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Open AccessEditorial

Editorial on Special Issues of Development of Unconventional Reservoirs

by Reza Rezaee

Energies 2022, 15(7), 2617; https://doi.org/10.3390/en15072617 - 3 Apr 2022

Cited by 3 | Viewed by 2027

Abstract

The energy transition to renewable energy is inevitable since fossil fuels are a finite source [...] Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2021)

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Research

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30 pages, 13876 KiB

Open AccessEditor’s ChoiceArticle

Ensemble Learning for Predicting TOC from Well-Logs of the Unconventional Goldwyer Shale

by Partha Pratim Mandal, Reza Rezaee and Irina Emelyanova

Energies 2022, 15(1), 216; https://doi.org/10.3390/en15010216 - 29 Dec 2021

Cited by 13 | Viewed by 2219

Abstract

Precise estimation of total organic carbon (TOC) is extremely important for the successful characterization of an unconventional shale reservoir. Indirect traditional continuous TOC prediction methods from well-logs fail to provide accurate TOC in complex and heterogeneous shale reservoirs. A workflow is proposed to [...] Read more.

Precise estimation of total organic carbon (TOC) is extremely important for the successful characterization of an unconventional shale reservoir. Indirect traditional continuous TOC prediction methods from well-logs fail to provide accurate TOC in complex and heterogeneous shale reservoirs. A workflow is proposed to predict a continuous TOC profile from well-logs through various ensemble learning regression models in the Goldwyer shale formation of the Canning Basin, WA. A total of 283 TOC data points from ten wells is available from the Rock-Eval analysis of the core specimen where each sample point contains three to five petrophysical logs. The core TOC varies largely, ranging from 0.16 wt % to 4.47 wt % with an average of 1.20 wt %. In addition to the conventional MLR method, four supervised machine learning methods, i.e., ANN, RF, SVM, and GB are trained, validated, and tested for continuous TOC prediction using the ensemble learning approach. To ensure robust TOC prediction, an aggregated model predictor is designed by combining the four ensemble-based models. The model achieved estimation accuracy with R² value of 87%. Careful data preparation and feature selection, reconstruction of corrupted or missing logs, and the ensemble learning implementation and optimization have improved TOC prediction accuracy significantly compared to a single model approach. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2021)

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14 pages, 4676 KiB

Open AccessArticle

Numerical Demonstration of an Unconventional EGS Arrangement

by George L. Danko and M. K. Baracza

Energies 2022, 15(1), 20; https://doi.org/10.3390/en15010020 - 21 Dec 2021

Cited by 6 | Viewed by 2348

Abstract

A new EGS arrangement, Robust EGS (REGS), is studied for its potential benefits for wide-spread applications for clean, carbon-free, electrical energy generation. Numerical simulations are carried out to prove the key benefit of REGS in a simple, but effective, geologic heat exchanger arrangement [...] Read more.

A new EGS arrangement, Robust EGS (REGS), is studied for its potential benefits for wide-spread applications for clean, carbon-free, electrical energy generation. Numerical simulations are carried out to prove the key benefit of REGS in a simple, but effective, geologic heat exchanger arrangement with large, stabilized fracture aperture and controlled flow zones. The numerical model results show the estimated potential energy capacity and the converted value to electrical energy generation over a 30-year operation time period for two simple REGS arrangements. The results may assist EGS investors and drilling companies in deciding whether the investment and operation can be made profitable for the wide-scale application of REGS for green energy generation. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2021)

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24 pages, 88896 KiB

Open AccessArticle

Stratigraphically Controlled Stress Variations at the Hydraulic Fracture Test Site-1 in the Midland Basin, TX

by Arjun Kohli and Mark Zoback

Energies 2021, 14(24), 8328; https://doi.org/10.3390/en14248328 - 10 Dec 2021

Cited by 14 | Viewed by 3297

Abstract

We investigated the relationship between stratigraphy, stress, and microseismicity at the Hydraulic Fracture Test Site-1. The site comprises two sets of horizontal wells in the Wolfcamp shale and a deviated well drilled after hydraulic fracturing. Regional stresses indicate normal/strike-slip faulting with E-W compression. [...] Read more.

