The main objective of this paper is to identify any current and future bottlenecks in the production system while honoring operational constraints on wells, production separators, pipelines, and total field gas/liquid processing capacity. It also concerns with identifying any flow assurance issues taking in consideration different field development scenarios for an offshore gas condensate field in the Mediterranean (Abu Qir Field). Liquid loading in gas wells occur when the gas flow rate falls below a critical rate due to reservoir depletion where the accompanying liquids cannot be lifted to surface. Such liquid accumulations at the wellbore can cause the gas well to cease production eventually. Severe slug flow (i.e., terrain-dominated slug flow) was studied. Severe slug flow is characterized by extremely long liquid slugs generated at the base of the vertical riser. This phenomenon occurs at low gas and liquid flow rates and for negative pipeline inclinations.
To evaluate future development options and to provide a monitoring tool and realistic results, a multi-disciplinary Petroleum Engineering study was carried out. Unknown reservoir parameters were estimated using the modern production data analysis method, which was also used as a reliable forecasting tool. Steady state multiphase flow simulator and the forecast from production data analysis and numerical reservoir simulator were used to identify any current and future bottlenecks and also optimize the production taking in considerations field's constraints. Transient multiphase flow simulator was used to identify and mitigate transient flow assurance issues i.e. liquid loading in gas wells and slugs in the pipelines. Other scenarios were also studied include: platform start-up and shutdown; production Ramp up due to the introduced platform; and Hydrates no show time due to any shutdown. This helped us to determine the proper design envelope of the new system.
This integrated workflow helped in optimizing the current operating conditions and decreasing field operating cost by increasing the current gas production rate by 6%. We managed to prevent the decline in reserves by more than 10% in the future caused by production system bottlenecks. Choke size for each well was identified honoring existing constrains (reservoir pressure, flow velocity limits, etc.) to increase field gas production. Outlet pressure of a surface network was maximized in order to minimize operational costs of gas processing while maintaining required gas production level. Different scenarios were carried out to come with procedures to prevent and mitigate production instabilities and also decreasing the deferred production.
This work can subsequently propose an integrated field management workflow on addressing various production issues especially in case of limited data availability and how different domains can co-operate to reach the optimum operating scenarios.