Abstract
Less than 10% of oil is usually recovered from liquid-rich shales and this leaves much room for improvement, while water injection into shale formation is virtually impossible because of the extremely low permeability of the formation matrix. Injecting carbon dioxide (CO2) into oil shale formations can potentially improve oil recovery. Furthermore, the large surface area in organic-rich shale could permanently store CO2 without jeopardizing the formation integrity. This work is a mechanism study of evaluating the effectiveness of CO2-enhanced oil shale recovery and shale formation CO2 sequestration capacity using numerical simulation. Petrophysical and fluid properties similar to the Bakken Formation are used to set up the base model for simulation. Result shows that the CO2 injection could increase the oil recovery factor from 7.4% to 53%. In addition, petrophysical characteristics such as in situ stress changes and presence of a natural fracture network in the shale formation are proven to have impacts on subsurface CO2 flow. A response surface modeling approach was applied to investigate the interaction between parameters and generate a proxy model for optimizing oil recovery and CO2 injectivity.
Highlights
An unconventional reservoir is a hydrocarbon resource that could not be economically recovered without stimulation because of its extreme low permeability
The simulation results focus on emphasizing the effect of shale formation properties on oil recovery and the amount of hydrocarbon pore volume of CO2 injected into the formation
We enabled a Computer Modeling Group (CMG) workflow to use D-optimal design to implement response surface modeling, and the Response surface modeling (RSM) polynomial fit will be of higher order, i.e., linear ? quadratic ? interaction parameters terms are used to generate a proxy model to validate the simulation results
Summary
An unconventional reservoir is a hydrocarbon resource that could not be economically recovered without stimulation because of its extreme low permeability. For tight formations, the injected CO2 flows through hydraulic fractures first and migrates into the rock matrix to swell and displace in-depth oil. To focus on the flow mechanisms of CO2 inside the reservoir, a zone of study (ZoS) was created with one injector and one producer Both wells were horizontal wells within the 12.2 m of pay zone and had a lateral length of 122 m each, located in the middle of the pay zone. To accurately simulate flow in a tight formation with ultralow permeability, a complex fracture network is a crucial part of model. Hydraulic fractures and natural fractures were explicitly created for simulation
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