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Collaborating Authors
Results
Abstract Injection of CO2 into subsurface coal seams is a viable technology for reducing the carbon footprint. The primary storage mechanism in coal, gas adsorption, is distinctively different from other subsurface reservoirs, providing secure and long-term storage for carbon; however, CO2 adsorption can reduce coal permeability and injectivity due to matrix swelling. In this work, a reservoir simulation study was performed to assist with the design of a field pilot for injecting CO2 into the deep Mannville coals of Alberta. The proposed field pilot consists of a vertical well for injection of CO2, and a closely spaced offset vertical well for observation (pressure measurement and fluid sampling). Extensive numerical modeling was carried out before the pilot implementation to aid with pilot design, assess injectivity, and optimize pilot operations. Because of the scarcity of reservoir information in the study area, most reservoir attributes were obtained by history-matching the Fenn Big Valley (FBV) micro-pilot (single vertical well) injection data, the closest analog field case performed in the Mannville coal. Accordingly, the reservoir simulation study was conducted in two phases: (1) testing of the numerical model setup using the FBV micro-pilot data and (2) construction of a new pilot area-specific simulation model, corresponding to the new pilot area. During the testing phase, the FBV injection well bottomhole pressure and produced gas compositions were adequately matched. During the new pilot area-specific simulation phase, a full field model (multilayer, two-well) covering a drainage area of 40000 m was constructed to represent the target coal seams and the bounding zones. Because the studied coal reservoir is considered to be geomechanically anisotropic with complex cleat systems, the anisotropic Palmer-Higgs model was integrated into the flow simulation to accurately simulate the stress-dependent permeability changes during CO2 injection. Utilizing geologic information and analog field studies, the new pilot area-specific simulation suggests that the target amount of 1500 tonnes CO2 can be securely stored in the Mannville coal seam at the planned pilot site. To optimize the injection scheme operations, and maximize injectivity, two hypothetical injection scenarios were considered: a constant-rate injection scheme at 5 tonnes per hour and a variable- rate injection scenario at a rate of up to 15 tonnes per hour. Both pre-field simulation scenarios suggest that 1500 tonnes of CO2 can be securely injected into the target coal seam (at 1500 m, with an initial permeability of 1.5 md). However, the time to inject the target amount of CO2 in the variable-rate scenario is significantly less than for the constant-rate scenario. Therefore, a variable injection rate schedule with a progressive increase of 5, 10, and 15 tonnes per hour was suggested for the actual field trial. Additionally, the effect of coal anisotropy on CO2 migration was accounted for in the well-spacing design. The simulation results demonstrate that geomechanical and permeability anisotropy do not substantially affect the CO2 distribution in the coal seam because most of the injected CO2 will be adsorbed onto the coal matrix, with a rate that is mainly controlled by diffusion (not permeability). Analysis of simulation results reveals that the simulated sweep zone at the end of 1500 tonnes CO2 injection ranges from about 42 to 50 m from the injection point. Consequently, an injection/observation well spacing of 44 m was suggested for the new pilot to ensure that the offset well (to injector) can serve as an effective subsurface monitoring well.
