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Collaborating Authors
Western Canada Sedimentary Basin
University of Calgary Summary Due to strong nonlinearities in the governing diffusivity equation for flow in porous media, numerically assisted rate-transient analysis (RTA) techniques have been suggested for the analysis of multiphase production data from multifractured horizontal wells (MFHWs). However, these methods are based on some limiting assumptions that cannot be generalized for three-phase flow or when relative permeability is unknown. In this study, a new RTA-assisted history-matching technique is proposed to simultaneously match production data and diagnostic plots during the calibration process. In the proposed method, the objective function is modified to include the derivative of the integral of rate-normalized pressure for the primary phases. As such, in the history-matching process using compositional numerical simulation, the flow regimes are also matched, which can increase the reliability of the calibrated numerical model. This approach is applied to a challenging data set of production data from an MFHW completed in a Canadian shale reservoir hosting a near-critical gas condensate fluid. The results demonstrate that when the modified objective function is used, the history-matching scheme will reject models that cannot reproduce the flow regimes even if the production data are visually matched. Another benefit of this modified history-matching workflow is that, unlike other numerically assisted RTA techniques, it is not limited to any specific conceptual model or reservoir geometry. Further, interactions between parameters are accounted for during the calibration process. Including the derivative terms in the objective function can ensure a better history-matched model with improved forecast quality. However, comparing the convergence rates of the history-matching with the standard and modified objective functions indicates that adding the derivative terms comes with an additional computational cost requiring more iterations and a slower convergence rate. In this study, a modified objective function is introduced for the first time to enhance the numerical history-matching process to ensure the resulting calibrated model can also reproduce the observed transient flow regimes. This approach is easy to implement and is not limited to a specific model geometry or any input-output relationship. Introduction The performance of MFHWs completed in ultralow permeability unconventional reservoirs is a function of various reservoir and fracture properties.
- North America > United States (1.00)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.34)
- Geology > Geological Subdiscipline > Geomechanics (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.49)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (7 more...)
Abstract The post-fracture-pressure-decay (PFPD) technique is a low-cost method allowing for stage-by-stage hydraulic fracture characterization. The physics of the PFPD method are complex, with data affected by both hydraulic fracture and reservoir properties. Available analysis methods in the literature are oversimplified; reservoir or fracture properties are often assumed to be constant along the horizontal well, and therefore changes in the trend of pressure decay data are attributed to hydraulic fracture or to reservoir properties only. Moreover, methods analogous to those applied to the analysis of conventional diagnostic fracture injection tests (DFITs) are often used and ignore critical mechanisms involved in main-stage hydraulic fracture stimulation. A conceptual numerical simulation study was first conducted herein to understand the key physics involved in main-stage hydraulic fracturing. An analytical model was then developed to account for the dynamic behavior of the hydraulic fracture, pressure-dependent leakoff, proppant distribution, multiple fractures, and propped- and unpropped-closure events. The analytical model is cast in the form of a new straight-line analysis (SLA) method that provides stage-by-stage estimates of the ratio of unpropped fracture surface area to total fracture surface area. The SLA method was validated against numerical simulation results. Moreover, to account for the variation of reservoir properties along the horizontal well, the PFPD model is integrated with DFIT-flowback (DFIT-FBA) tests, performed at some points along the lateral, to obtain a reliable stage-by-stage hydraulic fracture and reservoir characterization approach. The practical application of the proposed integrated approach was demonstrated using PFPD and DFIT-FBA data from a horizontal well completed in 22 stages in the Montney Formation. The numerical simulation study demonstrated that the use of proppant and injection into multiple clusters (creating multiple fractures) results in multiple-closure events. The closure process may start early after the pump-in period at a pressure significantly higher than the minimum in-situ stress. Employing DFIT-based analytical models, which ignore the presence of proppant, causes significant errors in hydraulic fracture and reservoir property estimation. The PFPD field data examined herein exhibited a similar pressure trend to the numerical simulation cases. The ratio of unpropped fracture surface area to total fracture surface area was determined stage-by-stage using the PFPD SLA method, constrained by DFIT-FBA data. Engineers can use this information to optimize hydraulic fracture stimulation design in real-time, optimize well spacing, and forecast production. The cost and time advantages of this diagnostic method make this approach very attractive.
