Integrated Characterization of Hydraulically Fractured Shale Gas Reservoirs Production History Matching

2014 ◽  
Author(s):  
Siavash Nejadi ◽  
Juliana Yuk Wing Leung ◽  
Japan J Trivedi ◽  
Claudio Juan Jose Virues
Keyword(s):  
Shale Gas ◽  
History Matching ◽  
Gas Reservoirs ◽  
Shale Gas Reservoirs ◽  
Production History

Multidisciplinary Approach for Detailed Characterization of Shale Gas Reservoirs: A Netherlands Showcase

2013 ◽  
Author(s):  
Yvonne Anja Schavemaker ◽  
Mart Zijp ◽  
Jan ter Heege ◽  
Susanne Nelskamp ◽  
Johan Ten Veen
Keyword(s):  
Shale Gas ◽  
Multidisciplinary Approach ◽  
Gas Reservoirs ◽  
Detailed Characterization ◽  
Shale Gas Reservoirs

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

2015 ◽  
Vol 18 (04) ◽  
pp. 481-494 ◽  
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.

From Streamlines to Fast Marching: Rapid Simulation and Performance Assessment of Shale-Gas Reservoirs by Use of Diffusive Time of Flight as a Spatial Coordinate

SPE Journal ◽  
2016 ◽  
Vol 21 (05) ◽  
pp. 1883-1898 ◽  
Author(s):  
Yanbin Zhang ◽  
Neha Bansal ◽  
Yusuke Fujita ◽  
Akhil Datta-Gupta ◽  
Michael J. King ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Performance Assessment ◽  
Shale Gas ◽  
History Matching ◽  
Well Performance ◽  
Gas Reservoirs ◽  
Fast Marching ◽  
Shale Gas Reservoirs ◽  
And Performance ◽  
Diffusivity Equation

Summary Current industry practice for characterization and assessment of unconventional reservoirs mostly uses empirical decline-curve analysis or analytic rate- and pressure-transient analysis. High-resolution numerical simulation with local perpendicular bisector (PEBI) grids and global corner-point grids has also been used to examine complex nonplanar fracture geometry, interaction between hydraulic and natural fractures, and implications for the well performance. Although the analytic tools require many simplified assumptions, numerical-simulation techniques are computationally expensive and do not provide the more-geometric understanding derived from the depth-of-investigation (DOI) and drainage-volume calculations. We propose a novel approach for rapid field-scale performance assessment of shale-gas reservoirs. Our proposed approach is dependent on a high-frequency asymptotic solution of the diffusivity equation in heterogeneous reservoirs and serves as a bridge between simplified analytical tools and complex numerical simulation. The high-frequency solution leads to the Eikonal equation (Paris and Hurd 1969), which is solved for a “diffusive time of flight” (DTOF) that governs the propagation of the “pressure front” in the reservoir. The Eikonal equation can be solved by use of the fast-marching method (FMM) to determine the DTOF, which generalizes the concept of DOI to heterogeneous and fractured reservoirs. It provides an efficient means to calculate drainage volume, pressure depletion, and well performance and can be significantly faster than conventional numerical simulation. More importantly, in a manner analogous to streamline simulation, the DTOF can also be used as a spatial coordinate to reduce the 3D diffusivity equation to a 1D equation, leading to a comprehensive simulator for rapid performance prediction of shale-gas reservoirs. The speed and versatility of our proposed method makes it ideally suited for high-resolution reservoir characterization through integration of static and dynamic data. The major advantages of our proposed approach are its simplicity, intuitive appeal, and computational efficiency. We demonstrate the power and utility of our method by use of a field example that involves history matching, uncertainty analysis, and performance assessment of a shale-gas reservoir in east Texas. A sensitivity study is first performed to systematically identify the “heavy hitters” affecting the well performance. This is followed by history matching and an uncertainty analysis to identify the fracture parameters and the stimulated-reservoir volume. A comparison of model predictions with the actual well performance shows that our approach is able to reliably predict the pressure depletion and rate decline.

Modeling Gas Adsorption in Marcellus Shale With Langmuir and BET Isotherms

SPE Journal ◽  
2016 ◽  
Vol 21 (02) ◽  
pp. 589-600 ◽  
Author(s):  
Wei Yu ◽  
Kamy Sepehrnoori ◽  
Tadeusz W. Patzek
Keyword(s):  
Shale Gas ◽  
Langmuir Isotherm ◽  
History Matching ◽  
Gas Adsorption ◽  
Marcellus Shale ◽  
Methane Adsorption ◽  
Gas Reservoirs ◽  
Gas Desorption ◽  
Shale Gas Reservoirs ◽  
Bet Isotherm

Summary Production from shale-gas reservoirs plays an important role in natural-gas supply in the United States. Horizontal drilling and multistage hydraulic fracturing are the two key enabling technologies for the economic development of these shale-gas reservoirs. It is believed that gas in shale reservoirs is mainly composed of free gas within fractures and pores and adsorbed gas in organic matter (kerogen). It is generally assumed in the literature that the monolayer Langmuir isotherm describes gas-adsorption behavior in shale-gas reservoirs. However, in this work, we analyzed four experimental measurements of methane adsorption from the Marcellus Shale core samples that deviate from the Langmuir isotherm, but obey the Brunauer-Emmett-Teller (BET) isotherm. To the best of our knowledge, it is the first time to find that methane adsorption in a shale-gas reservoir behaves similar to multilayer adsorption. Consequently, investigation of this specific gas-desorption effect is important for accurate evaluation of well performance and completion effectiveness in shale-gas reservoirs on the basis of the BET isotherm. The difference in calculating original gas in place (OGIP) on the basis of both isotherms is discussed. We also performed history matching with one production well from the Marcellus Shale and evaluated the contribution of gas desorption to the well's performance. History matching shows that gas adsorption obeying the BET isotherm contributes more to overall gas recovery than gas adsorption obeying the Langmuir isotherm, especially at early time in production. This work provides better understanding of gas desorption in shale-gas reservoirs and updates our current analytical and numerical models for simulation of shale-gas production.

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