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Abstract The Sandstone reservoir is on production since 1941. Water injection (WI) started since January 2013 and full fledge injection commenced through injectors in 2013. A maximum injection rate was achieved in 2015. Following start of WI, oil production has increased continuously and peaked in 2017. Both liquid rate and oil rate have declined continuously since 2017 due to lower injection stemming from facility issue. The liquid rate has declined 30% during 2020 to 2022 resulting 41% decline in oil rate as a result of reduction of water injection by 62% due to facility issue. The objective of the paper is to optimize the water injection rate based on historical voidage, current voidage and also future water injection rate based on predicted oil and water production. Besides decline curve analysis (DCA), modern analytical techniques are used to evaluate sweep and recovery and remaining potential in the reservoir. The X-plot technique is used for estimating water influx from production data. Water injection requirement is worked out based on water influx, historical and current voidage. The methodology also shows a workflow to estimate future water production en route to future water injection requirement. Additionally, volumetric sweep is estimated using production data, Y-function and extended X-plot techniques. Field derived fractional flow curve is generated to determine displacement efficiency. Besides recovery estimated from volumetric sweep and displacement efficiency, hydrocarbon pore volume (HCPV) injected vs. post-waterflood cumulative oil production is used to determine ultimate recovery at 99% water cut. When combined with DCA results, the analysis yields incremental water flood recovery potential. The injection requirement to redress the historical voidage is determined assuming 5 years of injection and injection required to address current voidage. Therefore, the current total injection requirement is 50% higher than current injection rate. As water production increases, the maximum injection requirement is 75% higher than current injection rate by 2025 and thereafter progressively reduces as oil and water rates decline. Volumetric sweep estimated by different techniques are in good agreement with each other, lending credence to the methods used. The ultimate water drive and waterflood recovery using sweep and displacement efficiency is 51% and compare favourably with HCPV injected method. In contrast to remaining waterflood recovery of 8% of original oil-in-place (OOIP), the DCA analysis indicates a recovery of 2.7% of OOIP. This underscores the fact that current injection is not adequate and additional injection will be required to improve production. This is in good agreement with the current production performance of the reservoir showing both gross and oil rate decline. This study underscores the importance of fit-for-purpose use of analytical tools to diagnose, analyse and improve waterflood performance.
Aljowder et al. (Mon,) studied this question.