3D Modeling of Multistage Hydraulic Fractures and Two-Way Coupling Geomechanics - Fluid Flow Simulation of a Horizontal Well in the Nikanassin Tight Gas Formation, Western Canada Sedimentary Basin

Gonzalez, Laureano; Nasreldin, Gaisoni; Rivero, Jose A.; Welsh, Peter; Aguilera, Roberto

doi:10.2118/159765-ms

Cited by 7 publications

(4 citation statements)

References 21 publications

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“…The Late Jurassic/Early Cretaceous tight-gas-sandstone reservoir in the Monteith Formation is part of the well-established large, extensive deep-basin-centered gas system in the subsurface of Alberta and British Columbia (Masters 1979;Miles et al 2009). The Monteith formation is subdivided into three members within the study area: 1.…”

Section: Case Studymentioning

confidence: 99%

“…Relative permeability curves, fluid properties, and completion data were provided by previous studies carried out by members of the GFREE [an integrated research program that includes Geoscience (G), Formation evaluation (F), Reservoir drilling, completion and stimulation (R), Reservoir Engineering (RE), and Economics and externalities (EE)] research group at the University of Calgary (Deng 2011;Deng et al 2011;Gonzalez 2012;Ramirez Vargas and Aguilera 2013;Gonzalez et al 2014). The static model includes effective matrix and fracture properties.…”

Section: Reservoir Modelmentioning

confidence: 99%

“…Schematic Location of study area in the Western Canada Sedimentary Basin (modified fromMasters (1979). Map shows isopach of the Monteith member in the study area.…”

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confidence: 99%

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Integrated Reservoir Characterization and 3D Modeling of the Monteith Formation: A Case Study of Tight Gas Sandstones in the Western Canada Sedimentary Basin, Alberta, Canada

Zambrano

Vargas

Pedersen

et al. 2016

SPE Reservoir Evaluation &Amp; Engineering

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The Monteith Formation is an important tight gas reservoir in the Deep Basin, Alberta, and consists of a progradational succession of shallow marine sediments, nonmarine carbonaceous and coaly, coastal plain facies, and coarse-grained fluvial deposits, from base to top, respectively. This study is based on multiscale description and characterization techniques with cores and drill cuttings, including multimethods laboratory measurements of key reservoir parameters such as porosity and permeability. A second stage of the study involves the use of laboratory measurements obtained from cores and drill cuttings and their integration with well logs to construct a numerical 3D model of the study area. The 3D model is used to history match gas production, and forecast performance of new wells in those areas where the geologic model indicates potential for gas production.The ultimate goal is to provide a better understanding of the distribution of reservoir properties in the study area for developing drilling prospects and their production potential in areas where reliable data are scarce. The reservoir-modeling stage is carried out by implementing a recently developed methodology that integrates a variable shape distribution (VSD) model, capable of capturing different reservoir properties throughout the whole scale spectrum without any data truncation. Truncation is the excuse generally used for eliminating information that does not fit a given distribution. The claim is that the data are of poor quality, something that is not true in many cases. This new methodology eliminates the need for truncation, and introduces an extension of the VSD approach for reservoir-simulation purposes that reduces uncertainty in the generation of drilling prospects.Core analysis shows that the Monteith A member is composed of complex fluvial-dominated deposits with better rock quality than the shallow marine sandstones of the Monteith C member. This is most likely because of larger pore-throat apertures that range between 0.5 and 1 lm, and a relatively higher proportion of preserved intergranular pore space within these coarser-grained framework grains. Furthermore, the best production performance is from wells that are producing from the Monteith A. Variability of production rates also seems to be controlled by the presence of natural fractures. It is anticipated that the resulting 3D reservoir model will allow improving field-development strategies for this and other similar unconventional gas reservoirs in the Deep Basin of Alberta and elsewhere.

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Section: Case Studymentioning

confidence: 99%

Section: Reservoir Modelmentioning

confidence: 99%

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Integrated Reservoir Characterization and 3D Modeling of the Monteith Formation: A Case Study of Tight Gas Sandstones in the Western Canada Sedimentary Basin, Alberta, Canada

Zambrano

Vargas

Pedersen

et al. 2016

SPE Reservoir Evaluation &Amp; Engineering

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“…The information has been used to assist in optimization of hydraulic fracturing jobs in vertical wells ( and multistage hydraulic fracturing jobs in horizontal wells (Ortega, 2012;Ortega andAguilera, 2012, 2013). In addition to the properties described in the previous section, which concentrate on pore apertures and fracture length, the VSD model can be used for evaluating other properties such as drill cuttings size, grain size, permeability, brittleness index and water saturation.…”

Section: Tight Reservoirsmentioning

confidence: 99%

Use of a Variable Shape Distribution (VSD) Model to Populate Reservoir Properties in Tight Fractured Reservoirs for Numerical 3D Modeling

