Single digit percentage of oil shale recovery leaves a large room for recovery improvement, while aqueous phase injection into shale formation is extremely challenging. Injecting Carbon Dioxide (CO2) into oil shale formations can potentially improve oil recovery. Furthermore, the large surface area in the organic rich shale could permanently store CO2 volume without jeopardizing the formation integrity. This work is a study on evaluating the effectiveness of CO2 enhanced oil shale recovery and shale formation CO2 sequestration capacity. A compositional reservoir simulator is used to model CO2 injection. Petrophysical and fluid properties similar to the Bakken formation are used to set up the base model for simulation. The reservoir model considered petrophysical characteristics of shale formation that affects CO2 flow migration like in-situ stress changes, reservoir heterogeneity, and natural fractures. The results are based on sensitivity analysis of the characteristic shale petrophysical and geomechanical properties. Sensitivity analysis method analyzed all uncertain parameters together using the Design of Experiment and Response Surface Modeling approach to counter the interaction between parameters and influential parameters into generating a proxy model for optimizing oil recovery and CO2 injection into the formation. The above studies are implemented with and without geomechanical module and results are analyzed. The results show that facilitating oil recovery from shale reservoirs by CO2 injection is much higher than primary depletion depending on fracture network connectivity and geomechanical impact. Also, significant CO2 storage capacity if applicable in shale formations, will be a major step towards advances in CO2 sequestration in widely spread shale reservoirs.


Unconventional reservoir is a term to describe a hydrocarbon resource that could not be technically or economically recoverable without stimulation. Reservoir quality of tight formations is categorized as very poor because the ultra-low permeability restricts fluid movement within the reservoir. This leads to single digit oil recovery factors and costly development activities. Commercial development of low permeability, ultra-tight formations by advances in horizontal drilling and multi-stage hydraulic fracturing techniques have led to the production of significant amount of hydrocarbons. A typical production profile of an unconventional tight oil formation is illustrated in Figure 1. The high initial production rates usually attribute to hydraulic fractures, and then oil rate declines steeply once the oil near the fractured zone is produced. Beyond this rate, the flow is mainly controlled by inter-porosity mass transfer between the matrix and fracture network. In literature we studied, enhanced oil recovery (EOR) for unconventional oil reservoirs are limited.

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