- North America > Canada > Alberta (0.48)
- North America > United States > Texas (0.46)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
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)
Fault Identification for the Purposes of Evaluating the Risk of Induced Seismicity: A Novel Application of the Flowback DFIT (DFIT-FBA)
Zeinabady, Danial (University of Calgary) | Clarkson, Christopher R. (University of Calgary) | Razzaghi, Samaneh (Ovintiv Inc.) | Haqparast, Sadjad (University of Calgary) | Benson, Abdul-Latif L. (University of Calgary) | Azad, Mohammad (University of Calgary)
Abstract The existence of faults, pre-existing hydraulic fractures, and depleted areas can have negative impacts on the development of unconventional reservoirs using multi-fractured horizontal wells (MFHWs). For example, the triggering of fault slippage through hydraulic fracturing can create the environmental hazard known as induced seismicity (earthquakes caused by hydraulic fracturing). A premium has therefore been placed on the development of technologies that can be used to identify the locations of fault systems (particularly if they are subseismic), as well as pre-existing hydraulic fractures and depleted areas that can similarly negatively impact reservoir exploitation. The objective of this study is to develop a diagnostic tool to identify these conditions using DFIT-FBA. DFIT-FBA is a modified diagnostic fracture injection test (DFIT) whereby a sequence of injection and flowback steps are performed to estimate minimum in-situ stress, fracture surface area, reservoir pressure, and permeability in shale and tight reservoirs. The time- and cost-efficiency of the DFIT-FBA method provides an opportunity to conduct multiple field tests at a single point, or along the lateral section of a horizontal well, without significantly delaying the completion program. The proposed diagnostic tool uses an analytical model which considers critical processes and mechanisms occurring during a DFIT-FBA test, including wellbore storage, leakoff rate, and fracture stiffness development. The results of analytical modeling demonstrate that faults, pre-existing hydraulic fractures, and depleted areas of the reservoir can be identified either by implementing multiple cycles of the DFIT-FBA test at a single point, or by applying multiple DFIT-FBA tests at different points along the lateral section of a horizontal well or at different wells. The analytical model is first verified using a fully-coupled hydraulic fracture, reservoir, and wellbore simulator, and flowing pressure responses in the presence of different reservoir heterogeneities are then illustrated. Practical application of the proposed method is demonstrated using DFIT-FBA field examples performed in a tight reservoir. Analysis of the field examples results in the conclusion that a fault occurs near the toe of the horizontal lateral. This finding was confirmed by other field information and provides the opportunity to modify the main-stage hydraulic fracturing design to avoid induced seismicity events. This study proposes a novel, fast, and low-cost approach for identifying faults, pre-existing hydraulic fractures, and depleted areas using the DFIT-FBA test. The recommended approach can help engineers to characterize the reservoir quality along a horizontal well, as well as identify features/conditions that could negatively influence reservoir development, such as faults (and the possibility of creating induced seismicity), pre-existing hydraulic fractures, and reservoir depletion.
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- North America > United States > Texas (0.69)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.88)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.35)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (9 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract Due to strong non-linearities in the diffusivity equation, numerically-assisted rate-transient analysis (RTA) techniques have been suggested for analysis of multi-phase production data from multi-fractured horizontal wells (MFHWs). However, these methods are based on some limiting assumptions that cannot be generalized for three-phase flow or when relative permeability is unknown. In this study, a new RTA-assisted history-matching technique is proposed to simultaneously match production data and diagnostic plots during the calibration process. In the proposed method, the objective function is modified to include the derivative of the integral of rate-normalized pressure for the primary phases. As such, in the history-matching process using compositional numerical simulation, the flow regimes are also matched, which can increase the reliability of the calibrated numerical model. This approach is applied to a challenging dataset: production data from a MFHW completed in a Canadian shale reservoir hosting a near-critical gas condensate fluid. The calibrated model is then applied to co-optimize CO2 storage and oil production using a cyclic gas injection scheme. The results demonstrate that when the modified objective function is used, the history-matching scheme will reject models that cannot reproduce the flow regimes even if the production data are visually matched. Another benefit of this modified history-matching workflow is that, unlike other numerically-assisted RTA techniques, it is not limited to any specific conceptual model or reservoir geometry. Further, interactions between parameters are accounted for during the calibration process. Co-optimization using the calibrated model leads to an optimized Huff-n-Puff (HnP) design that can produce 40% additional (incremental) oil, while around 17% of the injected CO2 is stored during the cyclic CO2 injection process. In this study, a modified objective function is introduced for the first time to enhance the numerical history-matching process to ensure the resulting calibrated model can also reproduce the observed transient flow regimes. This approach is easy to implement and is not limited to a specific model geometry or any input-output relationship.
