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16 pages, 2794 KiB

Open AccessArticle

A Critical Review of Osmosis-Associated Imbibition in Unconventional Formations

by Zhou Zhou, Xiaopeng Li and Tadesse Weldu Teklu

Energies 2021, 14(4), 835; https://doi.org/10.3390/en14040835 - 5 Feb 2021

Cited by 12 | Viewed by 3251

Abstract

In petroleum engineering, imbibition is one of the most important elements for the hydraulic fracturing and water flooding processes, when extraneous fluids are introduced to the reservoir. However, in unconventional shale formations, osmosis has been often overlooked, but it can influence the imbibition [...] Read more.

In petroleum engineering, imbibition is one of the most important elements for the hydraulic fracturing and water flooding processes, when extraneous fluids are introduced to the reservoir. However, in unconventional shale formations, osmosis has been often overlooked, but it can influence the imbibition process between the working fluid and the contacting formation rocks. The main objective of this study is to understand effects of fluid–rock interactions for osmosis-associated imbibition in unconventional formations. This paper summarizes previous studies on imbibition in unconventional formations, including shale, tight carbonate, and tight sandstone formations. Various key factors and their influence on the imbibition processes are discussed. Then, the causes and role of osmotic forces in fluid imbibition processes are summarized based on previous and recent field observations and laboratory measurements. Moreover, some numerical simulation approaches to model the osmosis-associated imbibition are summarized and compared. Finally, a discussion on the practical implications and field observations of osmosis-associated imbibition is included. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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15 pages, 7460 KiB

Open AccessArticle

Patent Analysis on the Development of the Shale Petroleum Industry Based on a Network of Technological Indices

by Jong-Hyun Kim and Yong-Gil Lee

Energies 2020, 13(24), 6746; https://doi.org/10.3390/en13246746 - 21 Dec 2020

Cited by 4 | Viewed by 2078

Abstract

This study investigated the technological developments in the shale petroleum industry by analyzing patent data using a network of technological indices. The technological developments were promoted by the beginning of the shale industry, and after the first five years, it showed a more [...] Read more.

This study investigated the technological developments in the shale petroleum industry by analyzing patent data using a network of technological indices. The technological developments were promoted by the beginning of the shale industry, and after the first five years, it showed a more complex development pattern with the convergence of critical technologies. This paper described progress in the shale petroleum technologies as changes in relatedness networks of technological components. The relatedness represents degree of convergence between technological components, and betweenness centrality of network represents priority of technological components. In the results, the progress of the critical technologies such as directional drilling, increasing permeability, and smart systems, were actively carried out from 2012 to 2016. Especially, unconverged technology of increasing permeability and the converged technology of directional drilling and smart system has been intensively developed. Some technological components of the critical technologies are more significant in the form of converged technology. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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13 pages, 3963 KiB

Open AccessArticle

Molecular-Scale Considerations of Enhanced Oil Recovery in Shale

by Mohamed Mehana, Qinjun Kang and Hari Viswanathan

Energies 2020, 13(24), 6619; https://doi.org/10.3390/en13246619 - 15 Dec 2020

Cited by 8 | Viewed by 2029

Abstract

With only less than 10% recovery, the primary production of hydrocarbon from shale reservoirs has redefined the energy equation in the world. Similar to conventional reservoirs, Enhanced Oil Recovery (EOR) techniques could be devised to enhance the current recovery factors. However, shale reservoirs [...] Read more.

With only less than 10% recovery, the primary production of hydrocarbon from shale reservoirs has redefined the energy equation in the world. Similar to conventional reservoirs, Enhanced Oil Recovery (EOR) techniques could be devised to enhance the current recovery factors. However, shale reservoirs possess unique characteristics that significantly affect the fluid properties. Therefore, we are adopting a molecular simulation approach that is well-suited to account for these effects to evaluate the performance of three different gases, methane, carbon dioxide and nitrogen, to recover the hydrocarbons from rough pore surfaces. Our hydrocarbon systems consists of either a single component (decane) or more than one component (decane and pentane). We simulated cases where concurrent and countercurrent displacement is studied. For concurrent displacement (injected fluids displace hydrocarbons towards the production region), we found that nitrogen and methane yielded similar recovery; however nitrogen exhibited a faster breakthrough. On the other hand, carbon dioxide was more effective in extracting the hydrocarbons when sufficient pressure was maintained. For countercurrent displacement (gases are injected and hydrocarbons are produced from the same direction), methane was found to be more effective, followed by carbon dioxide and nitrogen. In all cases, confinement reduced the recovery factor of all gases. This work provides insights to devise strategies to improve the current recovery factors observed in shale reservoirs. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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11 pages, 3633 KiB

Open AccessArticle

Research on the Estimate of Gas Hydrate Saturation Based on LSTM Recurrent Neural Network

by Chuanhui Li and Xuewei Liu

Energies 2020, 13(24), 6536; https://doi.org/10.3390/en13246536 - 11 Dec 2020

Cited by 6 | Viewed by 2272

Abstract

Gas hydrate saturation is an important index for evaluating gas hydrate reservoirs, and well logs are an effective method for estimating gas hydrate saturation. To use well logs better to estimate gas hydrate saturation, and to establish the deep internal connections and laws [...] Read more.

Gas hydrate saturation is an important index for evaluating gas hydrate reservoirs, and well logs are an effective method for estimating gas hydrate saturation. To use well logs better to estimate gas hydrate saturation, and to establish the deep internal connections and laws of the data, we propose a method of using deep learning technology to estimate gas hydrate saturation from well logs. Considering that well logs have sequential characteristics, we used the long short-term memory (LSTM) recurrent neural network to predict the gas hydrate saturation from the well logs of two sites in the Shenhu area, South China Sea. By constructing an LSTM recurrent layer and two fully connected layers at one site, we used resistivity and acoustic velocity logs that were sensitive to gas hydrate as input. We used the gas hydrate saturation calculated by the chloride concentration of the pore water as output to train the LSTM network. We achieved a good training result. Applying the trained LSTM recurrent neural network to another site in the same area achieved good prediction of gas hydrate saturation, showing the unique advantages of deep learning technology in gas hydrate saturation estimation. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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13 pages, 5520 KiB

Open AccessArticle

Porosity and Water Saturation Estimation for Shale Reservoirs: An Example from Goldwyer Formation Shale, Canning Basin, Western Australia

by Muhammad Atif Iqbal and Reza Rezaee

Energies 2020, 13(23), 6294; https://doi.org/10.3390/en13236294 - 29 Nov 2020

Cited by 19 | Viewed by 3989

Abstract

Porosity and water saturation are the most critical and fundamental parameters for accurate estimation of gas content in the shale reservoirs. However, their determination is very challenging due to the direct influence of kerogen and clay content on the logging tools. The porosity [...] Read more.

Porosity and water saturation are the most critical and fundamental parameters for accurate estimation of gas content in the shale reservoirs. However, their determination is very challenging due to the direct influence of kerogen and clay content on the logging tools. The porosity and water saturation over or underestimate the reserves if the corrections for kerogen and clay content are not applied. Moreover, it is very difficult to determine the formation water resistivity (R_w) and Archie parameters for shale reservoirs. In this study, the current equations for porosity and water saturation are modified based on kerogen and clay content calibrations. The porosity in shale is composed of kerogen and matrix porosities. The kerogen response for the density porosity log is calibrated based on core-based derived kerogen volume. The kerogen porosity is computed by a mass-balance relation between the original total organic carbon (TOC_o) and kerogen maturity derived by the percentage of convertible organic carbon (Cc) and the transformation ratio (TR). Whereas, the water saturation is determined by applying kerogen and shale volume corrections on the Rt. The modified Archie equation is derived to compute the water saturation of the shale reservoir. This equation is independent of R_w and Archie parameters. The introduced porosity and water saturation equations are successfully applied for the Ordovician Goldwyer formation shale from Canning Basin, Western Australia. The results indicate that based on the proposed equations, the total porosity ranges from 5% to 10% and the water saturation ranges from 35% to 80%. Whereas, the porosity and water saturation were overestimated by the conventional equations. The results were well-correlated with the core-based porosity and water saturation. Moreover, it is also revealed that the porosity and water saturation of Goldwyer Formation shale are subjected to the specific rock type with heterogeneity in total organic carbon total clay contents. The introduced porosity and water saturation can be helpful for accurate reserve estimations for shale reservoirs. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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13 pages, 1339 KiB

Open AccessArticle

A Novel Equivalent Continuum Approach for Modelling Hydraulic Fractures

by Eziz Atdayev, Ron C. K. Wong and David W. Eaton

Energies 2020, 13(23), 6187; https://doi.org/10.3390/en13236187 - 25 Nov 2020

Cited by 2 | Viewed by 1597

Abstract

Hydraulic fracturing has transitioned into widespread use over the last few decades. There are a variety of numerical methods available to simulate hydraulic fracturing. However, most current methods require a large number of input parameters, of which the values of some parameters are [...] Read more.

Hydraulic fracturing has transitioned into widespread use over the last few decades. There are a variety of numerical methods available to simulate hydraulic fracturing. However, most current methods require a large number of input parameters, of which the values of some parameters are poorly constrained. This paper proposes a new method of modelling the hydraulically fractured region using void-ratio dependent relation to define the permeability of the fractured region. This approach is computationally efficient and reduces the number of input parameters. By implementing this method with an equivalent continuum representation, uncertainties are reduced arising from heterogeneity and anisotropy of earth materials. The computational efficiency improves modelling performance in stress sensitive zones such as in the vicinity of the injection well or near faults. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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22 pages, 4651 KiB

Open AccessArticle

Quantitative Analysis of Amorphous Silica and Its Influence on Reservoir Properties: A Case Study on the Shale Strata of the Lucaogou Formation in the Jimsar Depression, Junggar Basin, China

by Ke Sun, Qinghua Chen, Guohui Chen, Yin Liu and Changchao Chen

Energies 2020, 13(23), 6168; https://doi.org/10.3390/en13236168 - 24 Nov 2020

Cited by 2 | Viewed by 1993

Abstract

To establish a new quantitative analysis method for amorphous silica content and understand its effect on reservoir properties, the amorphous silica (SiO₂) in the shale strata of the Lucaogou Formation in the Jimsar Depression was studied by scanning electron microscopy (SEM) [...] Read more.

