Streamline Based Polymerflood Injection Optimization: Experiences in the Mangala Field, India

Abstract

Mangala field (India) is one of the largest polymer flooding fields in the world with hundreds of wells and waxy crude oil. Field-scale optimization of polymer injection is challenging due to the geologic heterogeneity and operational constraints. This paper demonstrates an application of streamline-based injection optimization for the Mangala field. The paper will cover the mathematical foundation, optimization studies, and considerations for field implementation. Our field application consists of five key stages: i) Problem framing. This includes defining optimization objectives, tuning parameters and constraints such as optimization start/end times, schedule update intervals, field rate targets, and injection/production limits for each well. ii) Rate optimization by streamline method. The optimizer iteratively reallocates the well rates, diverting the injected fluid to high efficiency injector-producer pairs located in upswept oil regions. iii) Optimal schedule interpretation. The rate change, flow pattern alteration and injection efficiency improvement are systematically examined, providing decision makers physical explanations of the suggested rate changes. iv) Selection of key injectors for field implementation. To avoid the risk of large-scale field implementation, limited number of injectors contributing the most to the oil production increase or water production decrease are selected for initial deployment. v) Potential field implementation and validation of the proposed plan based on field observations. Data from offset producers surrounding the rate-reallocated injectors can help evaluate oil production improvement or alleviated decline. The optimized rate schedule is first compared with the current schedule in the field, honoring the field total liquid injection/production rates. The optimized case redistributes the rate allocation among high efficiency injectors within predefined bottom hole pressure and rate constraints. The cumulative oil production increase for the short-term optimization period, 11 months, is 0.66 MMbbl. The efficiency plots show efficient utilization of injected fluid after optimization and the bubble plots and streamline maps indicate that the optimizer alters the flow pattern for a better sweep of the remaining oil. Based on the full field optimization, 20 key injectors are selected for field implementation. Numerical simulation shows that 75% of total oil gain can be achieved from optimization of the key injectors. For field validation, offset producers are expected to show an arrest in the oil decline rate due to improved pressure support and, also reduced water cut increase after field implementation.