Injection Well Placement Analysis for Optimizing CO2 Enhanced Gas Recovery Coupled With Sequestration in Condensate Reservoirs

Abstract

Depleting hydrocarbon reserves and increasing greenhouse gases present a major challenge to the energy sectors. As a result, emphasis needs to be placed on ensuring optimum depletion of known hydrocarbon reserves and reduction of greenhouse gases. This paper presents the effects of various injection well placements on the efficiency of Enhanced Gas Recovery (EGR) and sequestration, using reservoir simulation, in an attempt to optimize EGR coupled with CO2 sequestration. The compositional simulator CMG-GEM was used to build a reservoir model with a simple 3D geometric shape (cuboid), which was populated with various layers with properties analogous to a real condensate field to improve the accuracy of the flow path modeling. WINPROP was used to create a detailed fluid model. Using the model as discussed above, the injector placement was varied whilst using a fixed injection pressure of 2000 psi at the end of primary recovery for all scenarios. These well placements included a single vertical injector, two vertical injectors and a single horizontal injector. At the end of each injection scenario, the simulation was run for an additional 1000 years to model the movement of the CO2 plume in the reservoir. From the simulations, over 60% of the injected CO2 remained in the reservoir. On average, approximately 20% of the injected CO2 was trapped by hysteresis. These relatively high storage values for this research can be attributed to relatively small volumes of CO2 being injected (on average 4 MtCO2 total over 5 years) into a relatively large reservoir (estimated hydrocarbon pore volume of 622.5 MMCF) at low injection pressures. The various injection scenarios resulted in as high as an additional 6.9% condensate recovery over primary production only. The results of this simple analytical model show that there is the potential to optimize gas and condensate recovery through the use of CO2 injection whilst mitigating a percentage of greenhouse gases. It also provides a base for future well planning models to build upon in order to effectively optimize CO2 EGR and sequestration in condensate fields.

Review on Carbon Capture, Utilization, and Storage for Enhancing Gas Recovery

“…Dispersion rises since the holes occupied by fundamental water lead to smaller pores and convoluted flow routes. Mitigation of carbon dioxide breakthrough at the production well may potentially be achieved by the use of CO 2 injection techniques, using a horizontal-well configuration in the lower sections of the reservoir, while simultaneously conducting methane production in the higher regions. , To guarantee supercritical phase displacement and attain an excellent CH 4 recovery, injecting CO 2 at the beginning of natural gas production has positive effects . CO 2 injection in the latter stages may increase CCS performance, making it more appealing when CO 2 sequestration is discussed. , Overall, the moment of carbon dioxide injection is very important for getting the best gradual recoveries by permissible generated carbon dioxide emphasis at the production well, governed by the CCS projects’ economics…”

A Review of CO2 Storage in View of Safety and Cost-Effectiveness

“…In addition to the above-mentioned geological parameters, engineering parameters also have a significant influence on gas mixing and CO 2 -EGR performance [131,240,241]. CO 2 injection with a horizontal well in the lower parts and CH 4 production in the upper parts of reservoirs could mitigate the breakthrough of CO 2 at the production well [131,242]. CO 2 injection during the early decline phase of natural gas production is beneficial for ensuring the displacement in supercritical phase and achieving a high CH 4 recovery [131].…”