- North America > Canada > Alberta (0.94)
- Europe (0.93)
- North America > United States > Texas (0.69)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.85)
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > New Mexico > Permian Basin > Wolfcamp Formation (0.99)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (4 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Generating a labeled data set to train machine learning algorithms for lithologic classification of drill cuttings
Becerra, Daniela (University of Calgary) | Pires de Lima, Rafael (Geological Survey of Brazil) | Galvis-Portilla, Henry (University of Calgary) | Clarkson, Christopher R. (University of Calgary)
Abstract Despite significant developments in the past few years in the application of machine learning algorithms for the lithologic classification of rock samples, publicly available labeled data sets are very scarce. We open source a fully labeled data set containing more than 16,000 scanning electron microscopy (SEM) images of drill cutting samples—mounted on thin sections—from a low-permeability reservoir in western Canada. We develop a simplified image processing workflow to segment and isolate the rock chips into individual SEM images, which in turn are used to identify, classify, and quantify rock types based on textural characteristics. In addition, using this data set, we explore the use of convolutional neural networks (CNNs) as a baseline tool for acceleration and automatization of rock-type classification. Without significant modifications to popular CNN models, we obtain an accuracy of approximately 90% for the test set. Results demonstrate the potential of CNN as a fast approach for lithologic classification in low-permeability siltstone reservoirs. In addition to making the data set publicly available, we believe our workflow to segment and isolate drill cutting samples in individual images of rock chips will facilitate future research of drill cuttings properties (e.g., lithology, porosity, and particle size) using machine learning algorithms.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.48)
- Oceania > Australia > South Australia > Cooper Basin (0.99)
- Oceania > Australia > Queensland > Cooper Basin (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- (30 more...)
Abstract In this study, a rigorous coupled flow-geomechanics semianalytical approach is presented to analyze flowback data and forecast production performance in multifractured horizontal wells. Hydraulic fracture characterization using post-stimulation flowback data is of critical importance to the quantification of early-time well performance and for efficient development of unconventional reservoirs. However, conventional reservoir (flow) simulators can be challenging to setup for flowback analysis. Further, flow simulators usually approximate stress-dependence of fracture and reservoir parameters, the former of which is particularly important to capture for both the flowback and forward modeling problem, using porosity and transmissibility multipliers. However, in order to apply this approach, transmissibility multipliers must be estimated from laboratory experiments, or used as a history-match parameter, possibly resulting in large errors in performance predictions. The goal of this study is to provide a rigorous, coupled semianalytical workflow for hydraulic fracture characterization from flowback data, that utilizes a 3D coupled flow-geomechanics semi-analytical model as its basis. A 3D semi-analytical coupled flow-geomechanical model is developed to capture the complexities of stress-dependence in order to forecast production performance from multifractured horizontal wells. The model can also be used to derive hydraulic fracture properties from early post-stimulation flowback data. An enhanced fracture region (EFR) conceptual model is applied for approximating complex fracture geometries. The fully-analytical fluid flow and semi-analytical geomechanical models are coupled for both the fracture and reservoir regions. The proposed approach requires simultaneous solutions of the fluid flow model (reservoir simulation) and geomechanics model, the latter capturing the stress and deformation behavior of the fracture and reservoir. Coupling between fluid flow and geomechanics is achieved by updating the pressure and stress-dependent properties through a porosity function (coupling parameter) in the flow model for each region (hydraulic fracture and reservoir) at each iteration step. The coupled flow-geomechanics EFR model is validated with fully-numerical simulation. Fracture properties are estimated by using the proposed inverse model for analyzing flowback (water) data. The new flowback analysis approach is applied to synthetic field data and the results compared with the inputs of the synthetic model. With this model, combined with the semi-analytical coupled flow-geomechanics workflow, a more confident estimate of hydraulic fracture properties is obtained.
