In normal operation, a gas condensate field can be operated in pressure and temperature conditions where hydrates are stable. To mitigate the formation and deposition of hydrates, Mono Ethylene Glycol (MEG) is injected in the subsea flowline at high concentration (30 to 60% vol. versus water) (Yong Bai, 2019). MEG is then separated from water in the MEG Recovery Unit (MRU) and reinjected in the flowline while the water is discharged to environment or reinjected in the reservoir.

When wells are aging, the water production is increasing and consequently the MEG flow rate. The increase of the liquid holdup (Water + MEG + condensate) in the production lines leads to a pressure buildup and increases the frequency of pigging outages for liquid removal. Therefore, finding a Low Dosage Hydrate Inhibitor (LDHI) could help to lower the volume of liquid (MEG) and consequently decrease the backpressure. (Bhajan Lal, 2020). This type of additive has shown that they can bring significant benefits in terms of additional production, HSE improvements and OPEX savings. (A. Singh; 2006; Orlin Lavallie, 2009)

This study is assessing the feasibility to replace MEG injection in the production lines to prevent hydrates formation by a Low Dosage Hydrate Inhibitor (LDHI), in this study Anti-Agglomerant (AA) because the subcooling is higher than 10°C. AA does not inhibit hydrates formation but prevents their agglomeration in the condensate phase. A viscous slurry, composed of condensate and hydrates will be transported to the surface installation. These last years, chemical suppliers have developed "green" AA to limit environmental impact when discharged to environment. These products efficiency will be evaluated during the study.

You can access this article if you purchase or spend a download.