History Matching Naturally Fractured Carbonate Gas Condensate Reservoir Performance for CO2 Storage

Abstract The objective of this research is to characterize the reservoir to develop a more realistic model that can be used to evaluate the feasibility of CO2 storage. A Black oil dual porosity/dual permeability simulation model was built for two naturally fractured carbonate reservoirs, A-B and C-D, and history matched with 20 years of production-pressure history to support key reservoir understanding, and compartmentalization for future reservoir management, including CO2 storage (CCS) decisions. The history matching (HM) considered different reservoir properties and features such as thrust complex, vertical and areal transmissibilities, and aquifer properties. After HM, a sector model was used to assess CO2 storage. CO2 was injected for 5 years and monitored for 25 years. The assessment did not consider CO2 solubility in the formation brine, molecular diffusion/physical dispersion, or mineralization. While modeling thrust complexes and HM, a significant pressure rebound was observed in the central part of the field (in shut-in wells), and thickening of the A and C zones due to structural causes was matched as a thrust complex. The A and C zones have a higher matrix porosity and net pay, which accounted for significant gas in-place, some of which lie in the north of the field, which has not been developed yet. While history matching, horizontal transmissibility multipliers were placed in every 10 grid cells, subdividing the affected volume into km-sized ‘thrust block’ units. Gas in these thrust block units was weakly connected to the B zone via a reduced vertical permeability, which was tuned to match the observed pressure rebound and reservoir performance. Additionally, 1 megaton of CO2 was stored in the western region of the field after depleting the reservoir until wellhead pressure reached 150 psi. Gas and condensate recoveries reached ∼80% and ∼50%, respectively, at the end of the primary production phase. Based on CO2 inventory analysis, CO2 solubilization in condensate/oil was minimal (∼2%). Approximately 29% of the total CO2 injected was stored through capillary/residual trapped and the remaining ∼69% CO2 was structurally trapped. Transient naturally fractured reservoirs are very heterogeneous and complex to develop and store CO2. The concept of thrust complexes and permeability barriers within reservoirs can provide a more realistic HM and performance forecast. This study will assist in understanding reservoir foundation in terms of facies variation, intra-field/intra-reservoir connectivity, or transmissibility baffling to HM the field data and then predict the future performance of CO2 storage.