Development of Production-Forecasting Model Based on the Characteristics of Production Decline Analysis Using the Reservoir and Hydraulic Fracture Parameters in Montney Shale Gas Reservoir, Canada

This study developed a production-forecasting model to replace the numerical simulation and the decline curve analysis using reservoir and hydraulic fracture data in Montney shale gas reservoir, Canada. A shale-gas production curve can be generated if some of the decline parameters such as a peak rate, a decline rate, and a decline exponent are properly estimated based on reservoir and hydraulic fracturing parameters. The production-forecasting model was developed to estimate five decline parameters of a modified hyperbolic decline by using significant reservoir and hydraulic fracture parameters which are derived through the simulation experiments designed by design of experiments and statistical analysis: (1) initial peak rate ( P hyp ), (2) hyperbolic decline rate ( D hyp ), (3) hyperbolic decline exponent ( b hyp ), (4) transition time ( T transition ), and (5) exponential decline rate ( D exp ). Total eight reservoir and hydraulic fracture parameters were selected as significant parameters on five decline parameters from the results of multivariate analysis of variance among 11 reservoir and hydraulic fracture parameters. The models based on the significant parameters had high predicted R 2 values on the cumulative production. The validation results on the 1-, 5-, 10-, and 30-year cumulative production data obtained by the simulation showed a good agreement: R 2 > 0.89 . The developed production-forecasting model can be also applied for the history matching. The mean absolute percentage error on history matching was 5.28% and 6.23% for the forecasting model and numerical simulator, respectively. Therefore, the results from this study can be applied to substitute numerical simulations for the shale reservoirs which have similar properties with the Montney shale gas reservoir.

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3D Numerical Investigation of Hydraulic Fracture Network Propagation in a Shale Gas Reservoir with Natural and Layered Discontinuities Under Fully Hydro-Mechanical Coupling

Journal of Porous Media ◽

10.1615/jpormedia.2021036113 ◽

2021 ◽

Author(s):

Honglian Li ◽

Mingjie Feng ◽

Hejuan Liu ◽

Lei Zhou ◽

Junchao Chen ◽

...

Keyword(s):

Numerical Investigation ◽

Shale Gas ◽

Hydraulic Fracture ◽

Fracture Network ◽

Gas Reservoir ◽

Mechanical Coupling ◽

Shale Gas Reservoir ◽

Network Propagation ◽

Hydraulic Fracture Network

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An efficient automatic history matching method through the probabilistic collocation based particle filter for shale gas reservoir

Journal of Petroleum Science and Engineering ◽

10.1016/j.petrol.2020.107086 ◽

2020 ◽

Vol 190 ◽

pp. 107086

Author(s):

Liang Xue ◽

Yuetian Liu ◽

Tongchao Nan ◽

Qianjun Liu ◽

Xieer Jiang

Keyword(s):

Particle Filter ◽

Shale Gas ◽

History Matching ◽

Matching Method ◽

Gas Reservoir ◽

Automatic History Matching ◽

Shale Gas Reservoir ◽

Probabilistic Collocation

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Integrated Characterization of Hydraulically Fractured Shale-Gas Reservoirs—Production History Matching

SPE Reservoir Evaluation & Engineering ◽

10.2118/171664-pa ◽

2015 ◽

Vol 18 (04) ◽

pp. 481-494 ◽

Cited By ~ 11

Author(s):

Siavash Nejadi ◽

Juliana Y. Leung ◽

Japan J. Trivedi ◽

Claudio Virues

Keyword(s):

