Multistage Hydraulic Fractured Horizontal Well Research Articles

Further Investigation of Forced Imbibition in Unconventional Oil Reservoirs for Enhanced Oil Recovery

One of the popular EOR methods for unconventional oil reservoirs is taking advantage of the spontaneous imbibition during the completion stage of a multistage hydraulic fractured horizontal well. An abundant amount of completion fluid is injected during the operation and is expected to boost oil production through counter-current imbibition before the well opens for production. While most similar studies focused on modeling the spontaneous imbibition, this process occurs with soaking pressure involved in real life, which is defined as forced imbibition. Our previous study discussed the mechanisms and demonstrated the difference between spontaneous imbibition and forced imbibition through experiments and numerical simulation. The soaking pressure negatively impacts the efficiency of imbibition due to a high-pressure barrier, which further impairs the production enhancement. This study further investigated factors that may affect the recovery during this soaking stage in a more realistic reservoir model. The model is validated through lab experiments and mimics a quarter of a hydraulic fracturing stage. The effects of cluster spacing, permeability, and wettability were studied under different soaking pressures. The results indicated that, regardless of the soaking pressure, imbibition is an effective method to enhance the recovery of an unconventional oil reservoir. The results are highly sensitive to the cluster distances and only effective within the stimulated reservoir volumes. The matrix permeability and wettability are also important factors to be considered. The objective is to provide a better picture for the accurate design of fracturing completion so that an optimum oil production enhancement can be achieved.

Comparison of the Methods for Analyzing Rate- and Pressure-Transient Data from Multistage Hydraulically Fractured Unconventional Gas Reservoirs

Summary In this study, we provide a detailed review and comparison of the various graphical methods, available in the literature, to interpret/analyze rate- and pressure-transient data acquired from multistage hydraulically fractured horizontal wells (MHFHWs) completed in unconventional gas reservoirs. The methods reviewed in this study do not address complex transport mechanisms and complex fracture networks, but do address transient matrix linear flow (Ibrahim and Wattenbarger 2006; Nobakht and Clarkson 2012a, 2012b; Chen and Raghavan 2013) and boundary-dominated flow (BDF). The methods for BDF are the contacted-volume methods based on the ending times of linear flow (Wattenbarger et al. 1998; Behmanesh et al. 2015) and the flowing material-balance (FMB) methods. The Agarwal-Gardner FMB method (Agarwal et al. 1999) and the conventional FMB method involve plotting rate-normalized pseudopressure vs. material-balance pseudotime. We delineate the advantages and limitations associated with each method and identify the best methods of interpretation and analysis. Three different production modes—constant rate (CR), constant bottomhole pressure (BHP) (CBHP), and variable-rate BHP—are considered. For comparison, various synthetic test data sets generated from a high-resolution spectral gas simulator, which treats nonlinear gas flow rigorously and accurately to simulate rate-transient data, is used. Both synthetic noise-free and noisy-rate pressure-data sets considering wide ranges of initial reservoir pressure and BHP, as well as real-field data sets, are used to compare the methods. For linear flow, the Nobakht-Clarkson method (Nobakht and Clarkson 2012a, 2012b) yields the best results, although its use is tedious because it requires an iterative procedure. The Chen and Raghavan (2013) method for linear flow seems to provide results that are comparable with the Nobakht-Clarkson method (Nobakht and Clarkson 2012b) but does not require an iterative procedure. The Ibrahim-Wattenbarger method (Ibrahim and Wattenbarger 2006) for linear-flow analysis always overestimates flow capacity compared with the other methods. Among the methods that discuss the ending time of linear flow, it was found that the unit-impulse method from Behmanesh et al. (2015) provides the best results for predicting gas in place. For BDF, the results show that the Agarwal-Gardner FMB method (Agarwal et al. 1999) is quite vulnerable to the error in rate/pressure data, whereas the conventional FMB method is more robust to noise and provides more accurate estimates of gas in place.