To establish a new quantitative analysis method for amorphous silica content and understand its effect on reservoir properties, the amorphous silica (SiO₂) in the shale strata of the Lucaogou Formation in the Jimsar Depression was studied by scanning electron microscopy (SEM) observation, X-ray diffraction (XRD), and X-ray fluorescence spectrometry (XRF). Amorphous silica shows no specific morphology, sometimes exhibits the spherical or ellipsoid shapes, and usually disorderly mounds among other mineral grains. A new quantitative analysis method for observing amorphous SiO₂ was established by combining XRD and XRF. On this basis, while the higher content of amorphous SiO₂ lowers the porosity of the reservoir, the permeability shows no obvious changes. The higher the content of amorphous SiO₂, the lower the compressive strength and Young’s modulus and the lower the oil saturation. Thus, amorphous SiO₂ can reduce the physical properties of reservoir rocks and increase the reservoir plasticity, which is not only conducive to the enrichment of shale oil but also increases the difficulty of fracturing in later reservoir development. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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17 pages, 69623 KiB

Open AccessArticle

Pore-Structural Characteristics of Tight Fractured-Vuggy Carbonates and Its Effects on the P- and S-Wave Velocity: A Micro-CT Study on Full-Diameter Cores

by Wei Li, Xiangjun Liu, Lixi Liang, Yinan Zhang, Xiansheng Li and Jian Xiong

Energies 2020, 13(22), 6148; https://doi.org/10.3390/en13226148 - 23 Nov 2020

Cited by 3 | Viewed by 2325

Abstract

Pore structure has been widely observed to affect the seismic wave velocity of rocks. Although taking lab measurements on 1.0-inch core plugs is popular, it is not representative of the fractured-vuggy carbonates because many fractures and vugs are on a scale up to [...] Read more.

Pore structure has been widely observed to affect the seismic wave velocity of rocks. Although taking lab measurements on 1.0-inch core plugs is popular, it is not representative of the fractured-vuggy carbonates because many fractures and vugs are on a scale up to several hundred microns (and greater) and are spatially heterogeneous. To overcome this shortage, we carried out the lab measurements on full-diameter cores (about 6.5–7.5 cm in diameter). The micro-CT (micro computed tomography) scanning technique is used to characterize the pore space of the carbonates and image processing methods are applied to filter the noise and enhance the responses of the fractures so that the constructed pore spaces are reliable. The wave velocities of P- and S-waves are determined then and the effects of the pore structure on the velocity are analyzed. The results show that the proposed image processing method is effective in constructing and quantitatively characterizing the pore space of the full-diameter fractured-vuggy carbonates. The porosity of all the collected tight carbonate samples is less than 4%. Fractures and vugs are well-developed and the spatial distributions of them are heterogeneous causing, even the samples having similar porosity, the pore structure characteristics of the samples being significantly different. The pores and vugs mainly contribute to the porosity of the samples and the fractures contribute to the change in the wave velocities more than pores and vugs. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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23 pages, 7187 KiB

Open AccessArticle

Reservoir Formation Model and Main Controlling Factors of the Carboniferous Volcanic Reservoir in the Hong-Che Fault Zone, Junggar Basin

by Danping Zhu, Xuewei Liu and Shaobin Guo

Energies 2020, 13(22), 6114; https://doi.org/10.3390/en13226114 - 21 Nov 2020

Cited by 14 | Viewed by 2265

Abstract

The Hong-Che Fault Zone is one of the important oil and gas enrichment zones in the Junggar Basin, especially in the Carboniferous. In recent five years, it has been proven that the Carboniferous volcanic rock has 140 million tons of oil reserves, and [...] Read more.

The Hong-Che Fault Zone is one of the important oil and gas enrichment zones in the Junggar Basin, especially in the Carboniferous. In recent five years, it has been proven that the Carboniferous volcanic rock has 140 million tons of oil reserves, and has built the Carboniferous volcanic reservoir with a capacity of million tons. Practice has proven that the volcanic rocks in this area have great potential for oil and gas exploration and development. To date, Carboniferous volcanic reservoirs have been discovered in well areas such as Che 32, Che 47, Che 91, Chefeng 3, Che 210, and Che 471. The study of drilling, logging, and seismic data shows that the Carboniferous volcanic reservoirs in the Hong-Che Fault Zone are mainly distributed in the hanging wall of the fault zone, and oil and gas have mainly accumulated in the high part of the structure. The reservoirs are controlled by faults and lithofacies in the plane and are vertically distributed within 400 m from the top of the Carboniferous. The Carboniferous of the Hong-Che Fault Zone has experienced weathering leaching and has developed a weathering crust. The vertical zonation characteristics of the weathering crust at the top of the Carboniferous in the area of the Che 210 well are obvious. The soil layer, leached zone, disintegration zone, and parent rock developed from top to bottom. Among these reservoirs, the reservoirs with the best physical properties are mainly developed in the leached zone. Based on a comprehensive analysis of the Carboniferous oil and gas reservoirs in areas of the Chefeng 3 and Che 210 wells, it is believed that the formation of volcanic reservoirs in the Hong-Che Fault Zone was mainly controlled by structures and was also controlled by lithofacies, unconformity surfaces, and physical properties. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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23 pages, 6820 KiB

Open AccessArticle

Effect of Particle Size on Pore Characteristics of Organic-Rich Shales: Investigations from Small-Angle Neutron Scattering (SANS) and Fluid Intrusion Techniques

by Yi Shu, Yanran Xu, Shu Jiang, Linhao Zhang, Xiang Zhao, Zhejun Pan, Tomasz P. Blach, Liangwei Sun, Liangfei Bai, Qinhong Hu and Mengdi Sun

Energies 2020, 13(22), 6049; https://doi.org/10.3390/en13226049 - 19 Nov 2020

Cited by 16 | Viewed by 2531

Abstract

The sample size or particle size of shale plays a significant role in the characterization of pores by various techniques. To systematically investigate the influence of particle size on pore characteristics and the optimum sample size for different methods, we conducted complementary tests [...] Read more.

The sample size or particle size of shale plays a significant role in the characterization of pores by various techniques. To systematically investigate the influence of particle size on pore characteristics and the optimum sample size for different methods, we conducted complementary tests on two overmature marine shale samples with different sample sizes. The tests included small-angle neutron scattering (SANS), gas (N₂, CO₂, and H₂O) adsorption, mercury injection capillary pressure (MICP), and field emission-scanning electron microscopy (FE-SEM) imaging. The results indicate that artificial pores and fractures may occur on the surface or interior of the particles during the pulverization process, and some isolated pores may be exposed to the particle surface or connected by new fractures, thus improving the pore connectivity of the shale. By comparing the results of different approaches, we established a hypothetical model to analyze how the crushing process affects the pore structure of overmature shales. Our results imply that intact wafers with a thickness of 0.15–0.5 mm and cubic samples (~1 cm³) are optimal for performing SANS and MICP analyses. Meanwhile, the 35–80 mesh particle size fraction provides reliable data for various gas physisorption tests in overmature shale. Due to the intrinsic heterogeneity of shale, future research on pore characteristics in shales needs a multidisciplinary approach to obtain a more comprehensive, larger scale, and more reliable understanding. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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15 pages, 20813 KiB

Open AccessArticle

Seismic Identification of Unconventional Heterogenous Reservoirs Based on Depositional History—A Case Study of the Polish Carpathian Foredeep

by Anna Łaba-Biel, Anna Kwietniak and Andrzej Urbaniec

Energies 2020, 13(22), 6036; https://doi.org/10.3390/en13226036 - 19 Nov 2020

Cited by 4 | Viewed by 2066

Abstract

An integrated geological and geophysical approach is presented for the recognition of unconventional targets in the Miocene formations of the Carpathian Foredeep, southern Poland. The subject of the analysis is an unconventional reservoir built of interlayered packets of sandstone, mudstone and claystone, called [...] Read more.

An integrated geological and geophysical approach is presented for the recognition of unconventional targets in the Miocene formations of the Carpathian Foredeep, southern Poland. The subject of the analysis is an unconventional reservoir built of interlayered packets of sandstone, mudstone and claystone, called a “heterogeneous sequence”. This type of sequence acts as both a reservoir and as source rock for hydrocarbons and it consists of layers of insignificant thickness, below the resolution of seismic data. The interpretation of such a sequence has rarely been based on seismic stratigraphy analysis; however, such an approach is proposed here. The subject of interpretation is high-quality seismic data of high resolution that enable detailed depositional analysis. The reconstruction of the depositional history was possible due to the analysis of flattened chronostratigraphic horizons (Wheeler diagram). The identification of depositional positions in a sedimentary basin was the first step for the indication of potential target areas. These areas were also subject to seismic attribute analysis (sweetness) and spectral decomposition. The seismic attribute results positively verified the previously proposed prospects. The results obtained demonstrate that the interpretation of the Miocene sediments in the Carpathian Foredeep should take into account the depositional history reconstruction and paleogeographical analysis. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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17 pages, 3939 KiB

Open AccessArticle

Multi-Phase Tectonic Movements and Their Controls on Coalbed Methane: A Case Study of No. 9 Coal Seam from Eastern Yunnan, SW China

by Ming Li, Bo Jiang, Qi Miao, Geoff Wang, Zhenjiang You and Fengjuan Lan

Energies 2020, 13(22), 6003; https://doi.org/10.3390/en13226003 - 17 Nov 2020

Cited by 15 | Viewed by 2069

Abstract

Multi-phase tectonic movements and complex geological structures limit the exploration and hotspot prediction of coalbed methane (CBM) in structurally complex areas. This scientific problem is still not fully understood, particularly in the Bumu region, Southwest China. The present paper analyses the occurrence characteristics [...] Read more.

