Application of Streamline-Based WAG Injection Rate Management to Improve Oil Recovery of GLSAU CO2 Flood

Abstract

Abstract The Goldsmith-Landreth San Andres Unit (GLSAU) in the Permian Basin has been under waterflood since 1963, and CO2 WAG flood since 2009. In January 2020, the asset team initiated a flood management workflow using a numerical Streamline Surveillance (SLSV) model approach. Starting in March 2020, because of the oil price collapse due to the pandemic, only produced CO2 was reinjected (harvest operation). Reduced availability of CO2 led to the field-wide voidage replacement ratio (VRR) declining and injectors unable to maintain their pre-harvesting CO2 rates. The approach described in this work outlines how SLSV was used to prioritize CO2 usage in the water-alternating-gas (WAG) scheduling process and to manage water and CO2 injection rate targets to improve the effectiveness of CO2 and minimize oil decline despite the reduction in VRR. Before using SLSV, injection targets were calculated assuming fixed geometric (FG) defined injection patterns and a per pattern processing rate of 10% to 15% HCPV/Yr. The WAG scheduling was then derived from the total injection volume by using a predetermined number of days of water and CO2 injection. In this work, we describe a novel WAG management approach by including injector efficiencies (offset oil produced per volume of fluid injected) computed from an SLSV model able to quantify injector-producer relationships. Fifty-three injectors were included in the Area of Interest (AOI) as candidates for new rate targets. The estimated incremental tertiary oil recovery on January 2020 was 3.9% at a CO2 maturity of 53.3%, slightly above the target defined by the field prototype curve. After applying SLSV as of this writing, incremental tertiary oil recovery is 4.9% at a CO2 maturity of 58.5%. Using the SLSV model, injection rates were increased or decreased depending on the efficiency of each injector-producer pair and additionally constrained by surface facility limits, the availability of CO2 volume to inject, and individual well injectivities. The injection rate target calculations were repeated in March and August of 2020, in January and August of 2021, and in January and June of 2022 using the latest measured well responses as a starting point. Due to the limited volume of CO2 available for re-injection with the start of harvest operation, all injectors that were scheduled to be switched to CO2 cycle (based on the water injection time and designed WAG ratios) were prioritized using injector efficiencies calculated by the SLSV model. The higher an injector efficiency, the higher the probability that a well would be switched to a CO2 cycle. Incremental oil recovery has outperformed the field's prototype for the given CO2 maturity using the SLSV approach. Across the 53 sets of injector rate targets, some injectors had rate increases up to 25%, while other injectors had rate decreases of 25%. During this same period of incremental oil response, overall CO2 injection volumes were reduced from 40.5 MMscf/d to 11.6 MMscf/d (a 71% decrease), water injection volumes were reduced from 38,400 stb/d to 26,400 stb/d (a 31% decrease), and total produced voidage rates dropped from 60,000 rb/d to 33,000 rb/d (a 45% decrease). GLSAU went from an established VRR > 1 (~1.09) before March 2020 to a constant VRR of 0.98 after March 2020 due to CO2 harvesting, yet oil recovery improved.