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A special issue of Energies (ISSN 1996-1073). This special issue belongs to the section "H: Geo-Energy".

Deadline for manuscript submissions: closed (30 October 2023) | Viewed by 14909

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Dr. Haifeng Zhao

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School of Petroleum Engineering, China University of Petroleum, Beijing 102249, China
Interests: tight oil and gas and shale gas volume fracturing technology; coalbed methane drilling and fracturing technology; carbonate rock acid fracturing technology; wellbore stability mechanics and chemistry; oil and gas well sand production prediction and prevention
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Dr. Yang Xia

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Guest Editor

School of Petroleum Engineering, China University of Petroleum, Beijing 102249, China
Interests: tight oil and gas reservoir simulations; shale gas flow; production prediction of unconventional reservoirs; fluid-solid coupling of unconventional reservoirs; fracturing technology of unconventional reservoirs
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

With the in-depth development of unconventional oil and gas resources, such as shale gas, tight oil and shale oil, reservoir simulation has been widely and deeply used in the integrated development model of geology and engineering. Reservoir conditions of deep formations are complex and changeable, and traditional simulation methods face many limitations. Various mechanical methods have been introduced into reservoir simulation, and new technologies such as big data and artificial intelligence have been introduced into the reservoir modeling, which jointly promote the vigorous development of reservoir simulation. This Special Issue welcomes the latest original research results of reservoir modeling and numerical analysis.

The research objects include, but are not limited to, shale gas, coalbed methane, tight sandstone gas, shale oil, tight oil and carbonate reservoir, which can be a fracturing simulation or long-term production simulation. The purpose of this Special Issue is to create a highland for academic publication and achievement display of reservoir simulation.

Dr. Haifeng Zhao
Dr. Yang Xia
Guest Editors

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Keywords

geological modeling
mechanical model
finite element/Discrete element/Finite difference/Energy method
fracturing or fractured reservoir simulation
engineering application

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Related Special Issue

Advances in Reservoir Simulation: 2nd Edition in Energies

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Research

15 pages, 4507 KiB

Open AccessArticle

Well-Test Interpretation Model of Water-Injection Well in a Low-Permeability Reservoir and Its Application

by Jianxiong Li, Kai Wang, Sheng Su, Kejun Huang, Haoran Feng, Ziyi Jin, Cong Peng, Jinbao Liu and Pin Jia

Energies 2024, 17(22), 5663; https://doi.org/10.3390/en17225663 - 13 Nov 2024

Viewed by 297

Abstract

For low-permeability reservoirs, water-flooding development is usually adopted, which leads to induced fractures near the wellbore, increasing reservoir heterogeneity, and making water-flooding development more complex. This paper focuses on low-permeability reservoirs, considering the characteristics of induced fractures and elliptic-flow composite, and the well-test model for injection wells is established. The mathematical model in Laplace space is obtained through dimensionless transformation and Laplace transformation. Subsequently, the Mathieu function is introduced to obtain the bottom hole pressure, and the pressure response curve is drawn. The six flow stages of the curve are defined, and the sensitivity of parameters such as half-length of induced fractures, range of lateral-swept area, permeability in unswept area, and outer boundary distance at constant pressure are analyzed. The results show that the half-length of the fracture mainly affects the linear flow of the fracture, the range of the lateral wave-affected area mainly affects the radial flow of the swept area, the permeability of the unswept area mainly affects the radial flow of the unswept area, and the outer boundary distance at constant pressure mainly affects the boundary flow. Based on the production performance of a certain injection well in J Oilfield, a series of key parameters are obtained through analytical solution model inversion, including the induced-fracture half-length of 10.32 m, the lateral-swept range of elliptic partition flow of 128.95 m, the permeability of the swept area of 6.87 mD, and the mobility ratio of 119.92, which show the superiority of the analytical solution model. Full article

(This article belongs to the Special Issue Advances in Reservoir Simulation)

