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

Deadline for manuscript submissions: closed (30 September 2021) | Viewed by 24617

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Dr. José A. Torres

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Guest Editor

Computational Hydrocarbon Laboratory for Optimized Energy Efficiency, University of Pau and Pays de l’Adour, 64012 Pau, France
Interests: reservoir engineering; reservoir simulation; enhanced oil recovery; unconventional reservoirs; data analysis; machine learning; advanced reservoir monitoring systems
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Special Issue Information

Dear Colleagues,

We are pleased to invite you to submit papers to the journal Energies for a Special Issue that will be entirely devoted to “Advances in Shale Oil and Shale Gas Technologies”. The Special Issue will expand on essential technical challenges for improving the understanding and management of these unconventional reservoirs. This Special Issue will serve as an excellent channel for sharing information and lessons learned, collected from different plays.

The relatively short production span observed in unconventional reservoirs demands novel solutions for optimizing drilling, completion, and improved recovery efficiencies. On the other hand, the consolidation and analysis of multiple sources of data are becoming key enablers for the discovery of strong production drivers and building predictive models for complex rock-fluid interactions on fractured media. This issue will seek to ignite contrasting perspectives towards optimal shale play management.

Potential topics of interest include, but are not limited to:

Advances in shale reservoir characterization techniques and workflows;
Analysis of physical-chemical interactions of shale rocks with drilling, injected, or in-situ fluids;
Novel technologies to address the complex challenges in the modeling and simulation of hydrocarbon production from shale formations;
Geomechanical aspects and impacts on shale reservoirs;
Novel methods for enhanced hydrocarbon recovery in shale reservoirs;
Machine learning and data science applications for unlocking new insights in shale resources exploitation;
Best practices and lessons learned from field applications.

Dr. José A. Torres
Guest Editor

Manuscript Submission Information

Manuscripts should be submitted online at www.mdpi.com by registering and logging in to this website. Once you are registered, click here to go to the submission form. Manuscripts can be submitted until the deadline. All submissions that pass pre-check are peer-reviewed. Accepted papers will be published continuously in the journal (as soon as accepted) and will be listed together on the special issue website. Research articles, review articles as well as short communications are invited. For planned papers, a title and short abstract (about 100 words) can be sent to the Editorial Office for announcement on this website.

Submitted manuscripts should not have been published previously, nor be under consideration for publication elsewhere (except conference proceedings papers). All manuscripts are thoroughly refereed through a single-blind peer-review process. A guide for authors and other relevant information for submission of manuscripts is available on the Instructions for Authors page. Energies is an international peer-reviewed open access semimonthly journal published by MDPI.

Please visit the Instructions for Authors page before submitting a manuscript. The Article Processing Charge (APC) for publication in this open access journal is 2600 CHF (Swiss Francs). Submitted papers should be well formatted and use good English. Authors may use MDPI's English editing service prior to publication or during author revisions.

Keywords

unconventional resources
shale gas
shale oil
shale plays
fractured media
hydraulic fracturing
completions
coupled flow and geomechanics
machine learning
data-driven models

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Published Papers (9 papers)

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Research

18 pages, 5338 KiB

Open AccessArticle

Experimental Investigation on the Characteristic Mobilization and Remaining Oil Distribution under CO₂ Huff-n-Puff of Chang 7 Continental Shale Oil

by Jianhong Zhu, Junbin Chen, Xiaoming Wang, Lingyi Fan and Xiangrong Nie

Energies 2021, 14(10), 2782; https://doi.org/10.3390/en14102782 - 12 May 2021

Cited by 16 | Viewed by 2090

Abstract

The Chang 7 continental shale oil reservoir is tight. The recovery factor is extremely low, the remaining oil is very high, and injecting water to improve oil recovery effectiveness is too hard. Therefore, in this paper, physical simulation experiments of CO₂ huff-n-puff shale oil and NMR tests were conducted to study the cycle numbers and permeability on the recovery degree, as well as the characteristics of shale oil mobilization and the remaining oil micro distribution. The results showed that the cumulative oil recovery factors (ORFs) gradually increased in the natural logarithmic form, the single cycle ORFs decreased rapidly in exponential form with the huff-n-puff cycle number, and the biggest economic cycle numbers were between approximately 3 and 5. Furthermore, the higher the permeability, the higher the ORF, but the difference of ORF decreased between the two experimental samples with the cycles. In addition, the gap of production and recovery degree was large between the different scale pores, the ORF of macropores was 6–8 times that of micropores, and the final remaining oil was mainly distributed in the micropores, accounting for 82.29% of the total amount; meanwhile, the macropores comprised less than 0.5%. In the process of huff-n-puff, CO₂ flowed into macropores, mesopores, and smallpores under the pressure differential effect, but a small amount of CO₂ slowly diffused into micropores, resulting in the ORF of the former with more free oil being higher and the ORF of micropores with more adsorbed oil being lower. Therefore, promoting a better contact and reaction between CO₂ and shale oil of micropores is one of the key ways to effectively develop the Chang 7 continental shale oil and enhance oil recovery. Full article