Multi-phase tectonic movements and complex geological structures limit the exploration and hotspot prediction of coalbed methane (CBM) in structurally complex areas. This scientific problem is still not fully understood, particularly in the Bumu region, Southwest China. The present paper analyses the occurrence characteristics and distribution of CBM based on the comprehensive analysis of CBM data. In combination with the analysis of the regional tectonics setting, geological structure features and tectonic evolution. The control action of multi-phase tectonic movements on CBM occurrence are further discussed. Results show that the Indosinian local deformation, Yanshanian intense deformation, and Himalayan secondary derived deformation formed the current tectonic framework of Enhong synclinorium. The intense tectonic compression and dextral shear action in the Yanshanian and Himalayan movements caused the complex geological structures in Bumu region, composed of the Enhong syncline, associated reverse faults and late derived normal fault. The CBM distribution is complex, which has the central and western NNE-trending high gas content zones along the syncline hinge zone and the reverse faults. The geological structure controls on CBM enrichment are definite and important. Based on geological structure features and responses of gas content, methane concentration, and gas content gradient, the gas controlling patterns of geological structure are determined and can be classified into five types: the reverse fault sealing, syncline sealing, monoclinal enrichment, normal fault dispersion, and buried floor fault dispersion types. The structural compression above the neutral surface plays an important role in the syncline sealing process, which is indicated by an increase in gas content gradient. The EW-trending tectonic intense compression and dextral shear action in the Himalayan movement avoided the negative inversion of NNE-trending Yanshanian compressive structure and its destruction of CBM reservoir. However, the chronic uplift and derived normal fault during Himalayan period caused the constant dissipation of CBM. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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15 pages, 4165 KiB

Open AccessArticle

Factors Affecting Shale Gas Chemistry and Stable Isotope and Noble Gas Isotope Composition and Distribution: A Case Study of Lower Silurian Longmaxi Shale Gas, Sichuan Basin

by Chunhui Cao, Liwu Li, Yuhu Liu, Li Du, Zhongping Li and Jian He

Energies 2020, 13(22), 5981; https://doi.org/10.3390/en13225981 - 16 Nov 2020

Cited by 6 | Viewed by 2212

Abstract

The Weiyuan (WY) and Changning (CN) fields are the largest shale gas fields in the Sichuan Basin. Though the shale gases in both fields are sourced from the Longmaxi Formation, this study found notable differences between them in molecular composition, carbon isotopic composition, [...] Read more.

The Weiyuan (WY) and Changning (CN) fields are the largest shale gas fields in the Sichuan Basin. Though the shale gases in both fields are sourced from the Longmaxi Formation, this study found notable differences between them in molecular composition, carbon isotopic composition, and noble gas abundance and isotopic composition. CO₂ (av. 0.52%) and N₂ (av. 0.94%) were higher in Weiyuan than in Changning by an average of 0.45% and 0.70%, respectively. The δ¹³C₁ (−26.9% to −29.7%) and δ¹³C₂ (−32.0% to −34.9%) ratios in the Changning shale gases were about 8% and 6% heavier than those in Weiyuan, respectively. Both shale gases had similar ³He/⁴He ratios but different ⁴⁰Ar/³⁶Ar ratios. These geochemical differences indicated complex geological conditions and shed light on the evolution of the Lonmaxi shale gas in the Sichuan Basin. In this study, we highlight the possible impacts on the geochemical characteristics of gas due to tectonic activity, thermal evolution, and migration. By combining previous gas geochemical data and the geological background of these natural gas fields, we concluded that four factors account for the differences in the Longmaxi Formation shale gas in the Sichuan Basin: a) A different ratio of oil cracking gas and kerogen cracking gas mixed in the closed system at the high over-mature stage. b) The Longmaxi shales in WY and CN have had differential geothermal histories, especially in terms of the effects from the Emeishan Large Igneous Province (LIP), which have led to the discrepancy in evolution of the shales in the two areas. c) The heterogeneity of the Lower Silurian Longmaxi shales is another important factor, according to the noble gas data. d) Although shale gas is generated in closed systems, natural gas loss throughout geological history cannot be avoided, which also accounts for gas geochemical differences. This research offers some useful information regarding the theory of shale gas generation and evolution. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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24 pages, 10936 KiB

Open AccessArticle

Fractional Time Derivative Seismic Wave Equation Modeling for Natural Gas Hydrate

by Yanfei Wang, Yaxin Ning and Yibo Wang

Energies 2020, 13(22), 5901; https://doi.org/10.3390/en13225901 - 12 Nov 2020

Cited by 9 | Viewed by 2458

Abstract

Simulation of the seismic wave propagation in natural gas hydrate (NGH) is of great importance. To finely portray the propagation of seismic wave in NGH, attenuation properties of the earth’s medium which causes reduced amplitude and dispersion need to be considered. The traditional [...] Read more.

Simulation of the seismic wave propagation in natural gas hydrate (NGH) is of great importance. To finely portray the propagation of seismic wave in NGH, attenuation properties of the earth’s medium which causes reduced amplitude and dispersion need to be considered. The traditional viscoacoustic wave equations described by integer-order derivatives can only nearly describe the seismic attenuation. Differently, the fractional time derivative seismic wave-equation, which was rigorously derived from the Kjartansson’s constant-Q model, could be used to accurately describe the attenuation behavior in realistic media. We propose a new fractional finite-difference method, which is more accurate and faster with the short memory length. Numerical experiments are performed to show the feasibility of the proposed simulation scheme for NGH, which will be useful for next stage of seismic imaging of NGH. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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26 pages, 14502 KiB

Open AccessArticle

An Analytical Model for Production Analysis of Hydraulically Fractured Shale Gas Reservoirs Considering Irregular Stimulated Regions

by Kaixuan Qiu and Heng Li

Energies 2020, 13(22), 5899; https://doi.org/10.3390/en13225899 - 12 Nov 2020

Cited by 4 | Viewed by 1569

Abstract

Shale gas reservoirs are typically developed by multistage, propped hydraulic fractures. The induced fractures have a complex geometry and can be represented by a high permeability region near each fracture, also called stimulated region. In this paper, a new integrative analytical solution coupled [...] Read more.

Shale gas reservoirs are typically developed by multistage, propped hydraulic fractures. The induced fractures have a complex geometry and can be represented by a high permeability region near each fracture, also called stimulated region. In this paper, a new integrative analytical solution coupled with gas adsorption, non-Darcy flow effect is derived for shale gas reservoirs. The modified pseudo-pressure and pseudo-time are defined to linearize the nonlinear partial differential equations (PDEs) and thus the governing PDEs are transformed into ordinary differential equations (ODEs) by integration, instead of the Laplace transform. The rate vs. pseudo-time solution in real-time space can be obtained, instead of using the numerical inversion for Laplace transform. The analytical model is validated by comparison with the numerical model. According to the fitting results, the calculation accuracy of analytic solution is almost 99%. Besides the computational convenience, another advantage of the model is that it has been validated to be feasible to estimate the pore volume of hydraulic region, stimulated region, and matrix region, and even the shape of regions is irregular and asymmetrical for multifractured horizontal wells. The relative error between calculated volume and given volume is less than 10%, which meets the engineering requirements. The model is finally applied to field production data for history matching and forecasting. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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32 pages, 13654 KiB

Open AccessArticle

Adaptive Processing for EM Telemetry Signal Recovery: Field Data from Sichuan Province

by Olalekan Fayemi, Qingyun Di, Qihui Zhen and Yu L. Wang

Energies 2020, 13(22), 5873; https://doi.org/10.3390/en13225873 - 10 Nov 2020

Cited by 3 | Viewed by 2467

Abstract

This paper deals with the study of multi-channel adaptive noise cancellation with a focus on its application in electromagnetic (EM) telemetry. We presented new variable step-size least mean square (LMS) techniques: regularized variable step-size LMS and regularized sigmoid variable size LMS, for electromagnetic [...] Read more.

This paper deals with the study of multi-channel adaptive noise cancellation with a focus on its application in electromagnetic (EM) telemetry. We presented new variable step-size least mean square (LMS) techniques: regularized variable step-size LMS and regularized sigmoid variable size LMS, for electromagnetic telemetry data processing. Considering the complexity and spatial distribution of environmental noise, algorithms with multiple reference signals were used to retrieve transmitted EM signals. The feasibility of the regularized variable step size LMS algorithms with numerical simulation was analyzed and presented. The adaptive processing techniques were applied in the recovery of frequency and binary phase shift key modulated signal. The proposed multi-channel adaptive technique achieves fast convergence speed, low mean squared error and is shown to have good convergence characteristics compared to conventional methods. In addition to attaining good results from the multi-channel adaptive filter and performing the signal analysis in real-time, we implemented combined fast effective impulse noise removal techniques. The combination of median and mean filters was effective in removing a wide range of impulsive noises without distorting any other data points. Further, electromagnetic telemetry data were acquired during a drilling operation in Sichuan province, China, for real field application. Data processing workflow was designed for EM telemetry data processing based on the noise characteristics, simulation results and expected result for demodulation. To establish a comprehensive overview, a performance comparison of the acquisition array system is also provided. Conclusively, the introduced multichannel adaptive noise canceling techniques are very effective in recovering transmitted EM telemetry signals. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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22 pages, 11312 KiB

Open AccessArticle

Numerical Investigation on Proppant–Water Mixture Transport in Slot under High Reynolds Number Conditions

by Tao Zhang, Ruoyu Yang, Jianchun Guo and Jie Zeng

Energies 2020, 13(21), 5665; https://doi.org/10.3390/en13215665 - 29 Oct 2020

Cited by 4 | Viewed by 2087

Abstract

Water hydraulic fracturing involves pumping low viscosity fluid and proppant mixture into the artificial fracture under a high pumping rate. In that high Reynolds number conditions (HRNCs, Re > 2000), the turbulence effect is one of the key factors affecting proppant transportation and [...] Read more.