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16 pages, 6259 KiB

Open AccessArticle

Experimental Investigation of Fracture Propagation in Clayey Silt Hydrate-Bearing Sediments

by Yanjiang Yu, Kaixiang Shen and Haifeng Zhao

Energies 2024, 17(2), 528; https://doi.org/10.3390/en17020528 - 22 Jan 2024

Cited by 3 | Viewed by 1075

Abstract

More than 90% of the natural gas hydrate resources are reserved as marine clayey silt sediments. It is of great significance to efficiently develop a clayey silt hydrate. At present, there are problems of low single well production and small depressurization range in its production test, which is still a long way from commercial exploitation. The combination of hydraulic fracturing technology and other methods such as depressurization method is regarded as one of the potential technical means to achieve the commercial exploitation of the hydrate. However, compared with shale gas reservoirs and coalbed methane reservoirs, clayey silt hydrate reservoirs have special mechanical properties, resulting in unique hydraulic fracturing processes. Therefore, it is necessary to study the fracture initiation and propagation laws of clayey silt hydrate reservoirs. To this end, we carried out large-scale (30 × 30 × 30 cm) true triaxial hydraulic fracturing experiments using a simulated material with similar mechanics, porosity, and permeability to clayey silt hydrate-bearing sediments. The effects of completion method, fracturing method, and fracturing fluid displacement on hydraulic fracture propagation of clayey silt hydrate-bearing sediments were studied. The results showed that a perforated completion can significantly increase the fracture reconstruction area and decrease the fracture initiation pressure compared to an open hole completion. Due to the small horizontal stress difference, it is feasible to carry out temporary plugging fracturing in clayey silt hydrate reservoirs. Temporary plugging fracturing can form steering fractures and significantly improve fracture complexity and fracture area. Increasing the fracturing fluid displacement can significantly increase the fracture area as well. When conducting fracturing in clayey silt hydrate-bearing sediments, the fracturing fluid filtration area is obviously larger than the fracture propagation area. Therefore, it is recommended to use a high-viscosity fracturing fluid to reduce the filtration of the fracturing fluid and improve the fracturing fluid efficiency. This study preliminarily explores the feasibility of temporary plugging fracturing in clayey silt hydrate reservoirs and analyzes the effect of completion methods on the propagation of fracturing fractures, which can provide a reference for the research conducted on the fracturing stimulation of clayey silt hydrate reservoirs. Full article

(This article belongs to the Special Issue Advances in Reservoir Simulation)

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23 pages, 11454 KiB

Open AccessArticle

Four-Dimensional History Matching Using ES-MDA and Flow-Based Distance-to-Front Measurement

by Eduardo Barrela, Philippe Berthet, Mario Trani, Olivier Thual and Corentin Lapeyre

Energies 2023, 16(24), 7984; https://doi.org/10.3390/en16247984 - 9 Dec 2023

Viewed by 931

Abstract

The use of 4D seismic data in history matching has been a topic of great interest in the hydrocarbon industry as it can provide important information regarding changes in subsurfaces caused by fluid substitution and other factors where well data is not available. However, the high dimensionality and uncertainty associated with seismic data make its integration into the history-matching process a challenging task. Methods for adequate data reduction have been proposed in the past, but most address 4D information mismatch from a purely mathematical or image distance-based standpoint. In this study, we propose a quantitative and flow-based approach for integrating 4D seismic data into the history-matching process. By introducing a novel distance parametrization technique for measuring front mismatch information using streamlines, we address the problem from a flow-based standpoint; at the same time, we maintain the amount of necessary front data at a reduced and manageable amount. The proposed method is tested, and its results are compared on a synthetic case against another traditional method based on the Hausdorff distance. The effectiveness of the method is also demonstrated on a semi-synthetic model based on a real-case scenario, where the standard Hausdorff methodology could not be applied due to high data dimensionality. Full article

(This article belongs to the Special Issue Advances in Reservoir Simulation)

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21 pages, 8966 KiB

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A Physics-Informed Neural Network Approach for Surrogating a Numerical Simulation of Fractured Horizontal Well Production Prediction