- North America > United States (1.00)
- Europe > United Kingdom > North Sea > Central North Sea (0.92)
- North America > Canada > Alberta (0.86)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.48)
- North America > United States > New Mexico > San Juan Basin (0.99)
- North America > United States > Colorado > San Juan Basin (0.99)
- North America > United States > Arizona > San Juan Basin (0.99)
- (5 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract Organic matter (OM) fractions partly control gas transport properties and permeability/diffusivity in the matrix of organic-rich shales. The objectives of this work are therefore to investigate the 1) OM controls on the gas flow mechanisms and matrix permeability/diffusivity and 2) evolution of gas flow mechanisms (i.e., slippage-viscous flow, Knudsen diffusion and surface diffusion) within micro/mesopores as a function of entrained hydrocarbon and OM components. A suite of organic-rich shales differing in OM type/content from the Canadian Duvernay Formation are studied for this purpose. Using the extended-slow-heating (ESH) pyrolysis technique, different hydrocarbon and OM components of the Duvernay shale samples eluted sequentially during pyrolysis including 1) free light oil (S1ESH; <150 ยฐC), 2) fluid-like hydrocarbon residue (S2a; 150-380 ยฐC), and 3) solid bitumen/ residual carbon (S2b; 380-650 ยฐC). A new model for quantifying rate-of-adsorption (ROA) of gas (N2/CO2) was used to evaluate matrix permeability/diffusivity and the extent of surface diffusion in micro/mesopores before and after elution of the aforementioned components during pyrolysis. Scanning electron microscope (SEM) images were used to visualize the evolution of OM with sequential pyrolysis. Based on the SEM observations, the solid bitumen fractions in the analyzed Duvernay samples are non-porous and are comprised of pore-occluding/filling residual carbon. However, the ROA results suggest that these OM fractions contain porosity and well-connected pore throats at the micro- (<2 nm) and mesopore (<5-10 nm) level. Further, the modeling results indicate that the OM fractions not only affect pore size/volume, but also control the flow regimes within the micro/mesopores. During pyrolysis, the contribution of surface diffusion (N2) increases progressively within micropores up to the S2a stage and declines after removal of solid bitumen (as supported by the SEM images), suggesting a strong correlation between surface diffusion and solid bitumen. Within macropores, slippage-viscous flow is the dominant transport mechanism, with lesser contributions from Knudsen and surface diffusion. The OM content/composition and entrained hydrocarbon phases (e.g., lighter vs. heavier components) evolve dynamically during hydrocarbon recovery from unconventional light oil and condensate reservoirs. However, the impact of OM components on fluid transport properties of organic-rich shales, particularly at micro/meso scales, is still a matter of debate. Understanding the evolution of gas transport properties as a function of OM and hydrocarbon components is important for โlong-termโ simulation of primary and enhanced hydrocarbon recovery in tight oil/condensate reservoirs.
- North America > Canada > Alberta (1.00)
- North America > United States > Texas (0.93)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.87)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Quebec > Appalachian Basin > Utica Shale Formation (0.99)
- (10 more...)
Abstract Reducing fracture/well spacing and increasing hydraulic fracture stimulation treatment size are popular strategies for increasing hydrocarbon recovery from multi-fractured horizontal wells (MFHWs). However, these strategies can also increase the chance of fracture interference, which not only can negatively impact the overall production, but also introduce complexities for production data analysis. To analyze the production data from two communicating wells, a semi-analytical model is developed and applied to a field case. The new semi-analytical model uses the dynamic drainage area (DDA) concept and assumes that the reservoir consists of two regions: a primary hydraulic fracture (PHF) and an adjacent enhanced fracture region (EFR) or non-stimulated region (NSR) in the reservoir. Assuming a well pair primarily communicates through PHFs, the equations for two communicating wells are coupled and solved simultaneously to model the fluid transfer between the wells. This method is used within a history matching framework to estimate the degree of communication between the wells by matching the production data. The model is first verified against more rigorous numerical simulation for a range of fracture/reservoir properties. These comparisons demonstrate that there is excellent agreement between the reservoir simulation results and the new semi-analytical model. The semi-analytical model is then employed to history match production data from six MFHWs (drilled from two adjacent well pads) exhibiting different degrees of communication. First, only strong communication between pairs of wells (intra-pair communication) is considered. Then sink/source terms are added to account for intermediate degrees of communication between well pairs (inter-pair communication). Addition of the source/sink terms improves the history-matching quality of the three well pairs, while total material balance of the entire section is honored. A flexible, yet simple, semi-analytical model is developed for the first time that can accurately model the communication between multiple well pairs. This approach can be used by reservoir engineers to analyze the production data from communicating MFHWs.
- North America > United States (0.68)
- North America > Canada > Alberta (0.29)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production data management (1.00)