We investigated the relationship between stratigraphy, stress, and microseismicity at the Hydraulic Fracture Test Site-1. The site comprises two sets of horizontal wells in the Wolfcamp shale and a deviated well drilled after hydraulic fracturing. Regional stresses indicate normal/strike-slip faulting with E-W compression. Stress measurements in vertical and horizontal wells show that the minimum principal stress varies with depth. Strata with high clay and organic content show high values of the least compressive stress, consistent with the theory of viscous stress relaxation. By integrating data from core, logs, and the hydraulic fracturing stages, we constructed a stress profile for the Wolfcamp sequence, which predicts how much pressure is required for hydraulic fracture growth. We applied the results to fracture orientation data from image logs to determine the population of pre-existing faults that are expected to slip during stimulation. We also determined microseismic focal plane mechanisms and found slip on steeply dipping planes striking NW, consistent with the orientations of potentially active faults predicted by the stress model. This case study represents a general approach for integrating stress measurements and rock properties to predict hydraulic fracture growth and the characteristics of injection-induced microseismicity. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2021)

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15 pages, 1968 KiB

Open AccessArticle

A Prediction Model of Pressure Loss of Cement Slurry in Deep-Water HTHP Directional Wells

by Kunhong Lv, Hao Huang, Xingqiang Zhong, Yian Tong, Xingjie Ling and Qiao Deng

Energies 2021, 14(23), 8180; https://doi.org/10.3390/en14238180 - 6 Dec 2021

Cited by 4 | Viewed by 1835

Abstract

The exploitations of deep-water wells often use directional well drilling to reach the target layer. Affected by special environments in deep water, the prediction of pressure loss of cement slurry is particularly important. This paper presents a prediction model of pressure loss suitable [...] Read more.

The exploitations of deep-water wells often use directional well drilling to reach the target layer. Affected by special environments in deep water, the prediction of pressure loss of cement slurry is particularly important. This paper presents a prediction model of pressure loss suitable for deep-water directional wells. This model takes the complex interaction between the temperature, pressure and hydration kinetics of cement slurry into account. Based on the initial and boundary conditions, the finite difference method is used to discretize and calculate the model to ensure the stability and convergence of the result calculated by this model. Finally, the calculation equation of the model is used to predict the transient temperature and pressure loss of Wells X1 and X2, and a comparison is made between the predicted value and the monitoring data. The comparison results show that the maximum error between the temperature and pressure predicted by the model and the field measured value is within 6%. Thus, this model is of high accuracy and can meet the needs of site construction. It is concluded that this result can provide reliable theoretical guidance for temperature and pressure prediction, as well as the anti-channeling design of HTHP directional wells. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2021)

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17 pages, 5835 KiB

Open AccessArticle

Seismostratigraphic Interpretation of Upper Cretaceous Reservoir from the Carpathian Foreland, Southern Poland

by Andrzej Urbaniec, Anna Łaba-Biel, Anna Kwietniak and Imoleayo Fashagba

Energies 2021, 14(22), 7776; https://doi.org/10.3390/en14227776 - 19 Nov 2021

Cited by 9 | Viewed by 1948

Abstract

The Upper Cretaceous complex in the central part of the Carpathian Foreland (southern Poland) is relatively poorly recognized and described. Its formations can be classified as unconventional reservoir due to poor reservoir properties as well as a low recovery factor. The main aim [...] Read more.

The Upper Cretaceous complex in the central part of the Carpathian Foreland (southern Poland) is relatively poorly recognized and described. Its formations can be classified as unconventional reservoir due to poor reservoir properties as well as a low recovery factor. The main aim of the article is to expand knowledge with conclusions resulting from the analysis of the latest seismic data with the application of seismic sequence stratigraphy. Moreover, the seismic attributes analysis was utilized. The depositional architecture recognition based on both chronostratigraphic horizons and Wheeler diagram interpretations was of paramount importance. A further result was the possibility of using the chronostratigraphic image for tectonostratigraphic interpretation. Two distinguished tectonostratigraphic units corresponding to megasequences were recognized. A tectonic setting of the analyzed interval is associated with global processes noticed by other authors in other parts of the central European Late Cretaceous basin, but also locally accompanied by evidence of small-scale tectonics. This study fills the gap on the issue of paleogeography in the Late Cretaceous sedimentary basin of the Carpathian Foreland. It presents the first results of detailed reconstruction of the basin paleogeography and an attempt to determine the impact of both eustatic and tectonic factors on sedimentation processes. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2021)

