In this work we evaluate the impact of integration between reservoir and production systems considering scenarios of polymer injection in a heavy-oil reservoir. We used a reservoir model named EPIC001 with characteristics from a Brazilian Sandstone offshore heavy-oil field. A Black-oil fluid model was used, considering heavy viscous oil (13° API). The production system is composed by 4 producers and 3 injectors wells. To integrate reservoir with production system, we use decoupled integration approach using vertical flow performance tables. Additionally, we propose an alternative approach to estimate a revised BHP for the integration. Simulation using the decoupled integration approach yields lower production compared to non-integrated scenarios based on initial conditions. The reduction was 22% for water injection and 41% for polymer injection, at concentration of 2.49 kg/m3. Sensitivity analysis of polymer concentration revealed that 1 kg/m³ was the most favorable concentration for the non-integrated case and 0.5 kg/m3 considering the integration. Revised BHPs approach lead to a production compatible with integrated case with differences reaching 2.46%. The results presented in this paper provide new insights into the importance of considering integration for accurate prediction, particularly in scenarios involving polymer injection in a heavy-oil reservoir. We also show that the best polymer injection concentration can change depending on the modelling approach and the revised BHP approach could be an alternative to integration.
Tag: Heavy oil
MODEL-BASED ANALYSIS TO EVALUATE THE EFFECT OF POLYMER PROPERTIES AND PHYSICAL PHENOMENA ON POLYMER FLOODING OPERATIONS
Polymer flooding, known for enhancing heavy oil displacement, may encounter efficiency-limiting physical phenomena. This work assesses the impact of key factors like viscosity, shear rate, and adsorption in field applications using a model-based approach on the EPIC001 case, a real offshore Brazilian heavy oil reservoir. In simulation results, increasing the displacing fluid viscosity using apparent or zero-shear functions, oil production and economic returns show improvements over waterflooding. The shear rate effect slightly increases oil production and enhances injectivity loss due to shear-thinning in polymer flow. However, modeling it increases computation costs, as it extends simulation run time from minutes to days, making it impractical for intensive processes like production optimization. An analysis of the method’s effectiveness shows that it varies based on the adsorption level considered. At its highest value, even with a higher oil recovery factor, the economic return was lower than using waterflooding. Combining shear rate and adsorption has a minimal impact on field indicators when compared to adsorption alone. This work enhances the comprehension of physical phenomena and non-Newtonian behavior in tertiary polymer flooding on heavy oil reservoirs and its impact on the production forecast. It also highlights important considerations for modeling-based procedures.