process concept(s) on pilot scale in a flow loop. In this proceeding we will give highlights of the early laboratory test results from a produced water case where two field qualified KHIs are removed from PW and reused 4 times, still showing adequate hydrate inhibition performance. Successful pilot tests will confirm the operability of this process in the field.

A new corrosion inhibitor that can reduce oil in water (OIW) was selected for use in a field offshore on Australia's North West Shelf. The selected product has allowed the achievement of the new stewardship OIW target of 17.5 ppm, enabling improvements in overall environmental impact. Laboratory tests showed that the selected product had similar corrosion inhibitor performance to the incumbent field product. Meanwhile, laboratory OIW measurements showed that 50 ppm of the selected product generated significantly less OIW (17 ppm OIW compared to 159 ppm OIW with 50 ppm of incumbent product). On-site tests were then performed with fresh produced fluids, demonstrating again that the selected product resulted in lower OIW (a 42%, 43% and 73% OIW reduction compared to incumbent product, at 20, 30 & 40 ppm of corrosion inhibitor, respectively). A full-field trial immediately demonstrated a decrease in OIW results corresponding to a decrease in overboard OIW from a daily average of 20.0 ppm to 8.8 ppm during the trial period, with no adverse impact on corrosion probe readings. The new product has now been in use on this facility for 10 months. Corrosion monitoring continues to show good inhibition while the OIW levels remain below 16 ppm average, and concurrently is allowing a reduction in the use of associated water treatment chemicals, further benefiting the environment.

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.