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16 pages, 3949 KiB

Open AccessArticle

Study on the Mechanical Extended-Reach Limit Prediction Model of Horizontal Drilling with Dual-Channel Drillpipes

by Tianyi Tan and Hui Zhang

Energies 2021, 14(22), 7732; https://doi.org/10.3390/en14227732 - 18 Nov 2021

Cited by 1 | Viewed by 1675

Abstract

Extended-reach horizontal wells are critical for the development of unconventional reservoirs. Dual-channel drill pipe drilling has a great advantage in improving the horizontal section length, while the research on its mechanical extended-reach limit prediction model is insufficient. In this paper, the torque and [...] Read more.

Extended-reach horizontal wells are critical for the development of unconventional reservoirs. Dual-channel drill pipe drilling has a great advantage in improving the horizontal section length, while the research on its mechanical extended-reach limit prediction model is insufficient. In this paper, the torque and drag model is built considering the additional axial force of the sliding piston on the dual-channel drillpipe. Based on the torque and drag model, the mechanical extended-reach limit model for dual-channel drilling is established. A case study including a comparison to the conventional drilling method and sensitivity analysis is conducted. The result shows that under the same conditions, the mechanical extended-reach limit of the dual-channel drilling method is 10,592.2 m, while it is 9030.6 m of the conventional drilling method. The dual-channel drilling method achieves a further mechanical extended-reach limit than the conventional drilling method. To improve the mechanical extended-reach limit of dual-channel drilling, a higher back pressure on the sliding piston, a deeper measured depth of the sliding piston, a higher density of the passive drilling fluid, a smaller outer diameter of the outer pipe, a lower weight on bit and rate of penetration should be adopted. The work in this paper completes the extended-reach limit theory of dual-channel drilling, providing a guide for better use in unconventional reservoir development. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2021)

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19 pages, 2396 KiB

Open AccessArticle

The Effect of Hydraulic Fracture Geometry on Well Productivity in Shale Oil Plays with High Pore Pressure

by Daniela A. Arias Ortiz, Lukasz Klimkowski, Thomas Finkbeiner and Tadeusz W. Patzek

Energies 2021, 14(22), 7727; https://doi.org/10.3390/en14227727 - 18 Nov 2021

Cited by 8 | Viewed by 2811

Abstract

We propose three idealized hydraulic fracture geometries (“fracture scenarios”) likely to occur in shale oil reservoirs characterized by high pore pressure and low differential in situ stresses. We integrate these geometries into a commercial reservoir simulator (CMG-IMEX) and examine their effect on reservoir [...] Read more.

We propose three idealized hydraulic fracture geometries (“fracture scenarios”) likely to occur in shale oil reservoirs characterized by high pore pressure and low differential in situ stresses. We integrate these geometries into a commercial reservoir simulator (CMG-IMEX) and examine their effect on reservoir fluids production. Our first, reference fracture scenario includes only vertical, planar hydraulic fractures. The second scenario has stimulated vertical natural fractures oriented perpendicularly to the vertical hydraulic fractures. The third fracture scenario has stimulated horizontal bedding planes intersecting the vertical hydraulic fractures. This last scenario may occur in mudrock plays characterized by high pore pressure and transitional strike-slip to reverse faulting stress regimes. We demonstrate that the vertical and planar fractures are an oversimplification of the hydraulic fracture geometry in anisotropic shale plays. They fail to represent the stimulated volume geometric complexity in the reservoir simulations and may confuse hydrocarbon production forecast. We also show that stimulating mechanically weak bedding planes harms hydrocarbon production, while stimulated natural fractures may enhance initial production. Our findings reveal that stimulated horizontal bedding planes might decrease the cumulative hydrocarbon production by as much as 20%, and the initial hydrocarbon production by about 50% compared with the reference scenario. We present unique reservoir simulations that enable practical assessment of the impact of varied hydraulic fracture configurations on hydrocarbon production and highlight the importance of constraining present-day in situ stress state and pore pressure conditions to obtain a realistic hydrocarbon production forecast. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2021)

