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Multistage hydraulic fractured horizontal wells (MHFHWs) are widely used in most shale gas reservoirs around the world. Hydraulic fracturing treatment can create hydraulic fractures and activate existing natural fractures to generate a complex fracture network to significantly improve the well performance. For precise production prediction, it is critical to recongnize the spatial extent and properties of the hydraulic fracture network with multiple data such as production history, microseismic et al.
In this study, a novel method that combines the automatical history matching technology and embedded discrete fracture modeling (EDFM) is proposed for the recongnizing the spatial extent and properties of fracture network for MHFHWs. For each hydraulic fracturing stage, the fracture network is parameterized by a set of uncertain parameters, including the length of major fracture, width of the stimulated area, fracture density, fracture permeability, etc. Using these parameters, realizations of the fracture network are generated. The production predictions are obtained by running reservoir simulations with EDFM in which all fractures are embedded into a background grid system, and the automatical history matching method is applied to perform history matching. The proposed approach is validated using synthetic single- well and double-well cases. The results show that the spatial extent and properties of the hydraulic fracture network can be well recognized and that the production history can be well matched.
Considering that microseismic surveillance is often currently performed in shale gas reservoirs, the prior constraint of microseismic data is also investigated in this work. When microseismic data are available, an area with effective microseismic events for each fracturing stage is first defined. The events within the effective area are used to generate discrete fractures, and the events outside of the effective area are abandoned. Furthermore, the shape parameters of the area with effective microseismic events (wet events) are gradually modified by assimilating the production data. A real field case with microseismic data in the Sichuan Basin of China is investigated to test the performance of the proposed method. Reasonable results are obtained, thus demonstrating the robustness of the proposed approach.
Li, Xin (Peking University) | Li, Xiang (Qingdao Dadi Institute of New Energy Technologies) | Zhang, Dongxiao (Southern University of Science and Technology) | Yu, Rongze (Research Institute of Petroleum Exploration and Development)
Summary In the development of fractured reservoirs, geomechanics is crucial because of the stress sensitivity of fractures. However, the complexities of both fracture geometry and fracture mechanics make it challenging to consider geomechanical effects thoroughly and efficiently in reservoir simulations. In this work, we present a coupled geomechanics and multiphase-multicomponent flow model for fractured reservoir simulations. It models the solid deformation using a poroelastic equation, and the solid deformation effects are incorporated into the flow model rigorously. Because of the separation of the geomechanics part and the flow part, the model is not difficult to implement based on an existing reservoir simulator. We validated the accuracy and stability of this model through several benchmark cases and highlighted the practicability with two large-scale cases. The case studies demonstrate that this model is capable of considering the key effects of geomechanics in fractured-reservoir simulation, including matrix compaction, fracture normal deformation, and shear dilation, as well as hydrocarbon phase behavior. The flexibility, efficiency, and comprehensiveness of this model enable a more realistic geocoupled reservoir simulation. Introduction Fractured reservoirs, including naturally fractured reservoirs and artificially fractured reservoirs, contribute 60% of the world's oil and gas storage and have attracted intense attention in the past two decades. During the production of such reservoirs, stress perturbation induces fracture deformation, and fracture permeability changes significantly, because of its high stress sensitivity. As a result, production is greatly affected. To simulate fractured reservoirs accurately, reservoir models should couple geomechanics, and the geocoupled model should consider fracture effects.
Liu, Lijun (China University of Petroleum (East China)) | Huang, Zhaoqin (China University of Petroleum (East China)) | Yao, Jun (China University of Petroleum (East China)) | Di, Yuan (Peking University) | Wu, Yu-Shu (Colorado School of Mines)
Fractured vuggy reservoir is a typical type of carbonate reservoir. The 3D complex fracture networks and Stokes flow inside vugs make fractured vuggy reservoir simulation remain a challenging problem. Most of the proposed models in previous studies are computation consuming, which cannot meet with the demand of field application. In this paper, a novel and efficient hybrid model, consisting of a modified embedded discrete fracture model (EDFM) and a vug model, is proposed to simulate multiphase flow in 3D complex fractured vuggy reservoirs. The modified EDFM improves the fracture-discretization process by using two sets of independent grids for matrix and fracture systems, which promotes the modeling of 3D complex fractures in real geological structures. Meanwhile, the vug model simplifies the coupled porous-free flow with the assumption of multiphase instantaneous gravity differentiation. The accuracy of the modified EDFM and the vug model is demonstrated by comparing the results with those of the conventional EDFM and volume of fluid (VOF) method. After that, a series of case studies, including three conceptual fracture-vug unit models and a real field model, have been conducted to test the proposed hybrid model. The results of the three fracture-vug unit models indicate the significant effect of a local fracture-vug structure on the flow characteristics and production performance. Finally, the application with a real field model with 3D complex fracture and vug geometries further verifies the practicability of our proposed model in real fractured vuggy reservoirs.