Water hydraulic fracturing involves pumping low viscosity fluid and proppant mixture into the artificial fracture under a high pumping rate. In that high Reynolds number conditions (HRNCs, Re > 2000), the turbulence effect is one of the key factors affecting proppant transportation and placement. In this paper, a Eulerian multiphase model was used to simulate the proppant particle transport in a parallel slot under HRNCs. Turbulence effects in high pumping rates and frictional stress among the proppant particles were taken into consideration, and the Johnson-Jackson wall boundary conditions were used to describe the particle-wall interaction. The numerical simulation result was validated with laboratory-scale slot experiment results. The simulation results demonstrate that the pattern of the proppant bank is significantly affected by the vortex near the wellbore, and the whole proppant transport process can be divided into four stages under HRNCs. Furthermore, the proppant placement structure and the equilibrium height of proppant dune under HRNCs are comprehensively discussed by a parametrical study, including injection position, velocity, proppant density, concentration, and diameter. As the injection position changes from the lower one to the top one, the unpropped area near the entrance decrease by 7.1 times, and the equilibrium height for the primary dune increase by 5.3%. As the velocity of the slurry jet increases from 2 m/s to 5 m/s (Re = 2000–5000), the vortex becomes stronger, so the non-propped area near the inlet increase by 5.3 times, and the equilibrium height decrease by 5.2%. The change of proppant properties does not significantly change the vortex; however, the equilibrium height is affected by the high-speed flush. Thus, the conventional equilibrium height prediction correlation is not suitable for the HRNCs. Therefore, a modified bi-power law prediction correlation was proposed based on the simulation data, which can be used to accurately predict the equilibrium height of the proppant bank under HRNCs (mean deviation = 3.8%). Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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16 pages, 8674 KiB

Open AccessArticle

Experimental Investigation and Mechanism Analysis on Rock Damage by High Voltage Spark Discharge in Water: Effect of Electrical Conductivity

by Zhixiang Cai, Hui Zhang, Kerou Liu, Yufei Chen and Qing Yu

Energies 2020, 13(20), 5432; https://doi.org/10.3390/en13205432 - 18 Oct 2020

Cited by 15 | Viewed by 2994

Abstract

High voltage spark discharge (HVSD) could generate strong pressure waves that can be combined with a rotary drill bit to improve the penetration rate in unconventional oil and gas drilling. However, there has been little investigation of the effect of electrical conductivity on [...] Read more.

High voltage spark discharge (HVSD) could generate strong pressure waves that can be combined with a rotary drill bit to improve the penetration rate in unconventional oil and gas drilling. However, there has been little investigation of the effect of electrical conductivity on rock damage and the fragmentation mechanism caused by HVSD. Therefore, we conducted experiments to destroy cement mortar, a rock-like material, in water with five conductivity levels, from 0.5 mS/cm to 20 mS/cm. We measured the discharge parameters, such as breakdown voltage, breakdown delay time, and electrical energy loss, and investigated the damage mechanism from stress waves propagation using X-ray computed tomography. Our study then analyzed the influence of conductivity on the surface damage of the sample by the pore size distribution and the cumulative pore area, as well as studied the dependence of internal damage on conductivity by through-transmission ultrasonic inspection technique. The results indicated that the increase in electrical conductivity decreased the breakdown voltage and breakdown delay time and increased the energy loss, which led to a reduction in the magnitude of the pressure wave and, ultimately, reduced the sample damage. It is worth mentioning that the relationship between the sample damage and electrical conductivity is non-linear, showing a two-stage pattern. The findings suggest that stress waves induced by the pressure waves play a significant role in sample damage where pores and two types of tensile cracks are the main failure features. Compressive stresses close horizontal cracks inside the sample and propagate vertical cracks, forming the tensile cracks-I. Tensile stresses generated at the sample–water interface due to the reflection of stress waves produce the tensile cracks-II. Our study is the first to investigate the relationship between rock damage and electrical conductivity, providing insights to guide the design of drilling tools based on HVSD. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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21 pages, 6272 KiB

Open AccessArticle

A Novel Data-Driven Method to Estimate Methane Adsorption Isotherm on Coals Using the Gradient Boosting Decision Tree: A Case Study in the Qinshui Basin, China

by Jiyuan Zhang, Qihong Feng, Xianmin Zhang, Qiujia Hu, Jiaosheng Yang and Ning Wang

Energies 2020, 13(20), 5369; https://doi.org/10.3390/en13205369 - 15 Oct 2020

Cited by 18 | Viewed by 2238

Abstract

The accurate determination of methane adsorption isotherms in coals is crucial for both the evaluation of underground coalbed methane (CBM) reserves and design of development strategies for enhancing CBM recovery. However, the experimental measurement of high-pressure methane adsorption isotherms is extremely tedious and [...] Read more.

The accurate determination of methane adsorption isotherms in coals is crucial for both the evaluation of underground coalbed methane (CBM) reserves and design of development strategies for enhancing CBM recovery. However, the experimental measurement of high-pressure methane adsorption isotherms is extremely tedious and time-consuming. This paper proposed the use of an ensemble machine learning (ML) method, namely the gradient boosting decision tree (GBDT), in order to accurately estimate methane adsorption isotherms based on coal properties in the Qinshui basin, China. The GBDT method was trained to correlate the adsorption amount with coal properties (ash, fixed carbon, moisture, vitrinite, and vitrinite reflectance) and experimental conditions (pressure, equilibrium moisture, and temperature). The results show that the estimated adsorption amounts agree well with the experimental ones, which prove the accuracy and robustness of the GBDT method. A comparison of the GBDT with two commonly used ML methods, namely the artificial neural network (ANN) and support vector machine (SVM), confirms the superiority of GBDT in terms of generalization capability and robustness. Furthermore, relative importance scanning and univariate analysis based on the constructed GBDT model were conducted, which showed that the fixed carbon and ash contents are primary factors that significantly affect the adsorption isotherms for the coal samples in this study. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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27 pages, 10806 KiB

Open AccessArticle

Controls on Pore Structures and Permeability of Tight Gas Reservoirs in the Xujiaweizi Rift, Northern Songliao Basin

by Luchuan Zhang, Shu Jiang, Dianshi Xiao, Shuangfang Lu, Ren Zhang, Guohui Chen, Yinglun Qin and Yonghe Sun

Energies 2020, 13(19), 5184; https://doi.org/10.3390/en13195184 - 5 Oct 2020

Cited by 3 | Viewed by 2126

Abstract

As significant components of tight gas reservoirs, clay minerals with ultrafine dimensions play a crucial role in controlling pore structures and permeability. XRD (X-ray diffraction), SEM (scanning electron microscopy), N₂GA (nitrogen gas adsorption), and RMIP (rate-controlled mercury injection porosimetry) experiments were [...] Read more.

As significant components of tight gas reservoirs, clay minerals with ultrafine dimensions play a crucial role in controlling pore structures and permeability. XRD (X-ray diffraction), SEM (scanning electron microscopy), N₂GA (nitrogen gas adsorption), and RMIP (rate-controlled mercury injection porosimetry) experiments were executed to uncover the effects of clay minerals on pore structures and the permeability of tight gas reservoirs, taking tight rock samples collected from the Lower Cretaceous Dengloukou and Shahezi Formations in the Xujiaweizi Rift of the northern Songliao Basin as an example. The results show that the pore space of tight gas reservoirs primarily comprises intragranular-dominant pore networks and intergranular-dominant pore networks according to fractal theory and mercury intrusion features. The former is interpreted as a conventional pore-throat structure where large pores are connected by wide throats, mainly consisting of intergranular pores and dissolution pores, and the latter corresponds to a tree-like pore structure in which the narrower throats are connected to the upper-level wider throats like tree branches, primarily constituting intercrystalline pores within clay minerals. Intragranular-dominant pore networks contribute more to total pore space, with a proportion of 57.79%–90.56%, averaging 72.55%. However, intergranular-dominant pores make more contribution to permeability of tight gas reservoirs, with a percentage of 62.73%–93.40%. The intragranular-dominant pore networks gradually evolve from intergranular-dominant pore networks as rising clay mineral content, especially authigenic chlorite, and this process has limited effect on the total pore space but can evidently lower permeability. The specific surface area (SSA) of tight gas reservoirs is primarily derived from clay minerals, in the order of I/S (mixed-layer illite/smectite) > chlorite > illite > framework minerals. The impact of clay minerals on pore structures of tight gas reservoirs is correlated to their types, owing to different dispersed models and morphologies, and chlorite has more strict control on the reduction of throat radius of tight rocks. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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18 pages, 5021 KiB

Open AccessArticle

Pore-Scale Lattice Boltzmann Simulation of Gas Diffusion–Adsorption Kinetics Considering Adsorption-Induced Diffusivity Change

by Zhigao Peng, Shenggui Liu, Yingjun Li, Zongwei Deng and Haoxiong Feng

Energies 2020, 13(18), 4927; https://doi.org/10.3390/en13184927 - 20 Sep 2020

Cited by 6 | Viewed by 3068

Abstract

The diffusion–adsorption behavior of methane in coal is an important factor that both affecting the decay rate of gas production and the total gas production capacity. In this paper, we established a pore-scale Lattice Boltzmann (LB) model coupled with fluid flow, gas diffusion, [...] Read more.

The diffusion–adsorption behavior of methane in coal is an important factor that both affecting the decay rate of gas production and the total gas production capacity. In this paper, we established a pore-scale Lattice Boltzmann (LB) model coupled with fluid flow, gas diffusion, and gas adsorption–desorption in the bi-dispersed porous media of coalbed methane. The Knudsen diffusion and dynamic adsorption–desorption of gas in clusters of coal particles were considered. Firstly, the model was verified by two classical cases. Then, three dimensionless numbers, Re, Pe, and Da, were adopted to discuss the impact of fluid velocity, gas diffusivity, and adsorption/desorption rate on the gas flow–diffusion–adsorption process. The effect of the gas adsorption layer in micropores on the diffusion–adsorption–desorption process was considered, and a Langmuir isotherm adsorption theory-based method was developed to obtain the dynamic diffusion coefficient, which can capture the intermediate process during adsorption/desorption reaches equilibrium. The pore-scale bi-disperse porous media of coal matrix was generated based on the RCP algorithm, and the characteristics of gas diffusion and adsorption in the coal matrix with different Pe, Da, and pore size distribution were discussed. The conclusions were as follows: (1) the influence of fluid velocity on the diffusion–adsorption process of coalbed methane at the pore-scale is very small and can be ignored; the magnitude of the gas diffusivity in macropores affects the spread range of the global gas diffusion and the process of adsorption and determines the position where adsorption takes place preferentially. (2) A larger Fickian diffusion coefficient or greater adsorption constant can effectively enhance the adsorption rate, and the trend of gas concentration- adsorption is closer to the Langmuir isotherm adsorption curve. (3) The gas diffusion–adsorption–desorption process is affected by the adsorption properties of coal: the greater the p_L or V_m, the slower the global gas diffusivity decay. (4) The effect of the gas molecular adsorption layer has a great impact on the kinetic process of gas diffusion–adsorption–desorption. Coal is usually tight and has low permeability, so it is difficult to ensure that the gas diffusion and adsorption are sufficient, the direct use of a static isotherm adsorption equation may be incorrect. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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17 pages, 3323 KiB

Open AccessArticle

Proppant Transportation in Cross Fractures: Some Findings and Suggestions for Field Engineering

by Yan Zhang, Xiaobing Lu, Xuhui Zhang and Peng Li

Energies 2020, 13(18), 4912; https://doi.org/10.3390/en13184912 - 19 Sep 2020

Cited by 8 | Viewed by 2186

Abstract

The proppant transportation is a typical two-phase flow process in a complex cross fracture network during hydraulic fracturing. In this paper, the proppant transportation in cross fractures is investigated by the computational fluid dynamics (CFD) method. The Euler–Euler two-phase flow model and the [...] Read more.