- North America > United States > Texas (0.46)
- North America > Canada > Alberta (0.46)
- North America > Canada > British Columbia (0.28)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Greater Peace River High Basin > Upper Montney Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
Abstract Stress-dependence of reservoir matrix and fractures can strongly affect the performance of multifractured horizontal wells (MFHWs) completed in unconventional hydrocarbon reservoirs. In order to model fluid flow in unconventional reservoirs exhibiting this stress-dependence, most traditional reservoir flow simulators, and many simulators described in published work, use conventional reservoir fluid flow model formulations. These formulations typically neglect the influence of the rate of change of volumetric strain of the reservoir matrix and fractures, even though reservoir stress and pressure change significantly during the course of production. As a result, the effect of matrix and fracture deformation on production is neglected, which can lead to errors in predicting production performance in most stress-sensitive reservoirs. To address this problem, some studies have proposed the use of porosity and transmissibility multipliers to model stress-sensitive reservoirs. However, in order to apply this approach, multipliers must be estimated from laboratory experiments, or used as a history-match parameter, possibly resulting in large errors in well performance predictions. Alternatively, fully-coupled, fully numerical geomechanical simulation can be performed, but these methods are computationally costly, and models are difficult to setup. This paper presents a new fully-coupled, two-way analytical modeling approach that can be used to simulate fluid flow in stress-sensitive unconventional reservoirs produced through MFHWs. The model couples poroelastic geomechanics theory with fluid flow formulations. The two-way coupled fluid flow-geomechanical analytical model is applied simultaneously to both the matrix and fracture regions. In the proposed algorithm, a porosity-compressibility coupling parameter for the two physical models is setup to update the stress- and pressure-dependent fracture/matrix properties iteratively, which are later used as input data for the fracture-matrix reservoir fluid flow model at each iteration step. The analytical approach developed for the fully-coupled, two-way analytical model, using the enhanced fracture region conceptual model, is validated by comparing the results with numerical simulation. Predictions using the fully-coupled enhanced fracture region model are then compared with the same enhanced fracture region model but with the conventional pressure-dependent modeling approach implemented. A sensitivity study performed by comparing the new fully-coupled model predictions with and without geomechanics effects accounted for reveals that, without geomechanics effects, production performance in stress-sensitive reservoirs might be overestimated. The study also demonstrates that use of the conventional stress-dependent modeling approach may cause production performance to be underestimated. Therefore, the proposed fully-coupled, two-way analytical model can be useful for practical engineering purposes.
- North America > Canada > Alberta (0.46)
- North America > United States > Texas (0.46)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.48)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Greater Peace River High Basin > Upper Montney Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- (2 more...)
Abstract Hydraulic fracture/reservoir properties and fluid-in-place can be quantified by using rate-transient analysis (RTA) techniques applied to flow rates/pressures gathered from multi-fractured horizontal wells (MFHWs) completed in unconventional reservoirs. These methods are commonly developed for the analysis of production data from single wells without considering communication with nearby wells. However, in practice, wells drilled from the same pad can be in strong hydraulic communication with each other. This study aims to develop the theoretical basis for analyzing production data from communicating MFHWs completed in single-phase shale gas reservoirs. A simple and practical semi-analytical method is developed to quantify the communication between wells drilled from the same pad by analyzing online production data from the individual wells. This method is based on the communicating tanks model and employs the concepts of macroscopic material balance and the succession of pseudo-steady states. A set of nonlinear ordinary differential equations (ODEs) are generated and solved simultaneously using the efficient Adams-Bashforth-Moulton algorithm. The accuracy of the solutions is verified against robust numerical simulation. In the first example provided, a MFHW well-pair is presented where the wells are communicating through primary hydraulic fractures with different communication strengths. In the subsequent examples, the method is extended to consider production data from a three-well and a six-well pad with wine-rack-style completions. The developed model is flexible enough to account for asynchronous wells that are producing from distinct reservoir blocks with different fracture/rock properties. For all the studied cases, the semi-analytical method closely reproduces the results of fully numerical simulation. The results demonstrate that, in some cases, when new wells start to produce, the production rates of existing wells can drop significantly. The amount of productivity loss is a direct function of the communication strengths between the wells. The new method can accurately quantify the communication strength between wells through transmissibility multipliers between the hydraulic fractures that are adjusted to match individual well production data. In this study, a new simple and efficient semi-analytical method is presented that can be used to analyze online production data from multiple wells drilled from a pad simultaneously with minimal computation time. The main advantage of the developed method is its scalability, where additional wells can be added to the system very easily.
- North America > Canada > Alberta (0.68)
- North America > United States > Texas (0.46)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.61)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production data management (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 °C), 2) fluid-like hydrocarbon residue (S2a; 150-380 °C), and 3) solid bitumen/ residual carbon (S2b; 380-650 °C). 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 ‘long-term’ 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...)