For the unconventional reservoir, triple-porosity models are widely applied to take the macro-fracture, micro-fracture and matrix system into consideration. However, the models are usually built based on the assumption of sequential flow from matrix to micro-fracture to macro-fracture, which will result in inaccuracy of production evaluation. Although a quadri-linear flow model (QFM) has been proposed to consider the simultaneous flow from matrix into micro-fracture and macro-fracture. It is relatively complicated to solve the model with the Laplace transform and numerical inversion. In this paper, a new analytical solution for the QFM is derived.
In order to simplify the problem, the matrix flow is divided into two parts: one feeding the macro-fracture and the other feeding the micro-fracture. Then, four partial differential equations (PDEs) are obtained to express the transient linear flow in different media. The PDEs are transformed into ordinary differential equations (ODEs) by integration bypassing the Laplace transform and numerical inversion. Finally, a rate vs. time solution in real-time space is derived.
The results are validated by typical analytical models. While the micro-fracture system is neglected, the results agree well with the dual-porosity model. While ignoring flow between the matrix and macro-fracture, the results agree with the triple-porosity model. What’s more, according to the output parameters from the new model, one can infer the ratio of pore volume of different media and even the ratio of flow from matrix to the micro-fracture and to the macro-fracture simultaneously. The model is also applied to analyze the field production data. After identifying the flow regime, the solution can match well with the data and the model parameters can be obtained. Through the parameters, we can make production forecast accurately.
Bayesian inference provides a convenient framework for history matching and prediction. In this framework, prior knowledge, system nonlinearity, and measurement errors can be directly incorporated into the posterior distribution of the parameters. The Markov-chain Monte Carlo (MCMC) method is a powerful tool to generate samples from the posterior distribution. However, the MCMC method usually requires a large number of forward simulations. Hence, it can be a computationally intensive task, particularly when dealing with large-scale flow and transport models. To address this issue, we construct a surrogate system for the model outputs in the form of polynomials using the stochastic collocation method (SCM). In addition, we use interpolation with the nested sparse grids and adaptively take into account the different importance of parameters for high-dimensional problems. Furthermore, we introduce an additional transform process to improve the accuracy of the surrogate model in case of strong nonlinearities, such as a discontinuous or unsmooth relation between the input parameters and the output responses. Once the surrogate system is built, we can evaluate the likelihood with little computational cost. Numerical results demonstrate that the proposed method can efficiently estimate the posterior statistics of input parameters and provide accurate results for history matching and prediction of the observed data with a moderate number of parameters.
Naturally or hydraulically fractured reservoirs usually contain fractures at various scales. Among these fractures, large-scale fractures might strongly affect fluid flow, making them essential for production behavior. Areas with densely populated small-scale fractures might also affect the flow capacity of the region and contribute to production. However, because of limited information, locating each small-scale fracture individually is impossible. The coexistence of different fracture scales also constitutes a great challenge for history matching. In this work, an integrated approach is proposed to inverse model multiscale fractures hierarchically using dynamic production data. in the proposed method, a hybrid of an embedded discrete fracture model (EDFM) and a dual-porosity/dual-permeability (DPDP) model is devised to parameterize multiscale fractures. The large-scale fractures are explicitly modeled by EDFM with Hough-transform-based parameterization to maintain their geometrical details. For the area with densely populated small-scale fractures, a truncated Gaussian field is applied to capture its spatial distribution, and then the DPDP model is used to model this fracture area. After the parameterization, an iterative history-matching method is used to inversely model the flow in a fractured reservoir. Several synthetic cases, including one case with single-scale fractures and three cases with mutliscale fractures, are designed to test the performance of the proposed approach.
Massive hydraulic fracturing requires an enormous consumption of water and introduces many potential environmental issues. In addition, water-based fluid tends to be trapped in formations, reducing oil/gas-phase relative permeability, and causes clay-mineral swelling, which lowers absolute permeability. Carbon dioxide (CO2) is seen as a promising alternative working fluid that poses no formation-damage risk, and it can stimulate more-complex and extensive fracture networks. However, very little, if any, extant research has quantitatively analyzed the effectiveness of CO2 fracturing, except for some qualitative fracturing experiments that are based on acoustic emissions. In this study, we systematically examine water and CO2 fracturing, and compare their performance on the basis of a rigorously coupled geomechanics and a fluid-heat-flow model. Parameters investigated include fluid viscosity, compressibility, in-situ stress, and rock permeability, illustrating how they affect breakdown pressure (BP) and leakoff, as well as fracturing effectiveness. It is found that (1) CO2 has the potential to lower BP, benefiting the propagation of fractures; (2) water fracturing tends to create wider and longer tensile fractures compared with CO2 fracturing, thereby facilitating proppant transport and placement; (3) CO2 fracturing could dramatically enhance the complexity of artificial fracture networks even under high-stress-anisotropy conditions; (4) thickened CO2 tends to generate simpler fracture networks than does supercritical CO2 (SC-CO2), but still more-complex fracture networks than fresh water; and (5) the alternative fracturing scheme (i.e., SC-CO2 fracturing followed by thickened-CO2 fracturing) can readily create complex fracture networks and carry proppant to keep hydraulic fractures open. This study reveals that, for intact reservoirs, water-based fracturing can achieve better fracturing performance than CO2 fracturing; however, for naturally fractured reservoirs, CO2 fracturing can constitute an effective way to stimulate tight/shale oil/gas reservoirs, thereby improving oil/gas production.