by Taiyu Jin, Yang Xia and Haolin Jiang

Energies 2023, 16(24), 7948; https://doi.org/10.3390/en16247948 - 7 Dec 2023

Viewed by 1169

Abstract

With the popularity of deep learning (DL), more and more studies are focusing on replacing time-consuming numerical simulations with efficient surrogate models to predict the production of multi-stage fractured horizontal wells. Previous studies on constructing surrogate models for the prediction of the production of fractured horizontal wells often relied on directly applying existing deep learning architectures without incorporating physical constraints into the model. When dealing with the large number of variables necessary for characterizing the properties of fractures, the input variables of proxy models are often oversimplified; meanwhile, lots of physical information is lost. Consequently, predictions are sometimes physically inconsistent with the underlying principles of the domain. In this study, by modifying the traditional Seq2Seq (LSTM–LSTM) deep learning architecture, a physics-informed encoder–decoder (PIED) architecture was developed to surrogate the numerical simulation codes for predicting the production of horizontal wells with unequal-length intersecting hydraulic fractures on a 2D plane. The encoder is a LSTM network, and the decoder consists of LSTM and fully connected layers. The attention algorithm is also applied in the Seq2Seq architecture. The PIED model’s encoder is capable of extracting the physical information related to fractures. And the attention module effectively passes on the most relevant physical information related to production to the decoder during the training process. By modifying Seq2Seq architecture, the decoder of the PIED incorporates the intermediate input, which is the constant production time, along with the extracted physical information to predict production values. The PIED model excels in extracting sufficient physical information from high-dimensional inputs while ensuring the integrity of the production time information. By considering the physical constraints, the model predicts production values with improved accuracy and generalization capabilities. In addition, a multi-layer perceptron (MLP) which is broadly used as a proxy model; a regular Seq2Seq model (LSTM–Attention–LSTM); and the PIED were compared via a case study, and their MAE values were shown to be 241.76, 184.07, 168.81, respectively. Therefore, the proposed model has higher accuracy and better generalization ability. In the case study, a comparative experiment was conducted by comparing LSTM–MLP (with an MAE of 221.50) and LSTM–LSTM to demonstrate that using LSTM as the decoder structure is better for predicting production series. Moreover, in the task of predicting production sequences, LSTM outperforms MLP. The Seq2Seq architecture demonstrated excellent performance in this problem, and it achieved a 48.4% reduction in MSE compared to MLP. Meanwhile, the time cost for build datasets was considered, and the proposed model was found to be capable of training in a small dataset (e.g., in the case study, 3 days were used to generate 450 samples for training.); thus, the proposed model has a certain degree of practicality. Full article

(This article belongs to the Special Issue Advances in Reservoir Simulation)

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17 pages, 3945 KiB

Open AccessArticle

Failure Mechanism of Integrity of Cement Sheath under the Coupling Effect of Formation Creep and Temperature during the Operation of Salt Rock Gas Storage

by Heng Yang, Yuhuan Bu, Shaorui Jing, Shenglai Guo and Huajie Liu

Energies 2023, 16(20), 7089; https://doi.org/10.3390/en16207089 - 13 Oct 2023

Cited by 1 | Viewed by 1060

Abstract

Maintaining the integrity of the cement sheath is essential for the sealing of underground gas storage. The formation creep, temperature changes, and operating pressure changes during the operation of underground gas storage can cause changes in the stress of the cement sheath, which probably induces the failure of the cement sheath’s integrity. A creep model taking the effects of stress and temperature into account is developed to study the cement sheath’s integrity in creep formation, and the feasibility of creep simulation via finite element method is verified. The finite element method is used to analyze the effects of formation creep, temperature, operating pressure, and the cement sheath’s elastic modulus on the cement sheath’s integrity. The result shows that the coupling effect of formation creep and temperature increases the cement sheath’s failure risk; both the formation creep and the decrease in cement sheath temperature increase the Von Mises stress on the cement sheath, increasing the risk of the cement sheath’s shear failure. The decrease in cement sheath temperature decreases the circumferential compressive stress on the cement sheath and raises the risk of the cement sheath’s tensile failure. Shear failure of the cement sheath occurs at high operating pressure upper limits. The operating pressure is less than 70 MPa, or the cement sheath’s elastic modulus is less than 3 GPa, which can prevent the failure of the cement sheath’s integrity during the operation of underground gas storage. Full article

(This article belongs to the Special Issue Advances in Reservoir Simulation)

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19 pages, 7395 KiB

Open AccessArticle

Rock Typing Approaches for Effective Complex Carbonate Reservoir Characterization

by Sergey Krivoshchekov, Alexander Kochnev, Nikita Kozyrev, Andrey Botalov, Olga Kochneva and Evgeny Ozhgibesov