The proppant transportation is a typical two-phase flow process in a complex cross fracture network during hydraulic fracturing. In this paper, the proppant transportation in cross fractures is investigated by the computational fluid dynamics (CFD) method. The Euler–Euler two-phase flow model and the kinetic theory of granular flow (KTGF) are adopted. The dimensionless controlling parameters are derived by dimensional analysis. The equilibrium proppant height (EPH) and the ratio of the proppant mass (RPM) in the secondary fracture to that in the whole cross fracture network are used to describe the movement and settlement of proppants in the cross fractures. The main features of the proppant transportation in the cross fractures are given, and several relative suggestions are presented for engineering application in the field. The main controlling dimensionless parameters for relative EPH are the proppant Reynolds number and the inlet proppant volume fraction. The dominating dimensionless parameters for RPM are the relative width of the primary and the secondary fracture. Transportation of the proppants with a certain particle size grading into the cross fractures may be a good way for supporting the hydraulic fractures. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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15 pages, 5940 KiB

Open AccessArticle

Machine Learning-Based Probabilistic Lithofacies Prediction from Conventional Well Logs: A Case from the Umiat Oil Field of Alaska

by Nilesh Dixit, Paul McColgan and Kimberly Kusler

Energies 2020, 13(18), 4862; https://doi.org/10.3390/en13184862 - 17 Sep 2020

Cited by 27 | Viewed by 3109

Abstract

A good understanding of different rock types and their distribution is critical to locate oil and gas accumulations in the subsurface. Traditionally, rock core samples are used to directly determine the exact rock facies and what geological environments might be present. Core samples [...] Read more.

A good understanding of different rock types and their distribution is critical to locate oil and gas accumulations in the subsurface. Traditionally, rock core samples are used to directly determine the exact rock facies and what geological environments might be present. Core samples are often expensive to recover and, therefore, not always available for each well. Wireline logs provide a cheaper alternative to core samples, but they do not distinguish between various rock facies alone. This problem can be overcome by integrating limited core data with largely available wireline log data with machine learning. Here, we presented an application of machine learning in rock facies predictions based on limited core data from the Umiat Oil Field of Alaska. First, we identified five sandstone reservoir facies within the Lower Grandstand Member using core samples and mineralogical data available for the Umiat 18 well. Next, we applied machine learning algorithms (ascendant hierarchical clustering, self-organizing maps, artificial neural network, and multi-resolution graph-based clustering) to available wireline log data to build our models trained with core-driven information. We found that self-organizing maps provided the best result among other techniques for facies predictions. We used the best self-organizing maps scheme for predicting similar reservoir facies in nearby uncored wells—Umiat 23H and SeaBee-1. We validated our facies prediction results for these wells with observed seismic data. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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16 pages, 11374 KiB

Open AccessArticle

Development and Performance Evaluation of Solid-Free Drilling Fluid for CBM Reservoir Drilling in Central Hunan

by Pinghe Sun, Meng Han, Han Cao, Weisheng Liu, Shaohe Zhang and Junyi Zhu

Energies 2020, 13(18), 4857; https://doi.org/10.3390/en13184857 - 16 Sep 2020

Cited by 3 | Viewed by 2482

Abstract

Solid-free drilling fluid is a matter of cardinal significance in the course of Coal bed Methane (CBM) reservoir drilling. This study evaluated the performance of solid-free CBM drilling fluid in central Hunan. Three types of surfactants, namely TX-10 (nonionic), HSB1618 (zwitterionic) and penetrant [...] Read more.

Solid-free drilling fluid is a matter of cardinal significance in the course of Coal bed Methane (CBM) reservoir drilling. This study evaluated the performance of solid-free CBM drilling fluid in central Hunan. Three types of surfactants, namely TX-10 (nonionic), HSB1618 (zwitterionic) and penetrant T (anionic), were added in basic fluid at various concentrations of 0.05, 0.10 and 0.15% (m/m). This study comprised of drilling fluid rheology, sample mineral analysis, sample nuclear magnetic resonance (NMR) scanning, sample wettability, and sample surface micro characteristics tests. The results show that TX-10 and HSB1618 enhance the rheological properties of drilling fluid, such as yield point and gel strength. Penetrant T has opposite effect on it. It was found that the minimum American Petroleum Institute (API) filtration is only 0.3 mL. This study adopted a new method using laser particle size analyzer to evaluate suspension performance. Based on the surface micro characteristics of the sample and the NMR scanning tests, it is found that the residual amount of basic fluid + HSB1618 in the sample is the smallest. The wettability modification curve indicates that three surfactants decrease the sample’s hydrophobicity. With the increase of surfactant concentration, all above parameters change regularly. The basic fluid + 0.10% HSB1618 has the strongest hydrophobicity for sample at pH = 10. This study obtained a set of solid-free drilling fluid system, which provides better suspension capacity and large contact angle and reduces residue of drilling fluid in CBM reservoir. Ultimately, it can accelerate the desorption of coal gas and reduce damage to the reservoir. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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15 pages, 4943 KiB

Open AccessArticle

Application of Waveform Stacking Methods for Seismic Location at Multiple Scales

by Lei Li, Yujiang Xie and Jingqiang Tan

Energies 2020, 13(18), 4729; https://doi.org/10.3390/en13184729 - 11 Sep 2020

Cited by 3 | Viewed by 2728

Abstract

Seismic source location specifies the spatial and temporal coordinates of seismic sources and lays the foundation for advanced seismic monitoring at all scales. In this work, we firstly introduce the principles of diffraction stacking (DS) and cross-correlation stacking (CCS) for seismic location. The [...] Read more.

Seismic source location specifies the spatial and temporal coordinates of seismic sources and lays the foundation for advanced seismic monitoring at all scales. In this work, we firstly introduce the principles of diffraction stacking (DS) and cross-correlation stacking (CCS) for seismic location. The DS method utilizes the travel time from the source to receivers, while the CCS method considers the differential travel time from pairwise receivers to the source. Then, applications with three field datasets ranging from small-scale microseismicity to regional-scale induced seismicity are presented to investigate the feasibility, imaging resolution, and location reliability of the two stacking operators. Both of the two methods can focus the source energy by stacking the waveforms of the selected events. Multiscale examples demonstrate that the imaging resolution is not only determined by the inherent property of the stacking operator but also highly dependent on the acquisition geometry. By comparing to location results from other methods, we show that the location bias is consistent with the scale size, as well as the frequency contents of the seismograms and grid spacing values. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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26 pages, 13062 KiB

Open AccessFeature PaperArticle

Numerical Investigation of Injection-Induced Fracture Propagation in Brittle Rocks with Two Injection Wells by a Modified Fluid-Mechanical Coupling Model

by Song Wang, Jian Zhou, Luqing Zhang and Zhenhua Han

Energies 2020, 13(18), 4718; https://doi.org/10.3390/en13184718 - 10 Sep 2020

Cited by 13 | Viewed by 2522

Abstract

Hydraulic fracturing is a key technical means for stimulating tight and low permeability reservoirs to improve the production, which is widely employed in the development of unconventional energy resources, including shale gas, shale oil, gas hydrate, and dry hot rock. Although significant progress [...] Read more.

Hydraulic fracturing is a key technical means for stimulating tight and low permeability reservoirs to improve the production, which is widely employed in the development of unconventional energy resources, including shale gas, shale oil, gas hydrate, and dry hot rock. Although significant progress has been made in the simulation of fracturing a single well using two-dimensional Particle Flow Code (PFC2D), the understanding of the multi-well hydraulic fracturing characteristics is still limited. Exploring the mechanisms of fluid-driven fracture initiation, propagation and interaction under multi-well fracturing conditions is of great theoretical significance for creating complex fracture networks in the reservoir. In this study, a series of two-well fracturing simulations by a modified fluid-mechanical coupling algorithm were conducted to systematically investigate the effects of injection sequence and well spacing on breakdown pressure, fracture propagation and stress shadow. The results show that both injection sequence and well spacing make little difference on breakdown pressure but have huge impacts on fracture propagation pressure. Especially under hydrostatic pressure conditions, simultaneous injection and small well spacing increase the pore pressure between two injection wells and reduce the effective stress of rock to achieve lower fracture propagation pressure. The injection sequence can change the propagation direction of hydraulic fractures. When the in-situ stress is hydrostatic pressure, simultaneous injection compels the fractures to deflect and tend to propagate horizontally, which promotes the formation of complex fracture networks between two injection wells. When the maximum in-situ stress is in the horizontal direction, asynchronous injection is more conducive to the parallel propagation of multiple hydraulic fractures. Nevertheless, excessively small or large well spacing reduces the number of fracture branches in fracture networks. In addition, the stress shadow effect is found to be sensitive to both injection sequence and well spacing. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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15 pages, 4397 KiB

Open AccessArticle

Dynamic Pore-Scale Network Modeling of Spontaneous Water Imbibition in Shale and Tight Reservoirs

by Xiukun Wang and James J. Sheng

Energies 2020, 13(18), 4709; https://doi.org/10.3390/en13184709 - 10 Sep 2020

Cited by 9 | Viewed by 2511

Abstract

Spontaneous water imbibition plays an imperative role in the development of shale or tight oil reservoirs. Spontaneous water imbibition is helpful in the extraction of crude oil from the matrix, although it decreases the relative permeability of the hydrocarbon phase dramatically. The dynamic [...] Read more.