(This article belongs to the Special Issue Advances in Shale Oil and Shale Gas Technologies)

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16 pages, 5650 KiB

Open AccessFeature PaperArticle

Coupling between Source Rock and Reservoir of Shale Gas in Wufeng-Longmaxi Formation in Sichuan Basin, South China

by Yuying Zhang, Shu Jiang, Zhiliang He, Yuchao Li, Dianshi Xiao, Guohui Chen and Jianhua Zhao

Energies 2021, 14(9), 2679; https://doi.org/10.3390/en14092679 - 7 May 2021

Cited by 9 | Viewed by 1969

Abstract

In order to analyze the main factors controlling shale gas accumulation and to predict the potential zone for shale gas exploration, the heterogeneous characteristics of the source rock and reservoir of the Wufeng-Longmaxi Formation in Sichuan Basin were discussed in detail, based on the data of petrology, sedimentology, reservoir physical properties and gas content. On this basis, the effect of coupling between source rock and reservoir on shale gas generation and reservation has been analyzed. The Wufeng-Longmaxi Formation black shale in the Sichuan Basin has been divided into 5 types of lithofacies, i.e., carbonaceous siliceous shale, carbonaceous argillaceous shale, composite shale, silty shale, and argillaceous shale, and 4 types of sedimentary microfacies, i.e., carbonaceous siliceous deep shelf, carbonaceous argillaceous deep shelf, silty argillaceous shallow shelf, and argillaceous shallow shelf. The total organic carbon (TOC) content ranged from 0.5% to 6.0% (mean 2.54%), which gradually decreased vertically from the bottom to the top and was controlled by the oxygen content of the bottom water. Most of the organic matter was sapropel in a high-over thermal maturity. The shale reservoir of Wufeng-Longmaxi Formation was characterized by low porosity and low permeability. Pore types were mainly <10 nm organic pores, especially in the lower member of the Longmaxi Formation. The size of organic pores increased sharply in the upper member of the Longmaxi Formation. The volumes of methane adsorption were between 1.431 m³/t and 3.719 m³/t, and the total gas contents were between 0.44 m³/t and 5.19 m³/t, both of which gradually decreased from the bottom upwards. Shale with a high TOC content in the carbonaceous siliceous/argillaceous deep shelf is considered to have significant potential for hydrocarbon generation and storage capacity for gas preservation, providing favorable conditions of the source rock and reservoir for shale gas. Full article

(This article belongs to the Special Issue Advances in Shale Oil and Shale Gas Technologies)

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25 pages, 5219 KiB

Open AccessArticle

Development of a Permeability Formula for Tight and Shale Gas Reservoirs Based on Advanced High-Precision Lab Measurement Techniques

by Paulina Krakowska-Madejska, Edyta Puskarczyk, Magdalena Habrat, Paweł Madejski, Marek Dohnalik and Mariusz Jędrychowski

Energies 2021, 14(9), 2628; https://doi.org/10.3390/en14092628 - 4 May 2021

Cited by 1 | Viewed by 1967

Abstract

Computed X-ray tomography (CT), together with pulse and pressure decay permeability methods were used to evaluate a formula for absolute reservoir permeability. For this reason, 62 core samples representing geological material of tight, gas-bearing sandstones, mudstones, limestones, and dolostones were studied. Samples were divided into two groups with lower and higher permeability values. Images of the pore space were processed and interpreted to obtain geometrical parameters of the objects (pores, microfractures) with 0.5 × 0.5 × 0.5 µm³ voxel size. Statistical methods, which included basic statistical analysis, linear regression, and multiple linear regression analysis, were combined to evaluate the formula for absolute permeability. It appeared that the following parameters: Feret Breadth/Volume, Flatness/Anisotropy, Feret Max/Flatness, moments of inertia around middle principal axis I2/around longest principal axis I3, Anisotropy/Flatness, Flatness/Anisotropy provided the best results. The presented formula was obtained for a large set of data and is based only on the geometric parameters of the pore space. The novelty of the work is connected with the estimation of absolute permeability using only data from the CT method for tight rocks. Full article

(This article belongs to the Special Issue Advances in Shale Oil and Shale Gas Technologies)