Modeling Hydraulically Fractured Shale Wells Using the Fast-Marching Method With Local Grid Refinements and an Embedded Discrete Fracture Model

Summary Recently, fast–marching–method (FMM) –based flow simulation has shown great promise for rapid modeling of unconventional oil and gas reservoirs. Currently, the application of FMM–based simulation has been limited to using tartan grids to model the hydraulic fractures (HFs). The use of tartan grids adversely impacts the computational efficiency, particularly for field–scale applications with hundreds of HFs. Our purpose in this paper is to extend FMM–based simulation to incorporate local grid refinements (LGRs) and an embedded discrete fracture model (EDFM) to simulate HFs with natural fractures, and to validate the accuracy and efficiency of the methodologies. The FMM–based simulation is extended to LGRs and EDFM. This requires novel gridding through the introduction of triangles (2D) and tetrahedrons (2.5D) to link the local and global domain and solution of the Eikonal equation in unstructured grids to compute the diffusive time of flight (DTOF). The FMM–based flow simulation reduces a 3D simulation to an equivalent 1D simulation using the DTOF as a spatial coordinate. The 1D simulation can be carried out using a standard finite–difference method, thus leading to orders of magnitude of savings in computation time compared with full 3D simulation for high–resolution models. First, we validate the accuracy and computational efficiency of the FMM–based simulation with LGRs by comparing them with tartan grids. The results show good agreement and the FMM–based simulation with LGRs shows significant improvement in computational efficiency. Then, we apply the FMM–based simulation with LGRs to the case of a multistage–hydraulic–fractured horizontal well with multiphase flow, to demonstrate the practical feasibility of our proposed approach. After that, we investigate various discretization schemes for the transition between the local and global domain in the FMM–based flow simulation. The results are used to identify optimal gridding schemes to maintain accuracy while improving computational efficiency. Finally, we demonstrate the workflow of the FMM–based simulation with EDFM, including grid generation; comparison with FMM with unstructured grid; and validation of the results. The FMM with EDFM can simulate arbitrary fracture patterns without simplification and shows good accuracy and efficiency. This is the first study to apply the FMM–based flow simulation with LGRs and EDFM. The three main contributions of the proposed methodology are (i) unique mesh–generation schemes to link fracture and matrix flow domains, (ii) DTOF calculations in locally refined grids, and (iii) sensitivity studies to identify optimal discretization schemes for the FMM–based simulation.

Effects of ‘soft-hard’ compaction and multiscale flow on the shale gas production from a multistage hydraulic fractured horizontal well

In this study, the shale gas production from a multistage hydraulic fractured shale gas reservoir was analyzed. Firstly, the reservoir was divided into single-porosity medium zone, dual-porosity medium zone, and hydraulic fracture zone. Then, a mathematical model was established for the multiscale gas diffusion and adsorption/desorption mechanisms in matrix, the gas flow in fractures and the interaction between gas flow and shale deformation. Thirdly, this mathematical model was numerically solved within the platform of Comsol Multiphysics and verified by the history matching of the gas production data from Barnett and Marcellus shale reservoirs. Finally, sensitivity study was conducted to identify key parameters to the efficiency of gas recovery enhancement. It is found that hydraulic fracture aperture and initial permeability of fractures are positively correlated with gas production rate. The ‘soft – hard’ compaction of fractures can significantly modify gas production rate but the modification varies with gas production stage. The deformation and flow properties of hydraulic fractures have significant impacts on gas production rate, particularly in the early stage.

Flow model of a multi-stage hydraulic fractured horizontal well based on tree-shaped fractal fracture networks

Multi-stage hydraulic fractured horizontal wells (MHFHWs) are used to develop low permeability reservoirs. A flow model of the MHFHW is proposed based on tree-shaped fractal fracture networks (TFFNs) considering the tree-shaped fractal network and the hydraulic theory of fracture. Then, a physical model of the MHFHW is established by several TFFNs, including the physical model, generating rules, and numbering rules of the TFFN. A coupling mathematical model is presented by combining the flow and seepage models for the TFFN of the MHFHW. The iterative method is used to solve the mathematical model, and the distributions of pressure, flow rate, and seepage rate in the MHFHW are obtained. The proposed model provides a new method to simulate the flow of the MHFHW considering the tree shape and the fractal characteristics of fractures in the MHFHW.