Spontaneous water imbibition plays an imperative role in the development of shale or tight oil reservoirs. Spontaneous water imbibition is helpful in the extraction of crude oil from the matrix, although it decreases the relative permeability of the hydrocarbon phase dramatically. The dynamic pore-scale network modeling of water imbibition in shale and tight reservoirs is presented in this work; pore network generation, local capillary pressure function, conductance calculation and boundary conditions for imbibition are all presented in detail in this paper. The pore network is generated based on the characteristics of Barnett shale formations, and the corresponding laboratory imbibition experiments are matched using this established dynamic pore network model. The effects of the wettability, throat aspect ratio, viscosity, shape factor, micro-fractures, etc. are all investigated in this work. Attempts are made to investigate the water imbibition mechanisms from a micro-scale perspective. According to the simulated results, wettability dominates the imbibition characteristics. Besides this, the viscous effects including viscosity, initial capillary pressure and micro-fractures increase the imbibition rate, while the final recovery factor is more controlled by the capillarity effect including the cross-area shape factor, contact angle and the average pore-throat aspect ratio. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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23 pages, 18480 KiB

Open AccessFeature PaperArticle

Natural Fractures in Carbonate Basement Reservoirs of the Jizhong Sub-Basin, Bohai Bay Basin, China: Key Aspects Favoring Oil Production

by Guoping Liu, Lianbo Zeng, Chunyuan Han, Mehdi Ostadhassan, Wenya Lyu, Qiqi Wang, Jiangwei Zhu and Fengxiang Hou

Energies 2020, 13(18), 4635; https://doi.org/10.3390/en13184635 - 7 Sep 2020

Cited by 18 | Viewed by 3615

Abstract

Analysis of natural fractures is essential for understanding the heterogeneity of basement reservoirs with carbonate rocks since natural fractures significantly control key attributes such as porosity and permeability. Based on the observations and analyses of outcrops, cores, borehole image logs, and thin sections [...] Read more.

Analysis of natural fractures is essential for understanding the heterogeneity of basement reservoirs with carbonate rocks since natural fractures significantly control key attributes such as porosity and permeability. Based on the observations and analyses of outcrops, cores, borehole image logs, and thin sections from the Mesoproterozoic to Lower Paleozoic in the Jizhong Sub-Basin, natural fractures are found to be abundant in genetic types (tectonic, pressure-solution, and dissolution) in these reservoirs. Tectonic fractures are dominant in such reservoirs, and lithology, mechanical stratigraphy, and faults are major influencing factors for the development of fractures. Dolostones with higher dolomite content are more likely to have tectonic fractures than limestones with higher calcite content. Most tectonic fractures are developed inside mechanical units and terminate at the unit interface at nearly perpendicular or high angles. Also, where a thinner mechanical unit is observed, tectonic fractures are more frequent with a small height. Furthermore, the dominant direction of tectonic fractures is sub-parallel to the fault direction or oblique at a small angle. In addition, integrating diverse characteristics of opening-mode fractures and well-testing data with oil production shows that, in perforated intervals where dolostone and limestone are interstratified or dolostone is the main lithologic composition, fractures are developed well, and the oil production is higher. Moreover, fractures with a larger dip angle have bigger apertures and contribute more to oil production. Collectively, this investigation provides a future reference for understanding the importance of natural fractures and their impact on oil production in the carbonate basement reservoirs. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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20 pages, 7608 KiB

Open AccessArticle

Theoretical Comparison of Test Performance of Different Pulse Decay Methods for Unconventional Cores

by Guofeng Han, Xiaoli Liu and Jin Huang

Energies 2020, 13(17), 4557; https://doi.org/10.3390/en13174557 - 2 Sep 2020

Cited by 7 | Viewed by 2036

Abstract

Various pulse decay methods are proposed to test tight cores. These methods can be divided into three types. This study compares the performance of these methods to test the permeability of unconventional cores in terms of homogeneous cores, dual-medium cores, and gas adsorption, [...] Read more.

Various pulse decay methods are proposed to test tight cores. These methods can be divided into three types. This study compares the performance of these methods to test the permeability of unconventional cores in terms of homogeneous cores, dual-medium cores, and gas adsorption, including the pressure equilibrium time, possible errors caused by conventional analysis methods, and reflections on the characteristics of dual-media. Studies shows that the two test methods with an antisymmetric relationship in the boundary conditions have basically identical test performance. When testing homogeneous cores, regardless of whether the gas is adsorptive or not, the pressure equilibrium time of the first type of method is approximately half of that of the second type of method. The dual-medium parameters seriously affect the pressure equilibrium time of different methods, which may cause the difference of order of magnitude. For homogeneous cores, the permeability errors of the first and second types of methods caused by porosity errors are similar and larger than that of the third type of method. For dual media, the fracture permeability obtained by the third type of method using the conventional analysis method may differ from the actual value by tens of times. No method can significantly eliminate the sorption effect. When the core is a dual-medium, only the pressure curves of the upstream positive-pulse method, downstream negative-pulse method and one-chamber method can reflect the characteristics of dual media. The pressure derivative of the one-chamber method cannot reflect the characteristics of dual media at the early time. The pressure derivative of the second type and the upstream positive-pulse downstream negative-pulse method can reflect the complete characteristics of dual media, but their pressure derivative of the constant-slope segment is small, and the interporosity flow parameter may not be identified. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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16 pages, 6315 KiB

Open AccessArticle

Reservoir Characteristics of the Lower Jurassic Lacustrine Shale in the Eastern Sichuan Basin and Its Effect on Gas Properties: An Integrated Approach

by Jianhua He, Hucheng Deng, Ruolong Ma, Ruyue Wang, Yuanyuan Wang and Ang Li

Energies 2020, 13(17), 4495; https://doi.org/10.3390/en13174495 - 31 Aug 2020

Cited by 11 | Viewed by 2146

Abstract

The exploration of shale gas in Fuling area achieved great success, but the reservoir characteristics and gas content of the lower Jurassic lacustrine in the northern Fuling areas remain unknown. We conducted organic geochemical analyses, Field Emission Scanning Electron Microscope (FE-SEM), X-ray diffraction [...] Read more.

The exploration of shale gas in Fuling area achieved great success, but the reservoir characteristics and gas content of the lower Jurassic lacustrine in the northern Fuling areas remain unknown. We conducted organic geochemical analyses, Field Emission Scanning Electron Microscope (FE-SEM), X-ray diffraction (XRD) analysis, high-pressure mercury intrusion (MIP) and CH₄adsorption experimental methods, as well as NMR logging, to study mineral composition, geochemical, pore structure characteristics of organic-rich shales and their effects on the methane adsorption capacity. The Da’anzhai shale member is generally a set of relatively thick (avg. 75 m) and high carbonate-content (avg. 56.89%) lacustrine sediments with moderate total organic carbon (TOC) (avg. 1.12%) and thermal maturation (Vitrinite reflectance (VR): avg. 1.19%). Five types of lithofacies can be classified: marl (ML), calcareous shale (CS), argillaceous shale (AS), muddy siltstone (MS), and silty shale (SS). CS has good reservoir quality with a high porosity (avg. 4.72%). The small pores with the transverse relaxation time of 0.6–1 ms and 1–3 ms comprised the major part of the porosity in the most lithofacies from Nuclear magnetic resonance (NMR) data, while the large pore (>300 ms) accounts for a small porosity proportion in the CS. The pores mainly constitute of mesopores (avg. 23.2 nm). The clay minerals with a large number of interparticle pores in the SEM contributes most to surface area in the shale lithofacies with a moderate TOC. The adsorption potential of shale samples is huge with an average adsorption capacity of 4.38 mL/g and also has high gas content (avg. 1.04 m³/t). The adsorption capacity of shale samples increases when TOC increases and temperature decreases. Considered reservoir properties and gas properties, CS with the laminated structures in the medium-upper section of the Da’anzhai member is the most advantage lithofacies for shale gas exploitation. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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19 pages, 8090 KiB

Open AccessArticle

Multidisciplinary Characterization of Unconventional Reservoirs Based on Correlation of Well and Seismic Data

by Weronika Kaczmarczyk and Małgorzata Słota-Valim

Energies 2020, 13(17), 4413; https://doi.org/10.3390/en13174413 - 26 Aug 2020

Cited by 2 | Viewed by 2579

Abstract

Combinatorial analysis of key petrophysical parameters can provide valuable information about subsurface hydrocarbon reservoirs. This is particularly important for reservoirs with unconventional rock formations that, due to the low permeability, need to be stimulated by fracturing treatment to provide fluid flow to the [...] Read more.

Combinatorial analysis of key petrophysical parameters can provide valuable information about subsurface hydrocarbon reservoirs. This is particularly important for reservoirs with unconventional rock formations that, due to the low permeability, need to be stimulated by fracturing treatment to provide fluid flow to the exploitation wellbore. In this article, based on data from unconventional shale formations (N Poland), we outline how independent sets of elastic and petrophysical parameters and other reservoir features can be co-analyzed to estimate the fracture susceptibility of shale intervals, which are characterized by a high total organic carbon (TOC) content and high porosity. These features were determined by analysis of each horizon’s elastic and mineralogical brittleness index (BI). These two variants were calculated first in 1D; integrated with the seismic data and finally compared with other parameters such as acoustic impedance, ratio of compressional and shear wave velocities, porosity, and density; and then presented and analyzed using cross plots that highlighted the key relationships between them. The overall BI trends were similar in both horizontal and vertical directions. The highest BI values were observed in the southeast of the analyzed area (Source I) and in the southeast and northwest of the area (Source II). These results can form the basis for predictive modeling of reservoir properties aiding effective reservoir exploration. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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19 pages, 4859 KiB

Open AccessArticle

Investigation of the Pore Structure of Tight Sandstone Based on Multifractal Analysis from NMR Measurement: A Case from the Lower Permian Taiyuan Formation in the Southern North China Basin

by Kaixuan Qu and Shaobin Guo

Energies 2020, 13(16), 4067; https://doi.org/10.3390/en13164067 - 6 Aug 2020

Cited by 11 | Viewed by 2045

Abstract

Understanding the pore structure can help us acquire a deep insight into the fluid transport properties and storage capacity of tight sandstone reservoirs. In this work, a series of methods, including X-ray diffraction (XRD) analysis, casting thin sections, scanning electron microscope (SEM), nuclear [...] Read more.

