In this paper, we compare 4D seismic interpretations of CO 2 plume evolution with fluid-flow numerical simulation results for Cranfield, Mississippi. Historic pressure trends, oil and gas production rates, and current CO 2-EOR production data from the field were history matched, and a tuned model was used for predictive simulations. For CO 2-EOR operations, numerical simulation results of the CO 2 plume distribution and CO 2 first arrival (breakthrough) times in production wells were compared to the available field data. Three interpretations of 4D seismic data show discrepancies on the edges of the seismic survey, and along the sealing fault, where numerical simulations show high CO 2 saturations. In areas between these two limits, the match between simulation and 4D seismic interpretation improves. In addition, for most of the production wells, comparison of the breakthrough time of CO 2 showed a reasonable match. The tuned model was then used to predict reservoir response and storage capacity in different field development scenarios under CO 2 injection. We compared hypothetical scenarios where the operator transitions from CO 2-EOR to CO 2 injection without oil production (CO 2-EORT) when oil production is $ Abbreviations used in this paper: EOR (enhanced oil recovery), EORT (enhanced oil recovery transition), VRR (voidage replacement ratio), CCS (carbon dioxide capture and storage).

No abstract

During reservoir depletion, effective stress is increased and permeability is reduced, while the organic- rich matrix might experience a shrinkage process that will boost the permeability. The main objective was to develop a mathematical simulator coupling gas flow process, geomechanics effects, and matrix shrinkage in order to evaluate their influences on reservoir permeability and production performance. The mesh was divided into three different continuums: organic matter, inorganic matter, and natural fractures. Matrix shrinkage was only considered for organic matter because of gas desorption, and the stress- dependent permeability was considered for both inorganic matter and natural fractures. The flow and stress-equilibrium equations were solved by the fixed-stress sequential method, where the flow equations are solved first, followed by the mechanics equations. The displacements are solved for each grid node by finite element method, and the pressure is solved by the integral finite difference method. Different stress- dependent correlations are chosen to separately apply to the three porous media. Based on those correlations, the porosity and permeability are updated at end of each time step. A synthetic reservoir model was built, where the permeability change and the accumulative gas production is calculated at each time step. The results of permeability change and gas production rate are compared for three different cases: the coupled flow and geomechanics model without permeability change, the coupled model considering stress-dependent permeability, the coupled model considering both matrix shrinkage and permeability change. Additionally, the sensitivity analyses were investigated for total organic carbon (TOC), Young's modulus, matrix permeability, and bottom hole pressure. Results show that the stress-dependent permeability plays a large influence on the gas production performance, because permeability could be significantly reduced with the decrease of reservoir pressure. The matrix shrinkage on organic matter could provide an obvious rebound on accumulative production at the late producing stage, because the permeability is boosted by that media shrinkage at the late producing stage. That explains why permeability largely decreases at early stage and then gradually reduces in experimental data. However, the permeability and production loss are highly depended on the selected correlation, its coefficients, reservoir initial condition, and rock properties. Organic matter is the critical controller on matrix shrinkage: the higher the TOC, the larger the increase of permeability. Nevertheless, their overall impacts on production is quite limited. Young's modulus does not make obvious differences on the accumulative gas based on the numerical results. The large matrix permeability and higher bottom hole pressure can reduce the production loss caused by the effect of stress-dependent permeability. Overall, the triple-porosity coupled simulator can quantitatively interpret the impacts of matrix shrinkage and geomechanics effect on permeability and gas production performance for organic-rich shale reservoirs. This provides more realistic production performance evaluation and economic assessment when the stress-dependent permeability needs to be considered.

Shale reservoirs are characterized by ultra-low permeability, multiple porosity types, and complex fluid storage and flow mechanisms. Consequentially the feasibility of performing simulations using conventional Dual Porosity Models based on Darcy flow has been frequently challenged. Additionally, tracking of water in shale continues to be controversial and mysterious. In organic-rich shale, kerogen is generally dispersed in the inorganic matter. Kerogen is different from any other shale constituents because it tends to be hydrocarbon-wet, abundant in nanopores, fairly porous and capable of adsorbing gas. However, the inorganic matter is usually water wet with low porosity such that capillary pressure becomes the dominant driving mechanism for water flow, especially during hydraulic fracturing operations. This work presents a technique of subdividing shale matrices and capturing different mechanisms including Darcy flow, gas diffusion and desorption, and capillary pressure. The extension of this technique forms a solid and comprehensive basis for a specially-designed simulator for fractured shale reservoirs at the micro-scale.Through the use of this unique simulator, this paper presents a micro-scale two-phase flow model which covers three continua (organic matter, inorganic matter and natural fractures) and considers the complex dynamics in shale. In the model, TOC is an indispensable parameter to characterize the kerogen in the shale. A unique tool for general multiple porosity systems is used so that several porosity systems can be tied to each other through arbitrary connections. The new model allows us to better understand the complex flow mechanisms and to observe the water transfer behavior between shale matrices and fractures under a microscopic view. Sensitivity analysis studies on the contributions of different flow mechanisms, kerogen properties, water saturation and capillary pressure are also presented. Normalized Cumulative Gas Production, % Normalized Cumulative Gas Production, % Dimensionless Time Case 1-Sw = 0.21 Case 2-Sw = 0.30 Case 3-Sw = 0.40 Case 4-Sw = 0.50 Case 5-Sw =0.60