Vargas

Freddy

2013

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Hydrodynamic plots of tight formations in the Deep Basin of the Western CanadaSedimentary Basin (WCSB) indicate the lack of a water leg and the presence of water on top of gas; quite unconventional. Furthermore, experience indicates that in many instances properties such as matrix and fracture density in these tight formations cannot be modeled using conventional statistical distributions. Widely used approaches such as normal, geometric and fractal distributions do not reproduce accurately the behaviour of such properties in many cases. Thus it could be said that the unconventional fluids distribution meets the unconventional rocks distribution in unconventional formations. These occurrences have led to the development of the research presented in this work. Original contributions are as follows: 1) Reservoir simulation covering over 1.5 million years that corroborates the presence of a block of water on top of gas in the tight gas Nikanassin formation of the WCSB.2) Implementation of a new methodology to populate matrix and fracture density properties in reservoir simulation with the use of a Variable Shape Distribution (VSD) model.The question is if it is reasonable to think that gas can be trapped for hundreds of years and more by an updip water block. A reservoir simulation model has been created as indicated in item 1 above in order to answer this question. The water seal is shown to be the result of very low permeability and high capillary pressures, properties that are generally found in tight gas formations. The model is defined by a geometry that mimics the geologic interpretation of the Nikanassin Basin Center Gas Accumulation (BCGA) in the Western Canada Sedimentary Basin (WCSB) and rock properties that provide a good representation of the real behavior of the reservoir in the Deep Basin of Alberta. Reservoir simulation has been used historically to model in the order of 10 to 40 years of production. But to our iii knowledge this is the first reservoir simulation that goes beyond 1.5 million years. The results lead to the conclusion that updip water blocks provide good seals in the Deep Basin.The new methodology mentioned above in item 2 introduces an extension of the VSD approach for reservoir simulation purposes. In the original methodology when matching input information in the VSD equation, each data point is assigned an integer according to its ranking (Nt) in the overall sample population. If these integers are used in a normal score transformation for reservoir simulation, the hard data (for example permeability) will not be honoured. As a result, in order to honour the hard data, the integers have been replaced with real numbers found by calculating the values that produce the exact data points when input into the VSD equation. Since this equation has an exponential form it cannot be solved directly for Nt and it is necessary to perform an iterative process to find the exact values.The new methodology is demonstrated with data from the WCSB tight gas Nikanassin Group and Cadomin form...

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Production Forecasting for Shale Gas Reservoirs With Fast Marching-Succession of Steady States Method

Teng

Cheng

Huang

et al. 2018

Journal of Energy Resources Technology

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In this paper, we introduce fast marching-succession of steady-states (FM-SSS) method to predict gas production from shale gas formations. The solutions of fast marching method (FMM) will describe the dynamic drainage boundary, and the succession of steady-state (SSS) method is applied to predict the gas production within the drainage boundary. As only the grids within drainage need to be taken into calculation at each time-step, this approach works much more efficiently than the implicit finite difference method, especially, at the early stage of production when the drainage is relatively small.We combine FMM with SSS to conduct reservoir simulation and predict gas production in shale gas reservoirs. The pressure profiles of transient flow are approximated with the pressure profiles of steady-state flow in our approach. The difference between the proposed method and the conventional SSS method is that we provide an efficient method to characterize the boundary conditions. In the conventional SSS method, the boundary pressure has to be measured, which is inconvenient for simulation purposes, whereas FM-SSS method takes the dynamic drainage as a changing boundary and approximates the drainage boundary pressure with initial reservoir pressure, such that the boundary condition can be numerically characterized. A major advantage of our approach is that it is unconditionally stable and more efficient than the implicit finite difference method because much smaller-scale linear equations need to be solved at each time-step.

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3D Modeling of Multistage Hydraulic Fractures and Two-Way Coupling Geomechanics - Fluid Flow Simulation of a Horizontal Well in the Nikanassin Tight Gas Formation, Western Canada Sedimentary Basin

Abstract: Unconventiona estimated world hat the volum recovery factorTo help unlock fracturing in ho geometry (not state in the dra geomechanical fractured tight g Traditionally, t system to a pla presented in th orientation and pressure deplet are ignored.

Cited by 7 publications

References 21 publications

Integrated Reservoir Characterization and 3D Modeling of the Monteith Formation: A Case Study of Tight Gas Sandstones in the Western Canada Sedimentary Basin, Alberta, Canada

Integrated Reservoir Characterization and 3D Modeling of the Monteith Formation: A Case Study of Tight Gas Sandstones in the Western Canada Sedimentary Basin, Alberta, Canada

Use of a Variable Shape Distribution (VSD) Model to Populate Reservoir Properties in Tight Fractured Reservoirs for Numerical 3D Modeling

Production Forecasting for Shale Gas Reservoirs With Fast Marching-Succession of Steady States Method

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