Understanding the pore structure can help us acquire a deep insight into the fluid transport properties and storage capacity of tight sandstone reservoirs. In this work, a series of methods, including X-ray diffraction (XRD) analysis, casting thin sections, scanning electron microscope (SEM), nuclear magnetic resonance (NMR) experiment and multifractal theory were employed to investigate the pore structure and multifractal characteristics of tight sandstones from the Taiyuan Formation in the southern North China Basin. The relationships between petrophysical properties, pore structure, mineral compositions and NMR multifractal parameters were also discussed. Results show that the tight sandstones are characterized by complex and heterogenous pore structure, with apparent multifractal features. The main pore types include clay-dominated micropores and inter- and intragranular dissolution pores. Multifractal parameters of sandstone samples were acquired by NMR and applied to quantitatively describe the pore heterogeneity in higher and lower probability density regions (with respect to small and large pore-scale pore system, respectively). The multifractal parameter (D₋₁₀) of lower probability density areas has better correlation with the petrophysical parameters, which is more suitable for evaluating the reservoir properties of tight sandstone. However, the multifractal parameter (D₁₀) of higher probability density areas is more conducive to characterize the pore structure of tight sandstone. Additionally, the mineral compositions of sandstone have a complex effect on multifractal characteristics of pores in different probability density areas. The D₁₀ increases with the decrease of quartz content and increase in clay mineral content, whereas D₋₁₀ decreases with the increase in clay minerals and decrease of authigenic quartz content and feldspar content. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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20 pages, 3452 KiB

Open AccessArticle

Development and Calibration of a Semianalytic Model for Shale Wells with Nonuniform Distribution of Induced Fractures Based on ES-MDA Method

by Qi Zhang, Shu Jiang, Xinyue Wu, Yan Wang and Qingbang Meng

Energies 2020, 13(14), 3718; https://doi.org/10.3390/en13143718 - 20 Jul 2020

Cited by 5 | Viewed by 2250

Abstract

Given reliable parameters, a newly developed semianalytic model could offer an efficient option to predict the performance of the multi-fractured horizontal wells (MFHWs) in unconventional gas reservoirs. However, two major challenges come from the accurate description and significant parameters uncertainty of stimulated reservoir [...] Read more.

Given reliable parameters, a newly developed semianalytic model could offer an efficient option to predict the performance of the multi-fractured horizontal wells (MFHWs) in unconventional gas reservoirs. However, two major challenges come from the accurate description and significant parameters uncertainty of stimulated reservoir volume (SRV). The objective of this work is to develop and calibrate a semianalytic model using the ensemble smoother with multiple data assimilation (ES-MDA) method for the uncertainty reduction in the description and forecasting of MFHWs with nonuniform distribution of induced fractures. The fractal dimensions of induced-fracture spacing (d_fs) and aperture (d_fa) and tortuosity index of induced-fracture system (θ) are included based on fractal theory to describe the properties of SRV region. Additionally, for shale gas reservoirs, gas transport mechanisms, e.g., viscous flow with slippage, Knudsen diffusion, and surface diffusion, among multi-media including porous kerogen, inorganic matter, and fracture system are taken into account and the model is verified. Then, the effects of the fractal dimensions and tortuosity index of induced fractures on MFHWs performances are analyzed. What follows is employing the ES-MDA method with the presented model to reduce uncertainty in the forecasting of gas production rate for MFHWs in unconventional gas reservoirs using a synthetic case for the tight gas reservoir and a real field case for the shale gas reservoir. The results show that when the fractal dimensions of induced-fracture spacing and aperture is smaller than 2.0 or the tortuosity index of induced-fracture system is larger than 0, the permeability of induced-fracture system decreases with the increase of the distance from hydraulic fractures (HFs) in SRV region. The large d_fs or small θ causes the small average permeability of the induced-fracture system, which results in large dimensionless pseudo-pressure and small dimensionless production rate. The matching results indicate that the proposed method could enrich the application of the semianalytic model in the practical field. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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20 pages, 6841 KiB

Open AccessArticle

Experimental Investigation of the Impacts of Fracturing Fluid on the Evolution of Fluid Composition and Shale Characteristics: A Case Study of the Niutitang Shale in Hunan Province, South China

by Jingqiang Tan, Guolai Li, Ruining Hu, Lei Li, Qiao Lyu and Jeffrey Dick

Energies 2020, 13(13), 3320; https://doi.org/10.3390/en13133320 - 29 Jun 2020

Cited by 4 | Viewed by 2386

Abstract

Hydraulic fracturing is a widely used technique for oil and gas extraction from ultra-low porosity and permeability shale reservoirs. During the hydraulic fracturing process, large amounts of water along with specific chemical additives are injected into the shale reservoirs, causing a series of [...] Read more.

Hydraulic fracturing is a widely used technique for oil and gas extraction from ultra-low porosity and permeability shale reservoirs. During the hydraulic fracturing process, large amounts of water along with specific chemical additives are injected into the shale reservoirs, causing a series of reactions the influence the fluid composition and shale characteristics. This paper is focused on the investigation of the geochemical reactions between shale and fracturing fluid by conducting comparative experiments on different samples at different time scales. By tracking the temporal changes of fluid composition and shale characteristics, we identify the key geochemical reactions during the experiments. The preliminary results show that the dissolution of the relatively unstable minerals in shale, including feldspar, pyrite and carbonate minerals, occurred quickly. During the process of mineral dissolution, a large number of metal elements, such as U, Pb, Ba, Sr, etc., are released, which makes the fluid highly polluted. The fluid–rock reactions also generate many pores, which are mainly caused by dissolution of feldspar and calcite, and potentially can enhance the extraction of shale gas. However, precipitation of secondary minerals like Fe-(oxy) hydroxides and CaSO₄ were also observed in our experiments, which on the one hand can restrict the migration of metal elements by adsorption or co-precipitation and on the other hand can occlude the pores, therefore influencing the recovery of hydrocarbon. The different results between the experiments of different samples revealed that mineralogical texture and composition strongly affect the fluid-rock reactions. Therefore, the identification of the shale mineralogical characteristics is essential to formulate fracturing fluid with the lowest chemical reactivity to avoid the contamination released by flowback waters. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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19 pages, 8967 KiB

Open AccessArticle

Occurrence, Classification and Formation Mechanisms of the Organic-Rich Clasts in the Upper Paleozoic Coal-Bearing Tight Sandstone, Northeastern Margin of the Ordos Basin, China

by Guanqun Yang, Wenhui Huang, Jianhua Zhong and Ningliang Sun

Energies 2020, 13(11), 2694; https://doi.org/10.3390/en13112694 - 27 May 2020

Cited by 4 | Viewed by 2581

Abstract

The detailed characteristics and formation mechanisms of organic-rich clasts (ORCs) in the Upper Paleozoic tight sandstone in the northeastern margin of the Ordos Basin were analyzed through 818-m-long drilling cores and logging data from 28 wells. In general, compared with soft-sediment clasts documented [...] Read more.

The detailed characteristics and formation mechanisms of organic-rich clasts (ORCs) in the Upper Paleozoic tight sandstone in the northeastern margin of the Ordos Basin were analyzed through 818-m-long drilling cores and logging data from 28 wells. In general, compared with soft-sediment clasts documented in other sedimentary environments, organic-rich clasts in coal-bearing tight sandstone have not been adequately investigated in the literature. ORCs are widely developed in various sedimentary environments of coal-bearing sandstone, including fluvial channels, crevasse splays, tidal channels, sand flats, and subaqueous debris flow deposits. In addition to being controlled by the water flow energy and transportation processes, the fragmentation degree and morphology of ORCs are also related to their content of higher plants organic matter. The change in water flow energy during transportation makes the ORCs show obvious mechanical depositional differentiation. Four main types of ORC can be recognized in the deposits: diamictic organic-rich clasts, floating organic-rich clasts, loaded lamellar organic-rich clasts, and thin interlayer organic-rich clasts. The relationship between energy variation and ORCs deposition continuity is rarely studied so far. Based on the different handling processes under the control of water flow energy changes, we propose two ORCs formation mechanisms: the long-term altering of continuous water flow and the short-term water flow acting triggered by sudden events. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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25 pages, 6724 KiB

Open AccessArticle

Reservoir Properties of Low-Permeable Carbonate Rocks: Experimental Features

by Aliya Mukhametdinova, Andrey Kazak, Tagir Karamov, Natalia Bogdanovich, Maksim Serkin, Sergey Melekhin and Alexey Cheremisin

Energies 2020, 13(9), 2233; https://doi.org/10.3390/en13092233 - 3 May 2020

Cited by 17 | Viewed by 4053

Abstract

This paper presents an integrated petrophysical characterization of a representative set of complex carbonate reservoir rock samples with a porosity of less than 3% and permeability of less than 1 mD. Laboratory methods used in this study included both bulk measurements and multiscale [...] Read more.

