Numerical Simulation of the Impact of a CO2 Flood Pattern Size on Oil Recovery and Carbon Storage

Abstract

Climate change legislation will not be able to incentivize energy stakeholders nor environmentalist to adopt carbon dioxide sequestration in the short term because of the cost associated with the technology. However, CO2 Enhanced Oil Recovery (CO2-EOR) has the potential to provide a win-win situation. One of the areas that can consider the implementation of this process are heavy oil reservoirs. The global heavy oil estimate is very large. For some countries it can help sustain their daily production simply by understanding reservoir behavior when CO2 is injected into the reservoirs. In recent times, other potential energy issues such as depleting resources and greenhouse gas emissions are playing a bigger role in defining what needs to be contemplated by many nations to obtain energy sustainability. This paper seeks to utilize numerical simulation using a commercial software to evaluate pattern size as a strategy for improving recovery in a heavy oil reservoir on the south east peninsula of Trinidad and Tobago (T&T). Some of these heavy oils can be recovered using conventional oil production followed by currently used enhanced oil recovery techniques. We focus our research on a injecting CO2 into a reservoir labelled field X with analogous data was used from fields in south-west Trinidad. Initially, a homogenous reservoir model was built using the compositional fluid model GMG-GEM and placed on primary production. These models were populated with vertical production and injection wells. Sensitivity analysis was then performed on three development scenarios: 160, 40, and 10 acre five-spots. We then developed a heterogeneous model using geostatistically-generated permeability. Based on the results shown, the 160 acre well spacing would be the most economic option; having a positive NPV and Cumulative Profit after taxes. Although the production was the lowest when compared to the other two patterns, coupled with the low CAPEX, the 160-acre spacing over the 55-year period would be best suited if we consider primary recovery only. While pipelines were found to be the better option for transport for the total 10-year period, the results reveal that trucking was the more attractive initial option; because of its low capital cost and flow-rates of CO2. Trucking initially is a more economic option for shorter injection periods and CO2 flow-rates when compared to pipelines however in the longer term, pipeline would be the better option. The CO2 utilisation rate ranges from 2-16MSCF/bbl over the 10 year injection period. In terms of CO2 storage, although the higher the injection volume, the greater the amount of CO2 stored for the scenarios that we have studied, the most economic case with storage would be the 160 acre spacing injecting a total of 40MSCF/D. However, if at any time there can be economic benefits derived from CO2 storage activities, the economics would drive the higher injection rates. From a storage point of view it is important to choose the right well spacing for not only oil production but for storage projects utilising depleted oil reservoirs. The results showed that on average the heterogeneous cases stored approximately 3% more CO2. For larger projects therefore, will have an impact on storage volumes. Once the reservoir remains unaffected by any breach, the CO2 will remain trapped mainly in the supercritical phase for at least 1000 years.