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14 pages, 13167 KiB

Open AccessArticle

Design and Evaluation of High-Temperature Well Cementing Slurry System Based on Fractal Theory

by Guanyi Zheng, Xiaoyang Guo, Zaoyuan Li and Jinfei Sun

Energies 2021, 14(22), 7552; https://doi.org/10.3390/en14227552 - 12 Nov 2021

Cited by 4 | Viewed by 2575

Abstract

The efficient development of oil and gas resources is inseparable from the progress of drilling technology and the safety of the long life cycle of wellbore. At present, exploration and development is expanding to deep and ultra-deep areas. The long life cycle safety [...] Read more.

The efficient development of oil and gas resources is inseparable from the progress of drilling technology and the safety of the long life cycle of wellbore. At present, exploration and development is expanding to deep and ultra-deep areas. The long life cycle safety of deep and ultra-deep wells is mainly realized by the sealing performance of cement slurry. Additionally, the accumulation degree of cement slurry particles is closely related to sealing performance. Based on fractal theory, an accumulation model of continuous distribution of additive material particles was designed, which can determine the range of fractal dimension necessary to realize the tight stacking and guide the proportion of solid admixture. The formulation of high temperature-resistant cement slurry was prepared by designing the ratio of solid admixture and optimizing the high temperature-resistant liquid admixture. The evaluation of engineering and temperature resistance of the cement slurry proves the rationality of the accumulation model, which can be applied to the design of a high temperature cementing slurry system in deep and ultra-deep wells. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2021)

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16 pages, 4098 KiB

Open AccessArticle

Cyclic Subcritical Water Injection into Bazhenov Oil Shale: Geochemical and Petrophysical Properties Evolution Due to Hydrothermal Exposure

by Aman Turakhanov, Albina Tsyshkova, Elena Mukhina, Evgeny Popov, Darya Kalacheva, Ekaterina Dvoretskaya, Anton Kasyanenko, Konstantin Prochukhan and Alexey Cheremisin

Energies 2021, 14(15), 4570; https://doi.org/10.3390/en14154570 - 28 Jul 2021

Cited by 13 | Viewed by 2226

Abstract

In situ shale or kerogen oil production is a promising approach to developing vast oil shale resources and increasing world energy demand. In this study, cyclic subcritical water injection in oil shale was investigated in laboratory conditions as a method for in situ [...] Read more.

In situ shale or kerogen oil production is a promising approach to developing vast oil shale resources and increasing world energy demand. In this study, cyclic subcritical water injection in oil shale was investigated in laboratory conditions as a method for in situ oil shale retorting. Fifteen non-extracted oil shale samples from Bazhenov Formation in Russia (98 °C and 23.5 MPa reservoir conditions) were hydrothermally treated at 350 °C and in a 25 MPa semi-open system during 50 h in the cyclic regime. The influence of the artificial maturation on geochemical parameters, elastic and microstructural properties was studied. Rock-Eval pyrolysis of non-extracted and extracted oil shale samples before and after hydrothermal exposure and SARA analysis were employed to analyze bitumen and kerogen transformation to mobile hydrocarbons and immobile char. X-ray computed microtomography (XMT) was performed to characterize the microstructural properties of pore space. The results demonstrated significant porosity, specific pore surface area increase, and the appearance of microfractures in organic-rich layers. Acoustic measurements were carried out to estimate the alteration of elastic properties due to hydrothermal treatment. Both Young’s modulus and Poisson’s ratio decreased due to kerogen transformation to heavy oil and bitumen, which remain trapped before further oil and gas generation, and expulsion occurs. Ultimately, a developed kinetic model was applied to match kerogen and bitumen transformation with liquid and gas hydrocarbons production. The nonlinear least-squares optimization problem was solved during the integration of the system of differential equations to match produced hydrocarbons with pyrolysis derived kerogen and bitumen decomposition. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2021)