This paper presents an integrated petrophysical characterization of a representative set of complex carbonate reservoir rock samples with a porosity of less than 3% and permeability of less than 1 mD. Laboratory methods used in this study included both bulk measurements and multiscale void space characterization. Bulk techniques included gas volumetric nuclear magnetic resonance (NMR), liquid saturation (LS), porosity, pressure-pulse decay (PDP), and pseudo-steady-state permeability (PSS). Imaging consisted of thin-section petrography, computed X-ray macro- and microtomography, and scanning electron microscopy (SEM). Mercury injection capillary pressure (MICP) porosimetry was a proxy technique between bulk measurements and imaging. The target set of rock samples included whole cores, core plugs, mini cores, rock chips, and crushed rock. The research yielded several findings for the target rock samples. NMR was the most appropriate technique for total porosity determination. MICP porosity matched both NMR and imaging results and highlighted the different effects of solvent extraction on throat size distribution. PDP core-plug gas permeability measurements were consistent but overestimated in comparison to PSS results, with the difference reaching two orders of magnitude. SEM proved to be the only feasible method for void-scale imaging with a spatial resolution up to 5 nm. The results confirmed the presence of natural voids of two major types. The first type was organic matter (OM)-hosted pores, with dimensions of less than 500 nm. The second type was sporadic voids in the mineral matrix (biogenic clasts), rarely larger than 250 nm. Comparisons between whole-core and core-plug reservoir properties showed substantial differences in both porosity (by a factor of 2) and permeability (up to 4 orders of magnitude) caused by spatial heterogeneity and scaling. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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22 pages, 4080 KiB

Open AccessArticle

Productivity-Index Behavior for a Horizontal Well Intercepted by Multiple Finite-Conductivity Fractures Considering Nonlinear Flow Mechanisms under Steady-State Condition

by Maojun Cao, Hong Xiao and Caizhi Wang

Energies 2020, 13(8), 2015; https://doi.org/10.3390/en13082015 - 17 Apr 2020

Cited by 1 | Viewed by 2919

Abstract

In this paper, a mathematical model is proposed to investigate the effect of nonlinear flow mechanisms on productivity-index (PI) behavior in hydraulically fractured reservoirs during steady-state condition. This approach focuses on the fact that PI approaches a constant value at a certain time, [...] Read more.

In this paper, a mathematical model is proposed to investigate the effect of nonlinear flow mechanisms on productivity-index (PI) behavior in hydraulically fractured reservoirs during steady-state condition. This approach focuses on the fact that PI approaches a constant value at a certain time, indicating the beginning of steady state. In this model, the reservoirs are considered as an elliptical-shaped drainage with constant-pressure boundary, which is depleted by a multiple-fractured horizontal well (MFHW), and various nonlinear flow mechanisms, such as the non-Darcy flow effect and pressure-dependency effect, control flow patterns in the hydraulic fractures. Then, an exact algorithm of solving the resulting nonlinear equations is developed to obtain the PI of MFHW using a semi-analytical approach. Next, type curves are generated to investigate the influences of flow mechanisms and fracture properties on PI. The most interesting points in this study are the following: (1) PI is determined by the properties of MHFW (i.e., dimensions and configuration), the reservoir geometry, and flow mechanism; (2) PI is deteriorated by non-Darcy flow caused by inertial forces; and (3) PI is reduced under the influence of pressure sensitivity caused by the degradation of dynamic conductivity. Generally, this study provides a significant insight into understanding the factors affecting the productivity of a MFHW with nonlinear flow mechanisms. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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20 pages, 7284 KiB

Open AccessArticle

An Analytical Solution for Transient Productivity Prediction of Multi-Fractured Horizontal Wells in Tight Gas Reservoirs Considering Nonlinear Porous Flow Mechanisms

by Qiang Wang, Jifang Wan, Langfeng Mu, Ruichen Shen, Maria Jose Jurado and Yufeng Ye

Energies 2020, 13(5), 1066; https://doi.org/10.3390/en13051066 - 1 Mar 2020

Cited by 12 | Viewed by 2939

Abstract

Multi-fractured horizontal wells (MFHW) is one of the most effective technologies to develop tight gas reservoirs. The gas seepage from tight formations in MFHW can be divided into three stages: early stage with high productivity, transitional stage with declined productivity, and final stage [...] Read more.

Multi-fractured horizontal wells (MFHW) is one of the most effective technologies to develop tight gas reservoirs. The gas seepage from tight formations in MFHW can be divided into three stages: early stage with high productivity, transitional stage with declined productivity, and final stage with stable productivity. Considering the characteristics and mechanisms of porous flows in different regions and at different stages, we derive three coupled equations, namely the equations of porous flow from matrix to fracture, from fracture to near wellbore region, and from new wellbore region to wellbore then an unstable productivity prediction model for a MFHW in a tight gas reservoir is well established. Then, the reliability of this new model, which considers the multi-fracture interference, is verified using a commercial simulator (CMG). Finally, using this transient productivity prediction model, the sensitivity of horizontal well’s productivity to several relevant factors is analyzed. The results illustrate that threshold pressure gradient has the most significant influence on well productivity, followed by stress sensitivity, turbulence flow, and slippage flow. To summarize, the proposed model has demonstrated a potential practical usage to predict the productivity of multi-stage fractured horizontal wells and to analyze the effects of certain factors on gas production in tight gas reservoirs. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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18 pages, 3300 KiB

Open AccessArticle

Prediction of Permeability Using Group Method of Data Handling (GMDH) Neural Network from Well Log Data

by Baraka Mathew Nkurlu, Chuanbo Shen, Solomon Asante-Okyere, Alvin K. Mulashani, Jacqueline Chungu and Liang Wang

Energies 2020, 13(3), 551; https://doi.org/10.3390/en13030551 - 23 Jan 2020

Cited by 26 | Viewed by 3768

Abstract

Permeability is an important petrophysical parameter that controls the fluid flow within the reservoir. Estimating permeability presents several challenges due to the conventional approach of core analysis or well testing, which are expensive and time-consuming. On the contrary, artificial intelligence has been adopted [...] Read more.

Permeability is an important petrophysical parameter that controls the fluid flow within the reservoir. Estimating permeability presents several challenges due to the conventional approach of core analysis or well testing, which are expensive and time-consuming. On the contrary, artificial intelligence has been adopted in recent years in predicting reliable permeability data. Despite its shortcomings of overfitting and low convergence speed, artificial neural network (ANN) has been the widely used artificial intelligent method. Based on this, the present study conducted permeability prediction using the group method of data handling (GMDH) neural network from well log data of the West arm of the East African Rift Valley. Comparative analysis of GMDH permeability model and ANN methods of the back propagation neural network (BPNN) and radial basis function neural network (RBFNN) were further explored. The results of the study showed that the proposed GMDH model outperformed BPNN and RBFNN as it achieved R/root mean square error (RMSE) value of 0.989/0.0241 for training and 0.868/0.204 for predicting, respectively. Sensitivity analysis carried out revealed that shale volume, standard resolution formation density, and thermal neutron porosity were the most influential well log parameters when developing the GMDH permeability model. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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20 pages, 3953 KiB

Open AccessArticle

Finite Element Simulation of Multi-Scale Bedding Fractures in Tight Sandstone Oil Reservoir

by Qianyou Wang, Yaohua Li, Wei Yang, Zhenxue Jiang, Yan Song, Shu Jiang, Qun Luo and Dan Liu

Energies 2020, 13(1), 131; https://doi.org/10.3390/en13010131 - 26 Dec 2019

Cited by 12 | Viewed by 3208

Abstract

Multi-scale bedding fractures, i.e., km-scale regional bedding fractures and cm-scale lamina-induced fractures, have been the focus of unconventional oil and gas exploration and play an important role in resource exploration and drilling practice for tight oil and gas. It is challenging to conduct [...] Read more.

Multi-scale bedding fractures, i.e., km-scale regional bedding fractures and cm-scale lamina-induced fractures, have been the focus of unconventional oil and gas exploration and play an important role in resource exploration and drilling practice for tight oil and gas. It is challenging to conduct numerical simulations of bedding fractures due to the strong heterogeneity without a proper mechanical criterion to predict failure behaviors. This research modified the Tien–Kuo (T–K) criterion by using four critical parameters (i.e., the maximum principal stress (σ₁), minimum principal stress (σ₃), lamina angle (θ), and lamina friction coefficient (μ_lamina)). The modified criterion was compared to other bedding failure criteria to make a rational finite element simulation constrained by the four variables. This work conducted triaxial compression tests of 18 column samples with different lamina angles to verify the modified rock failure criterion, which contributes to the simulation work on the multi-scale bedding fractures in the statics module of the ANSYS workbench. The cm-scale laminated rock samples and the km-scale Yanchang Formation in the Ordos Basin were included in the multi-scale geo-models. The simulated results indicate that stress is prone to concentrate on lamina when the lamina angle is in an effective range. The low-angle lamina always induces fractures in an open state with bigger failure apertures, while the medium-angle lamina tends to induce fractures in a shear sliding trend. In addition, the regional bedding fractures of the Yanchang Formation in the Himalayan tectonic period tend to propagate under the conditions of lower maximum principal stress, higher minimum principal stress, and larger stratigraphic dip. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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Review

Jump to: Research

50 pages, 11829 KiB

Open AccessReview

Review of Formation and Gas Characteristics in Shale Gas Reservoirs

by Boning Zhang, Baochao Shan, Yulong Zhao and Liehui Zhang

Energies 2020, 13(20), 5427; https://doi.org/10.3390/en13205427 - 17 Oct 2020

Cited by 33 | Viewed by 4625

Abstract

An accurate understanding of formation and gas properties is crucial to the efficient development of shale gas resources. As one kind of unconventional energy, shale gas shows significant differences from conventional energy ones in terms of gas accumulation processes, pore structure characteristics, gas [...] Read more.

An accurate understanding of formation and gas properties is crucial to the efficient development of shale gas resources. As one kind of unconventional energy, shale gas shows significant differences from conventional energy ones in terms of gas accumulation processes, pore structure characteristics, gas storage forms, physical parameters, and reservoir production modes. Traditional experimental techniques could not satisfy the need to capture the microscopic characteristics of pores and throats in shale plays. In this review, the uniqueness of shale gas reservoirs is elaborated from the perspective of: (1) geological and pore structural characteristics, (2) adsorption/desorption laws, and (3) differences in properties between the adsorbed gas and free gas. As to the first aspect, the mineral composition and organic geochemical characteristics of shale samples from the Longmaxi Formation, Sichuan Basin, China were measured and analyzed based on the experimental results. Principles of different methods to test pore size distribution in shale formations are introduced, after which the results of pore size distribution of samples from the Longmaxi shale are given. Based on the geological understanding of shale formations, three different types of shale gas and respective modeling methods are reviewed. Afterwards, the conventional adsorption models, Gibbs excess adsorption behaviors, and supercritical adsorption characteristics, as well as their applicability to engineering problems, are introduced. Finally, six methods of calculating virtual saturated vapor pressure, seven methods of giving adsorbed gas density, and 12 methods of calculating gas viscosity in different pressure and temperature conditions are collected and compared, with the recommended methods given after a comparison. Full article

(This article belongs to the Special Issue Development of Unconventional Reservoirs 2020)

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