Shale Gas ◽

Hydraulic Fracture ◽

History Matching ◽

Flow Simulation ◽

Simulation Models ◽

Model Parameters ◽

Fracture Parameters ◽

Production History ◽

Dfn Model

Summary Advancements in horizontal-well drilling and multistage hydraulic fracturing have enabled economically viable gas production from tight formations. Reservoir-simulation models play an important role in the production forecasting and field-development planning. To enhance their predictive capabilities and to capture the uncertainties in model parameters, one should calibrate stochastic reservoir models to both geologic and flow observations. In this paper, a novel approach to characterization and history matching of hydrocarbon production from a hydraulic-fractured shale is presented. This new methodology includes generating multiple discrete-fracture-network (DFN) models, upscaling the models for numerical multiphase-flow simulation, and updating the DFN-model parameters with dynamic-flow responses. First, measurements from hydraulic-fracture treatment, petrophysical interpretation, and in-situ stress data are used to estimate the initial probability distribution of hydraulic-fracture and induced-microfracture parameters, and multiple initial DFN models are generated. Next, the DFN models are upscaled into an equivalent continuum dual-porosity model with analytical techniques. The upscaled models are subjected to the flow simulation, and their production performances are compared with the actual responses. Finally, an assisted-history-matching algorithm is implemented to assess the uncertainties of the DFN-model parameters. Hydraulic-fracture parameters including half-length and transmissivity are updated, and the length, transmissivity, intensity, and spatial distribution of the induced fractures are also estimated. The proposed methodology is applied to facilitate characterization of fracture parameters of a multifractured shale-gas well in the Horn River basin. Fracture parameters and stimulated reservoir volume (SRV) derived from the updated DFN models are in agreement with estimates from microseismic interpretation and rate-transient analysis. The key advantage of this integrated assisted-history-matching approach is that uncertainties in fracture parameters are represented by the multiple equally probable DFN models and their upscaled flow-simulation models, which honor the hard data and match the dynamic production history. This work highlights the significance of uncertainties in SRV and hydraulic-fracture parameters. It also provides insight into the value of microseismic data when integrated into a rigorous production-history-matching work flow.

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Numerical Simulation for Shale Gas Flow in Complex Fracture System of Fractured Horizontal Well

International Journal of Nonlinear Sciences and Numerical Simulation ◽

10.1515/ijnsns-2017-0135 ◽

2018 ◽

Vol 19 (3-4) ◽

pp. 367-377 ◽

Cited By ~ 4

Author(s):

Yingzhong Yuan ◽

Wende Yan ◽

Fengbo Chen ◽

Jiqiang Li ◽

Qianhua Xiao ◽

...

Keyword(s):

Numerical Simulation ◽

Shale Gas ◽

Horizontal Well ◽

Fracture Network ◽

Gas Reservoir ◽

Complex Fracture ◽

Shale Gas Reservoir ◽

Fracture Parameters ◽

Fracture Systems ◽

Fractured Horizontal Well

AbstractComplex fracture systems including natural fractures and hydraulic fractures exist in shale gas reservoir with fractured horizontal well development. The flow of shale gas is a multi-scale flow process from microscopic nanometer pores to macroscopic large fractures. Due to the complexity of seepage mechanism and fracture parameters, it is difficult to realize fine numerical simulation for fractured horizontal wells in shale gas reservoirs. Mechanisms of adsorption–desorption on the surface of shale pores, slippage and Knudsen diffusion in the nanometer pores, Darcy and non-Darcy seepage in the matrix block and fractures are considered comprehensively in this paper. Through fine description of the complex fracture systems after horizontal well fracturing in shale gas reservoir, the problems of conventional corner point grids which are inflexible, directional, difficult to geometrically discretize arbitrarily oriented fractures are overcome. Discrete fracture network model based on unstructured perpendicular bisection grids is built in the numerical simulation. The results indicate that the discrete fracture network model can accurately describe fracture parameters including length, azimuth and density, and that the influences of fracture parameters on development effect of fractured horizontal well can be finely simulated. Cumulative production rate of shale gas is positively related to fracture half-length, fracture segments and fracture conductivity. When total fracture length is constant, fracturing effect is better if single fracture half-length or penetration ratio is relatively large and fracturing segments are moderate. Research results provide theoretical support for optimal design of fractured horizontal well in shale gas reservoir.

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