Polymer Injection Pilots in Bhagyam Oil Field and Full Field Polymer Development Planning

Abstract

Abstract The paper describes the experience of polymer injection pilots from both subsurface, surveillance and facilities perspective. It also discusses the optimization approach for revising the full field polymer plans. Bhagyam is an onshore oil and gas field in Rajasthan, India. The main producing unit is Fatehgarh multi-storied fluvial sand stone of Paleocene age. The oil is moderately viscous (20 cP to 400 cP) with a vertical viscosity gradient. Reservoir quality is excellent with porosity in the range of 25-30% and permeability of 1 to 10 Darcy. Bhagyam was developed as an edge water injection drive with 153 development wells and put on production in 2012. Polymer flood was recognized early in field life as a viable secondary recovery process. Bhagyam has several characteristics suited for polymer flood like high initial oil saturation, high rock permeability, low reservoir temperature, low connate water and low water salinity. A full field polymer development plan was envisaged in 2013 with a combination of pattern polymer flooding and peripheral polymer injection in water leg. But the field performance under water flood was way below expectations. Along with the fall in crude prices in 2014, the project turned economically unviable. Two polymer injection pilots were done to de risk the polymer flood. A multi-disciplinary team worked to optimize the pilot and full field development plan and improve the modeling of water flood. The two pilots used skid mounted polymer preparation units installed at the well pad and focused on data gathering. An online viscometer and special sampler with chemical stabilizers were used for polymer viscosity measurements. PLT, IFOs and polymer quality parameters like filter ratio, viscosity etc were also regularly measured. A revamped reservoir model was built for the field which helped better characterize the water flood performance. The tests were successful with the wells injecting at or better than expected rates. The offset response was good with WOR drop and oil rate increase in many nearby producers. The conformance of some injectors was successfully managed with selective completions installed. To reduce costs, additional well drilling count was reduced by focusing on high net pay areas, reducing polymer consumption by cutting back on water leg polymer injection, and optimizing polymer viscosity. Pipeline requirements were reduced and polymer injection facilities modified from centralized to skid based. The optimization significantly reduced costs compared to the earlier plan. The economic viability of the project was established at lower oil prices and the modeling efforts along with pilots helped significantly reduce the uncertainty associated with the project.