Energies 2023, 16(18), 6559; https://doi.org/10.3390/en16186559 - 12 Sep 2023

Cited by 5 | Viewed by 1908

Abstract

For highly heterogeneous complex carbonate reef reservoirs, rock typing with respect to depositional conditions, secondary processes, and permeability and porosity relationships is a useful tool to improve reservoir characterization, modeling, prediction of reservoir volume properties, and estimation of reserves. A review of various rock typing methods has been carried out. The basic methods of rock typing were applied to a carbonate reservoir as an example. The advantages and disadvantages of the presented methods are described. A rock typing method based on a combination of hydraulic flow units and the R35 method is proposed. Clustering methods for rock typing are used. The optimum clustering method is identified, and for each rock type, the permeability–porosity relationships are built and proposed for use in the geomodelling stage. Full article

(This article belongs to the Special Issue Advances in Reservoir Simulation)

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26 pages, 11591 KiB

Open AccessArticle

A Coupled Poro-Elastic Fluid Flow Simulator for Naturally Fractured Reservoirs

by Reda Abdel Azim, Saad Alatefi and Ahmad Alkouh

Energies 2023, 16(18), 6476; https://doi.org/10.3390/en16186476 - 7 Sep 2023

Cited by 2 | Viewed by 1050

Abstract

Naturally fractured reservoirs are characterized by their complex nature due to the existence of natural fractures and fissures within the rock formations. These fractures can significantly impact the flow of fluids within the reservoir, making it difficult to predict and manage production. Therefore, efficient production from such reservoirs requires a deep understanding of the flow behavior via the integration of various geological, geophysical, and engineering data. Additionally, advanced simulation models can be used to predict reservoir behavior under different production scenarios and aid in decision making and effective management. Accordingly, this study presents a robust mathematical two-phase fluid flow model (FRACSIM) for the simulation of the flow behavior of naturally fractured reservoirs in a 3D space. The mathematical model is based on the finite element technique and implemented using the FORTRAN language within a poro-elastic framework. Fractures are represented by triangle elements, while tetrahedral elements represent the matrix. To optimize computational time, short to medium-length fractures adopt the permeability tensor approach, while large fractures are discretized explicitly. The governing equations for poro-elasticity are discretized in both space and time using a standard Galerkin-based finite element approach. The stability of the saturation equation solution is ensured via the application of the Galerkin discretization method. The 3D fracture model has been verified against Eclipse 100, a commercial software, via a well-test case study of a fractured basement reservoir to ensure its effectiveness. Additionally, the FRACSIM software successfully simulated a laboratory glass bead drainage test for two intersected fractures and accurately captured the flow pattern and cumulative production results. Furthermore, a sensitivity study of water injection using an inverted five-spot technique was tested on FRACSIM to assess the productivity of drilled wells in complex fractured reservoirs. The results indicate that FRACSIM can accurately predict flow behavior and subsequently be utilized to evaluate production performance in naturally fractured reservoirs. Full article

(This article belongs to the Special Issue Advances in Reservoir Simulation)

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16 pages, 4974 KiB

Open AccessArticle

Testing the INSIM-FT Proxy Simulation Method

by Mkhitar Ovsepian, Egor Lys, Alexander Cheremisin, Stanislav Frolov, Rustam Kurmangaliev, Eduard Usov, Vladimir Ulyanov, Dmitry Tailakov and Nikita Kayurov

Energies 2023, 16(4), 1648; https://doi.org/10.3390/en16041648 - 7 Feb 2023

Cited by 1 | Viewed by 1512

Abstract

This paper describes testing of the INSIM-FT proxy simulation method (interwell-numerical-simulation model improved with front-tracking method) to assess the dependencies between production and injection wells, as well as to assess the forecast of oil/liquid production by wells depending on their operation parameters. The paper proposes the approach of taking into account the influence of various production enhancement operations. The method was tested on a synthetic hydrodynamic model and on a sector of a real field. The results show a good match between historical data and simulation results and indicate significant computational efficiency compared to classical reservoir simulators. Full article

(This article belongs to the Special Issue Advances in Reservoir Simulation)