GPU-Based Computation of Formation Pressure for Multistage Hydraulically Fractured Horizontal Wells in Tight Oil and Gas Reservoirs

A mathematical model for multistage hydraulically fractured horizontal wells (MFHWs) in tight oil and gas reservoirs was derived by considering the variations in the permeability and porosity of tight oil and gas reservoirs that depend on formation pressure and mixed fluid properties and introducing the pseudo-pressure; analytical solutions were presented using the Newman superposition principle. The CPU-GPU asynchronous computing model was designed based on the CUDA platform, and the analytic solution was decomposed into infinite summation and integral forms for parallel computation. Implementation of this algorithm on an Intel i5 4590 CPU and NVIDIA GT 730 GPU demonstrates that computation speed increased by almost 80 times, which meets the requirement for real-time calculation of the formation pressure of MFHWs.

Selection of decline curve analysis method using the cumulative production incline rate for transient production data obtained from a multi-stage hydraulic fractured horizontal well in unconventional gas fields

Selection of decline curve analysis method using the cumulative production incline rate for transient production data obtained from a multi-stage hydraulic fractured horizontal well in unconventional gas fields

Selection of decline curve analysis method using the cumulative production incline rate for transient production data obtained from a multi-stage hydraulic fractured horizontal well in unconventional gas fields

This research presents the selection of an appropriate decline curve analysis (DCA) methodology according to the transient production performance of a multi-fractured horizontal well in an unconventional gas field by using the cumulative production incline rate (IQp) The IQp introduced in this research is the change of cumulative production per unit time divided by the cumulative production. The IQp was confirmed for use as an indicator that could generalise and quantify a production decline through the analysis of well production data. The IQp values of eight and four DCA methods were applied to the production data generated by a reservoir simulation. The Duong method forecasted the production trends most accurately when the IQp exceeded 0.25%, while the YM-SEPD method was the most preferable for the rates below 0.05%. In addition, the analysis of production data for shale gas wells in Canada and the USA matched the simulation results, confirming that it would be reasonable to use the IQp in order to select a DCA method to forecast the production of unconventional gas wells. [Received: February 23, 2017; Revised: December 7, 2017; Accepted: December 9, 2017]

Semi-analytical modeling of shale gas flow through fractal induced fracture networks with microseismic data

Hydraulic fractures connecting to the adjacent induced fracture network significantly promote the productivity of unconventional gas reservoirs. Precise characterization of the fracture network in stimulated reservoir volume (SRV) is particularly important in modeling shale gas flow mechanisms. The objective of this work, based on available microseismic information of fracture density and field production data, is the integrated modeling of shale gas production with time-dependent pressure, pressure-dependent gas properties, and scale-dependent heterogeneous induced-fracture properties.This paper presents a Fractal Induced Fracture Network Distribution (FIFND) model to characterize SRV heterogeneity. The model consists of a novel fractal induced-fracture density distribution and a fractal permeability/porosity distribution. The FIFND model can accurately estimate the induced fracture permeability and porosity when only the microseismic data of fracture density are available. This is highly useful since microseismic fracture density data are more frequently available than permeability and porosity data. A semi-analytical Fractal Transient Shale Gas Flow model (FTSGF) is then derived for the multi-stage hydraulically-fractured horizontal wells. The FTSGF model is coupled with the FIFND model to better describe the fracture network heterogeneity in the SRV. The transient flow contribution from the matrix is modeled by apparent matrix porosity with the presence of adsorbed gas. The fractal transient flow features are ultimately transformed into a characteristic function of the fractal matrix-fracture flow transfer.The FIFND model is validated though the upscaled microseismic geological data for a Barnett shale well. Fracture density distribution, which is regulated by the Hausdorff dimension, is more significant on well productivity than fracture permeability, which is mainly subject to the fracture tortuosity index. The FTSGF model is verified by the field production data in Barnett shale. The robustness of the FTSGF model is justified by a good fit with the Power Law Exponential Decline model (PLE) and alignment with realistic values of multiple physical parameters, including average induced-fracture apertures. Our model is also validated for predicative robustness using fewer months of production data.Finally, we propose and implement a workflow for the integrated semi-analytical modeling of shale gas production. The workflow provides an effective tool for characterization, history-matching, and forecasting reservoir/well performance of hydraulically-fractured horizontal wells in shale reservoirs. The limitations of the proposed models and potential future expansions are discussed.

Production Forecasting of Multistage Hydraulically Fractured Horizontal Wells in Shale Gas Reservoirs with Radial Flow

Production Forecasting of Multistage Hydraulically Fractured Horizontal Wells in Shale Gas Reservoirs with Radial Flow