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14 pages, 4687 KiB

Open AccessFeature PaperArticle

Characteristics of Mineralogy, Lithofacies of Fine-Grained Sediments and Their Relationship with Sedimentary Environment: Example from the Upper Permian Longtan Formation in the Sichuan Basin

by Hongzhi Yang, Liangbiao Lin, Liqing Chen, Yu Yu, Du Li, Jingchun Tian, Wen Zhou and Jianhua He

Energies 2021, 14(12), 3662; https://doi.org/10.3390/en14123662 - 19 Jun 2021

Cited by 11 | Viewed by 2157

Abstract

The Longtan Formation of the Upper Permian in the Sichuan Basin has become a significant target for shale gas exploration in recent years. Multiple methods, including outcrop observations, thin sections, total organic matter content, X-ray diffraction and scanning electron microscopy were used to [...] Read more.

The Longtan Formation of the Upper Permian in the Sichuan Basin has become a significant target for shale gas exploration in recent years. Multiple methods, including outcrop observations, thin sections, total organic matter content, X-ray diffraction and scanning electron microscopy were used to investigate the mineralogy, shale lithofacies assemblages and their relationships with the deposition environment. The mineral composition of the Longtan Formation has strong mineral heterogeneity. The TOC values of the Longtan Formation have a wide distribution range from 0.07% to 74.67% with an average value of 5.73%. Four types of shale lithofacies assemblages of the Longtan Formation could be distinguished, as clayey mudstone (CLS), carbonaceous shale (CAS), siliceous shale (SS) and mixed shale (MS) on the basis of mineral compositions. The TOC values of various types of shale lithofacies assemblages in the Longtan Formation varied widely. The shore swamp of the Longtan Formation is most influenced by the terrestrial input and mainly develops CLS and MS. The tidal flat is influenced by the terrestrial input and can also deposit carbonate minerals, developing CLS, CAS and MS. The shallow water melanged accumulation shelf develops CAS and MS, dominated by clay and carbonate minerals. The deep water miscible shelf develops CLS and SS, whose mineral composition is similar to that of the shore swamp, but the quartz minerals are mainly formed by chemical and biological reactions, which are related to the Permian global chert event. The depositional environment of the Longtan Formation controls the shale mineral assemblage of the Longtan Formation and also influences the TOC content. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2021)

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18 pages, 4171 KiB

Open AccessArticle

A Novel Mathematical Model Considering Real Gas PVT Behavior to Estimate Inflow Performance Relationship of Gas Well Production

by Shuang Zhang, Huiqing Liu, Yanwei Wang, Ke Sun and Yunfei Guo

Energies 2021, 14(12), 3594; https://doi.org/10.3390/en14123594 - 16 Jun 2021

Cited by 2 | Viewed by 2931

Abstract

Inflow performance relationship (IPR) is one of the most important methods for the analysis of the dynamic characteristics of gas reservoir production. The objective of this study was to develop a model to improve the accuracy of the IPR for evaluating and predicting [...] Read more.

Inflow performance relationship (IPR) is one of the most important methods for the analysis of the dynamic characteristics of gas reservoir production. The objective of this study was to develop a model to improve the accuracy of the IPR for evaluating and predicting the production of gas reservoirs. In this paper, a novel mathematical model, taking into account the real gas PVT behavior, is developed to accurately estimate the inflow performance relationship. By introducing a pseudo-pressure function and a real gas properties database, this model eliminates the error caused by the linearization method and improves the calculation accuracy. The results show that more than 90% of the energy in the flow field is consumed by inertial forces, which leads to significant high-velocity non-Darcy effects in the gas reservoir. The reservoir permeability, original reservoir pressure, stress sensitivity coefficient, and skin factor have a great impact on the inflow performance relationship of gas reservoir production. This model predicts gas IPR curves with excellent accuracy and high efficiency. The high-precision gas well inflow performance relationship lays a solid foundation for dynamic production analysis, rational proration, and intelligent development of the gas field. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2021)