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23 pages, 11724 KiB

Open AccessArticle

A Fully Coupled Hydro-Mechanical Approach for Multi-Fracture Propagation Simulations

by Yinghao Deng, Di Wang, Yan Jin and Yang Xia

Energies 2023, 16(4), 1601; https://doi.org/10.3390/en16041601 - 5 Feb 2023

Cited by 2 | Viewed by 1731

Abstract

Hydraulic fracturing is a complex nonlinear hydro-mechanical coupled process. Accurate numerical simulation is of great significance for reducing fracturing costs and improving reservoir development benefits. The aim of this paper is to propose an efficient numerical simulation method for the fracturing-to-production problem under a unified framework that has good convergence and accuracy. A hydro-mechanical coupled fracturing model (HMFM) is established for poroelastic media saturated with a compressible fluid, and the local characteristics of the physical field are fully considered. Each fracture is explicitly characterized using the discrete fracture model (DFM), which can better reflect the physical characteristics near fractures. Based on the extended finite element method (XFEM) and the Newton–Raphson method, a fully coupled approach named Unified Extended Finite Element (UXFEM) is developed, which can solve the nonlinear system of equations that describe the solution under a unified framework. UXFEM can accurately capture the local physical characteristics of different physical fields on the orthogonal structured grids. It realizes the grid-fracture decoupling, and fractures can propagate in any direction, which shows greater flexibility in simulating fracture propagation. The fully coupled approach can better reflect the essential relationship between pressure, stress, and fracture, which is beneficial to studying hydro-mechanical coupled problems. To validate the UXFEM, UXFEM is compared with the classical KGD model, analytic solution, and COMSOL solution. Finally, based on UXFEM, the interference phenomenon and fracturing-to-production study are carried out to prove the broad practical application prospect of this new fully coupled approach. Full article

(This article belongs to the Special Issue Advances in Reservoir Simulation)

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12 pages, 4664 KiB

Open AccessArticle

Development of Virtual Flow-Meter Concept Techniques for Ground Infrastructure Management

by Ruslan Vylegzhanin, Alexander Cheremisin, Boris Kolchanov, Pavel Lykhin, Rustam Kurmangaliev, Mikhail Kozlov, Eduard Usov and Vladimir Ulyanov

Energies 2023, 16(1), 400; https://doi.org/10.3390/en16010400 - 29 Dec 2022

Viewed by 1298

Abstract

This paper describes the further development of the virtual flow meter concept based on the author’s simulator of an unsteady gas–liquid flow in wells. The results of comparison with commercial simulators based on real well data are given as practical applications. The results of the comparison of the simulators demonstrated high correspondence (<10% error) for a number of target parameters. The description of the architecture and results of testing the algorithm for automatic settings of the model parameters are given. Operating speed was the key criterion in the architecture development. According to the test results, it became possible to achieve the adaptation accuracy of 5% specified. Full article

(This article belongs to the Special Issue Advances in Reservoir Simulation)

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22 pages, 30688 KiB

Open AccessArticle

Joint History Matching of Multiple Types of Field Data in a 3D Field-Scale Case Study

by William Chalub Cruz, Xiaodong Luo and Kurt Rachares Petvipusit

Energies 2022, 15(17), 6372; https://doi.org/10.3390/en15176372 - 31 Aug 2022

Cited by 4 | Viewed by 1736

Abstract

This work presents an ensemble-based workflow to simultaneously assimilate multiple types of field data in a proper and consistent manner. The aim of using multiple field datasets is to improve the reliability of estimated reservoir models and avoid the underestimation of uncertainties. The proposed framework is based on an integrated history matching workflow, in which reservoir models are conditioned simultaneously on production, tracer and 4D seismic data with the help of three advanced techniques: adaptive localization (for better uncertainty quantification), weight adjustment (for balancing the influence of different types of field data), and sparse data representation (for handling big datasets). The integrated workflow is successfully implemented and tested in a 3D benchmark case with a set of comparison studies (with and without tracer data). The findings of this study indicate that joint history matching using production, tracer and 4D seismic data results in better estimated reservoir models and improved forecast performance. Moreover, the integrated workflow is flexible, and can be extended to incorporate more types of field data for further performance improvement. As such, the findings of this study can help to achieve a better understanding of the impacts of multiple datasets on history matching performance, and the proposed integrated workflow could serve as a useful tool for real field case studies in general. Full article

(This article belongs to the Special Issue Advances in Reservoir Simulation)

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