In this work, we present the development of a comprehensive mathematical formulation and reservoir simulator for thermal-hydraulic-mechanical simulation of CO2-EOR processes
We adopt the integral finite difference method to simulate coupled thermal-hydraulic-mechanical processes during CO2-EOR in conventional and unconventional reservoirs. In our method, the governing equations of the multiphysical processes are solved fully coupled on the same unstructured grid. A multiscale algebraic linear solver is adopted to speed up the non-isothermal flow calculation. Inspired by the meshless method, the algebraic solver eliminates the low-frequency terms through smoothing on a coarse grid. In order to simulate the phase behavior of a three-phase system, a three-phase flash calculation module, based on direct minimization of Gibbs energy, is implemented in the simulator.
We have investigated the impact of cold CO2 injection on injectivity as well as on phase behavior. We conclude that cold injection is an effective way to increase injectivity in tight-oil reservoirs. We have observed and studied the temperature decreasing phenomena near the production well, known as the Joule-Thomson effect, induced by expansion of in-situ fluids.
The novelty of this work lies in the fully coupled simulation scheme, including non-isothermal effects on CO2-EOR processes and recoveries, which has been ignored in almost all modeling studies of CO2-EOR. The multiscale solution strategy and the unique phenomena of non-isothermal compositional modeling coupled with geomechanics are captured by our simulator.
Weirong, Li (Xi'an Shiyou University) | Zhenzhen, Dong (Xi'an Shiyou University) | Gang, Lei (King Fahd University of Petroleum and Minerals) | Cai, Wang (Research Institute of Petroleum Exploration & Development, Petrochina) | Huijie, Wang (Peking University)
A local refined model, using micro-seismic data to model fracture geometry, is presented to study huff-n-puff surfactant injection in a tight oil reservoir. The goal of this study is to understand the key parameters that control the surfactant huff-n-puff performance in tight oil reservoirs.
In this new approach, natural fractures in tight oil reservoir is described by dual permeability model, and stimulated reservoir volume (SRV) based on micro-seismic datais is modeled by local refined grid. In the study, sensitivity analysis is carried out to optimize oil recovery, such as wettability change, interfacial tension, surfactant adsorption, huff-n-puff cycle, etc.
The results indicate that surfactant injection is a favorable method to mobilize oil in tight oil reservoirs; wettability alteration and interfacial tension of surfactant are the dominant mechanisms for the oil recovery through surfactant injection; surfactant adsorption is a key element to the success of the wettability alteration process; and soaking time does not have obvious impact on recovery. The incremental oil recovery factor over primary production for 15 years of total production is up to 3.5% of OOIP that doubles the recovery from the primary production.
The study gives new method to study surfactant injection in the tight oil reservoirs when micro-seismic data available. It can be helpful for modeling other EOR process in tight oil reservoirs. The results also can guide surfactant injection in field development for similar tight oil field.
Carbon dioxide (CO2) injection is an effective enhanced-oil-recovery (EOR) method in unconventional oil reservoirs. However, investigation of the CO2 huff ’n’ puff process in tight oil reservoirs with nanopore confinement is lacking in the petroleum industry. The conventional models need to be modified to consider nanopore confinement in both phase equilibrium and fluid transport.
Hence, we develop an efficient model to fill this gap and apply to the field production of the Bakken tight oil reservoir. Complexfracture geometries are also handled in this model. First, we revised the phase equilibrium calculation and evaluated the fluid properties with nanopore confinement. An excellent agreement between this proposed model and the experimental data is obtained considering nanopore confinement. Afterward, we verified the calculated minimum miscibility pressure (MMP) using this model against the experimental data from a rising-bubble apparatus (RBA). We analyzed the MMP and well performance of CO2 EOR in the Bakken tight oil reservoir. On the basis of the prediction of the field data, the MMP is 450 psi lower than the MMP with bulk fluid when the pore size reduces to 10 nm. Subsequently, we examined the effects of key parameters such as matrix permeability and CO2 molecular diffusion on the CO2 huff ’n’ puff process. Results show that both CO2-diffusion and capillary pressure effects improve the oil recovery factor from tight oil reservoirs, which should be correctly implemented in the simulation model. Finally, we analyzed well performance of a field-scale horizontal well from the Bakken Formation with nonplanar fractures and natural fractures. Contributions of CO2-diffusion and capillary pressure effects are also examined in depth in field scale with complex-fracture geometries. The oil recovery factor of the CO2 huff ’n’ puff process with both CO2-diffusion and capillary pressure effects increases by as much as 5.1% in the 20-year period compared with the case without these factors.
This work efficiently analyzes the CO2 huff ’n’ puff process with complex-fracture geometries considering CO2 diffusion and nanopore confinement in the field production from the Bakken tight oil reservoir. This model can provide a strong basis for accurately predicting the long-term production with complex-fracture geometries in tight oil reservoirs.