This work presents the main findings of a research project conducted to integrate well logs and advanced laboratory-based data from Bakken core samples into geocellular and simulation models at multiple scales. The objective of this effort was to improve the accuracy of modeling approaches for predicting potential incremental oil production through carbon dioxide (CO2)-based enhanced oil recovery (EOR) in unconventional tight oil reservoirs and to evaluate the ability of organic-rich shales to store CO2 and, possibly, produce incremental oil.
Unique data sets applied to the modeling included results from advanced scanning electron microscopy (SEM) techniques, computerized tomography (CT) scanning, and CO2 permeation and oil mobility experiments. Plug- and core-scale models were used to simulate and history-match the CO2 permeation and oil mobilization experiments. Larger-scale models, such as near-wellbore and drill spacing unit (DSU)-scale models, were used to simulate and predict CO2 behavior under conditions that are more representative of what might be expected in the field. Reservoir pressure, temperature, and injectivity data from a CO2 injection field test in a Bakken well were also applied to the reservoir-scale modeling.
The plug- and core-scale modeling efforts were able to reasonably reproduce the oil recovery results observed in the lab. Results from models with and without CH4adsorption settings suggest that integration of CH4 adsorption and core CT data allowed simulations to better reproduce the experimental results. However, perfect matches were never achieved, and a lack of data on capillary pressure effects and relative permeability were identified as being potential reasons for the imperfect matches. The larger-scale simulations included modeling of different huff ‘n’ puff scenarios with both single-fracture stage model and DSU models. The single-fracture stage model showed incremental recovery factors ranging from 0.6% to 5.4%. This number could be increased by conducting more huff ‘n’ puff cycles over the lifespan of an operating well and/or by optimizing the operational parameters and well placement. At the DSU scale, the simulations indicated that alternating wells with the huff ‘n’ puff showed the best performance in terms of EOR. In the best-case scenario, the alternating huff ‘n’ puff scheme was predicted to more than double the oil recovery factor of a well.
These results will ultimately be used to better estimate the EOR potential and associated CO2 storage resource of unconventional tight oil formations. While a 5% improvement in ultimate recovery may be perceived as a relatively small increase over primary production, the implications for an incremental recovery of 5% for production throughout the Bakken play is enormous. With estimated Bakken OOIP (original oil in place) estimates ranging from 300 billion to 900 billion barrels, realization of even this small improvement would yield billions of incremental barrels of oil and extend the lifetime of the play by decades.