An Integrated Workflow for Reservoir Modeling and Flow Simulation of the Nikanassin Tight Gas Reservoir in the Western Canada Sedimentary Basin

2011

All Days

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A workflow is presented for modeling actual hydraulic fracturing jobs in tight gas formations of the Western Canada Sedimentary Basin (WCSB). Matching of hydraulic fracture length and resulting gas production from past jobs provides a learning curve that allows design optimization of future fracturing jobs.Key parameters needed for modeling the design of hydraulic fracturing jobs in these types of formations are discussed and include properties such as porosity (matrix, natural fracture and isolated or non-connected), permeability (matrix and natural fracture), water saturation (matrix and natural fracture), shear velocities (even when direct measurements are not available), Poissons ratio, shear modulus, Young modulus, Biot constant, overburden, pore pressure, and net stress. The critical evaluation of these properties provides a valid representation of the tight gas formation and what the natural gas production outcome from the hydraulic fracturing job might be. Important recommendations to achieve a correct integration of logs, well testing, production decline analysis, and 3D modeling of the hydraulic fracturing job are also presented; as wells as an understanding of the differences that can arise from each source of information. The paper incorporates petrophysical and new linear-dominated well testing and production decline analysis methods using triple porosity models for matching petrographic work and production decline; and for quantifying rock properties such as natural fractures and slot porosity, intergranular porosity and isolated non-effective porosity.It is concluded that even though each tight gas reservoir is unique and as such, should be considered as a research project by itself, the workflow presented in this study could prove to be of value in other regions of the world where tight gas formations are present.

Section: Triple Porosity Rocksmentioning

confidence: 99%

Section: Petrophysical Triple Porosity Modelmentioning

confidence: 99%

Hydraulic Fracturing of Naturally Fractured Tight Gas Formations

Leguizamon

2011

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“…The total porosity of the composite system in the above equations is calculated from well logs and is represented by φ. The vug porosity ratio (v nc ), a concept introduced by Lucia (1983), was used initially for evaluation of carbonate reservoirs and has been extended successfully by Deng (2010) and Leguizamon and Aguilera (2011) for the case of isolated dissolution porosity and other types of non-connected porosities present in tight gas sands. In this case v nc is equal to the isolated non-connected porosity (φ nc ) divided by total porosity (φ).…”

Section: Petrophysical Triple Porosity Modelmentioning

confidence: 99%

Petrophysics of Triple Porosity Tight Gas Reservoirs with a Link to Gas Productivity

Deng

Leguizamon

SPE Western North American Region Meeting

2011

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Petrographic work on thin sections from rock samples collected in tight gas sandstones of the Western Canada Sedimentary basin (WCSB) shows that the sandstones are composed of intergranular, microfracture + slot, and isolated non-effective porosities. The petrographic observations of these triple porosity rocks have led to a petrophysical interpretation with the use of a triple porosity model.Tight gas reservoirs are very complex heterogeneous systems that have been evaluated in the past mostly with single porosity models. We propose that these types of reservoirs can be better represented by triple-porosity models for more rigorous quantitative petrophysical characterization. The triple porosity model discussed in this paper fits very well the petrographic observations leading to a more rigorous characterization of effective and non-effective porosity.The petrography and core-calibrated triple porosity model is then used for well log interpretation of those wells where these data are not available. The result is a reasonable quantitative characterization of the tight gas reservoir that can be used for improving hydraulic fracturing design, flow units determination, reservoir engineering and simulation studies. The data can be determined at room conditions and simulated conditions of net stress.It is concluded that honoring with a triple porosity model the different types of porosities observed in thin sections and cores lead to more rigorous and useful petrophysical interpretations that can be linked to gas productivity.

“…It has also been used with a good level of success for reservoir characterization and flow simulation of the Nikanassin and Cadomin formations in Alberta (Deng 2011).…”

Section: Proposed Integrated Workflowmentioning

confidence: 99%

Reservoir Characterization and Flow Simulation of a Low-Permeability Gas Reservoir: An Integrated Approach for Modelling the Tommy Lakes Gas Field

Deng

Journal of Canadian Petroleum Technology

Alfarhan³

et al. 2011

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Summary The Tommy Lakes field is located in northeastern British Columbia, Canada, and is one of the largest Middle Triassic gas pools within the western Canada sedimentary basin (WCSB). The major gas-production formation (Halfway/Doig reservoirs) at the Tommy Lakes field corresponds to shoreface sands with permeabilities ranging between 0.1 and 3 md, and porosities of 3 to12%. For the purpose of production optimization and field development, a full-field reservoir model was developed with the integration of advanced reservoir characterization, hydraulic-fracture modelling, and history-matching techniques. This study presents an integrated workflow for modelling the low-permeability Doig gas reservoir. A stochastic geostatistical reservoir model was developed on the basis of concepts emanating from an outcrop analogue analyzed with terrestrial light detection and ranging (LiDAR) technology and 60 wells that represent the fundamental rock characteristics, structure, facies? proportions, and petrophysical properties of the Doig anomalously thick sandstone bodies (ATSBs). Structural tops were interpreted from well logs and permeability/porosity relationships established from quantitative log analysis and core/log calibration. Facies were identified in cored intervals and were further grouped into four lithofacies. An artificial neural network (ANN) was used for training the logs of key wells [gamma ray (GR), neutron porosity (NPHI), and bulk density (RHOB)] and populating the facies distribution of uncored wells. Facies-based log-derived porosity, permeability, shale volume, and water saturation were assigned to gridblocks using sequential Gaussian simulation (SGS). Finally, the Monte Carlo simulation approach was used to rank the key variables affecting original gas in place (OGIP) in the uncertainty and optimization process. Flow-based techniques were used for upscaling reservoir properties into the coarse simulation grid. The full-field simulation model was calibrated with buildup data and hydraulic-fracture modelling of single wells. Production of the Doig channel from commingled wells was allocated systematically in order to achieve a good match of the gas-production history and bottomhole pressures. Sensitivity analysis of fracture half-length and its impact on ultimate gas recovery was investigated. This concluded with an integrated development strategy. It is concluded that integration of multiple domains leads to a valid full-field reservoir model, which is critical in developing an integrated strategy, predicting reservoir performance, and optimizing gas production.