A case study on the effect of reservoir heterogeneities and reservoir model uncertainties on prediction versus actual field behavior and efforts being taken to improve oil recovery in Bhagyam field is presented in this paper.

Bhagyam field is the second largest onshore oil field in RJ-ON-90/1 block, Rajasthan India. The main reservoir has large variations in rock and fluid characteristics. The reservoir porosity range between 20% to 30%, and the maximum in-situ permeability ranges up to 30 Darcies, although the average permeability is 3 Darcy. The in-situ viscosity of crude oil ranges between 20 and 400 cP. The commercial production from the field started in 2012 at an initial rate of 15,000 bopd; the field attained production of ~25,000 bopd, although the envisaged production was 40,000 bopd as per the Field Development Plan (FDP). Based on the drilling and production performance of wells, a significant gap between actual and reservoir model based predictions was observed due to various reservoir uncertainties and complexities. Some of the key factors impacting the overall performance include lower effective permeability, higher oil viscosity, lower transmissibility, and wellbore issues.

Based on the large gap observed between predicted and actual field data, it was estimated that a much denser well spacing was required to achieve recovery estimated in the Field Development Plan. Coupled with a very unfavorable mobility ratio (due to the high in-situ oil viscosity), the water breakthrough was more rapid and widespread early in the production life of the field. Therefore, it was not possible to achieve the peak production rate and recovery in the FDP, even with the drilling of additional wells. The oil production has continued to decline with increase in water cut.

The field is currently producing around 14,000 BOPD with 88% water cut. The reservoir pressure is being maintained through current average water injection of more than 100,000 barrels per day. As of the time of writing, approximately 7% of the initial oil in place has been produced from the field. In order to maximize incremental oil recoveries over waterflood recoveries through improvement in sweep efficiency, various reservoir studies have been carried out to evaluate the feasibility and benefits of implementing a suitable chemical EOR technique in the field.

The case study is a useful reminder of how heterogeneity and reservoir complexity can affect field development plans and how active reservoir management and production optimization can add significant value to field understanding and value.

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