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20 pages, 2834 KiB

Open AccessArticle

Study on Annular Pressure Buildup in Offshore Heavy Oil Thermal Recovery Wells Considering Dissolved Gas Contained in Annuli

by Hao Wang, Hui Zhang, Jun Li, Anming Chen, Jun Liu, Tengfei Sun and Cong Lin

Energies 2021, 14(11), 3213; https://doi.org/10.3390/en14113213 - 31 May 2021

Cited by 5 | Viewed by 3177

Abstract

In the offshore industry, especially heavy oil thermal recovery wells, due to the great temperature difference between the low-temperature seawater and high-temperature heavy oil, it is easy to cause the temperature increase of annular fluid in the operation process which will result in [...] Read more.

In the offshore industry, especially heavy oil thermal recovery wells, due to the great temperature difference between the low-temperature seawater and high-temperature heavy oil, it is easy to cause the temperature increase of annular fluid in the operation process which will result in the annular pressure buildup phenomenon (APB). The increase of annulus pressure may lead to the failure of the casing and wellbore integrity, which will seriously affect the normal production and lead to great economic loss. In order to study the formation of APB and provide a basis for the field operation design, a radial full-size physical experiment of APB was carried out in this work and an annular pressure prediction model in the presence of dissolved gas was proposed based on the experimental results. The verification and comparison analyses of the full-liquid model and the dissolved gas model were conducted with the experimental data. Furthermore, the sensitivity analysis of the influence of the dissolved gas volume fraction and casing deformation on APB was carried out. The results show that the prediction results calculated by the dissolved gas model are in good agreement with the experimental data and the prediction accuracy is higher than that of the full-liquid model. When the annular dissolved gas volume fraction is less than 0.1%, the full-liquid model can be used to simplify and approximate calculations. Ignoring casing deformation will produce prediction error in each annulus, which means this simplification should be used with extreme caution. This work provides a valuable experimental reference for the study of APB, as well as a novel model for APB prediction in the field. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2021)

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22 pages, 8867 KiB

Open AccessArticle

Numerical Investigation on Shape Optimization of Small-Spacing Twin-Well for Salt Cavern Gas Storage in Ultra-Deep Formation

by Haitao Li, Jingen Deng, Qiqi Wanyan, Yongcun Feng, Arnaud Regis Kamgue Lenwoue, Chao Luo and Cheng Hui

Energies 2021, 14(10), 2859; https://doi.org/10.3390/en14102859 - 15 May 2021

Cited by 11 | Viewed by 2667

Abstract

Small-spacing twin-well (SSTW) salt caverns have an extensive application prospect in thin or bedded rock salt formations due to their good performance, while they are rarely used in ultra-deep formations. The target strata depth of Pingdingshan salt mine is over 1700 m, and [...] Read more.

Small-spacing twin-well (SSTW) salt caverns have an extensive application prospect in thin or bedded rock salt formations due to their good performance, while they are rarely used in ultra-deep formations. The target strata depth of Pingdingshan salt mine is over 1700 m, and it is planned to apply an SSTW cavern to construct the underground gas storage (UGS). A 3D geomechanical model considering the viscoelastic plasticity of the rock mass is introduced into Flac^3D to numerically study the influence of internal gas pressure, cavern upper shape and well spacing on the stability of an SSTW salt cavern for Pingdingshan UGS. A set of assessment indices is summarized for the stability of gas storage. The results show that the minimum internal gas pressure is no less than 14 MPa, and the cavern should not be operated under constant low gas pressure for a long time. The cavern with an upper height of 70 m is recommended for Pingdingshan gas storage based on the safety evaluation and maximum volume. The well spacing has a limited influence on the stability of the salt cavern in view of the volume shrinkage and safety factor. Among the values of 10 m, 20 m and 30 m, the well spacing of 20 m is recommended for Pingdingshan gas storage. In addition, when the cavern groups are constructed, the pillar width on the short axis should be larger than that on the long axis due to its greater deformation in this direction. This study provides a design reference for the construction of salt cavern gas storage in ultra-deep formations with the technology of SSTW. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2021)

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