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17 pages, 4349 KiB

Open AccessArticle

Distribution Model of Fluid Components and Quantitative Calculation of Movable Oil in Inter-Salt Shale Using 2D NMR

by Weichao Yan, Fujing Sun, Jianmeng Sun and Naser Golsanami

Energies 2021, 14(9), 2447; https://doi.org/10.3390/en14092447 - 25 Apr 2021

Cited by 8 | Viewed by 2139

Abstract

Some inter-salt shale reservoirs have high oil saturations but the soluble salts in their complex lithology pose considerable challenges to their production. Low-field nuclear magnetic resonance (NMR) has been widely used in evaluating physical properties, fluid characteristics, and fluid saturation of conventional oil and gas reservoirs as well as common shale reservoirs. However, the fluid distribution analysis and fluid saturation calculations in inter-salt shale based on NMR results have not been investigated because of existing technical difficulties. Herein, to explore the fluid distribution patterns and movable oil saturation of the inter-salt shale, a specific experimental scheme was designed which is based on the joint adaptation of multi-state saturation, multi-temperature heating, and NMR measurements. This novel approach was applied to the inter-salt shale core samples from the Qianjiang Sag of the Jianghan Basin in China. The experiments were conducted using two sets of inter-salt shale samples, namely cylindrical and powder samples. Additionally, by comparing the one-dimensional (1D) and two-dimensional (2D) NMR results of these samples in oil-saturated and octamethylcyclotetrasiloxane-saturated states, the distributions of free movable oil and water were obtained. Meanwhile, the distributions of the free residual oil, adsorbed oil, and kerogen in the samples were obtained by comparing the 2D NMR T₁-T₂ maps of the original samples with the sample heated to five different temperatures of 80, 200, 350, 450, and 600 °C. This research puts forward a 2D NMR identification graph for fluid components in the inter-salt shale reservoirs. Our experimental scheme effectively solves the problems of fluid composition distribution and movable oil saturation calculation in the study area, which is of notable importance for subsequent exploration and production practices. Full article

(This article belongs to the Special Issue Advances in Shale Oil and Shale Gas Technologies)

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18 pages, 3992 KiB

Open AccessArticle

Perforation Optimization of Intensive-Stage Fracturing in a Horizontal Well Using a Coupled 3D-DDM Fracture Model

by Wan Cheng, Chunhua Lu and Bo Xiao

Energies 2021, 14(9), 2393; https://doi.org/10.3390/en14092393 - 23 Apr 2021

Cited by 8 | Viewed by 2018

Abstract

Intensive-stage fracturing in horizontal wells is a potentially new technology for reservoir stimulations of deep shale oil and gas. Due to a strong stress interaction among the dense fractures, the fracture geometry and stress field are very complicated, which are the bottlenecks of this technology. Aiming at simulating the intensive-stage fracturing, a coupled three-dimensional (3D) fracture model of multiple-fracture simultaneous propagation is proposed. The dynamic behavior of the fracture propagation and stress field was analyzed using this model. The perforation parameters were optimized for improving the fracture geometry equilibrium. The results showed that the exterior fractures of the multiple fractures penetrated by the horizontal well become the main fractures, while the interior fractures are drastically restrained. The exterior fracture widths increased with increasing injection time, while the interior fracture widths decreased with increasing injection time. An extruded region was created among the multiple fractures, which restrained the propagation of the interior fractures. Only increasing the perforation cluster number did not improve the fracture geometry equilibrium in the intensive-stage fracturing. To improve the fracture geometry equilibrium, we suggest designing more perforation numbers in each perforation cluster and ensuring that both the perforation number and diameter in the interior perforation cluster are greater than those of the exterior ones. Full article

(This article belongs to the Special Issue Advances in Shale Oil and Shale Gas Technologies)

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24 pages, 12964 KiB

Open AccessFeature PaperArticle

Recovery Mechanisms for Cyclic (Huff-n-Puff) Gas Injection in Unconventional Reservoirs: A Quantitative Evaluation Using Numerical Simulation

by B. Todd Hoffman and David Reichhardt

Energies 2020, 13(18), 4944; https://doi.org/10.3390/en13184944 - 21 Sep 2020

Cited by 10 | Viewed by 2805

Abstract

Unconventional reservoirs produce large volumes of oil; however, recovery factors are low. While enhanced oil recovery (EOR) with cyclic gas injection can increase recovery factors in unconventional reservoirs, the mechanisms responsible for additional recovery are not well understood. We examined cyclic gas injection recovery mechanisms in unconventional reservoirs including oil swelling, viscosity reduction, vaporization, and pressure support using a numerical flow model as functions of reservoir fluid gas–oil ratio (GOR), and we conducted a sensitivity analysis of the mechanisms to reservoir properties and injection conditions. All mechanisms studied contributed to the additional recovery, but their significance varied with GOR. Pressure support provides a small response for all fluid types. Vaporization plays a role for all fluids but is most important for gas condensate reservoirs. Oil swelling impacts low-GOR oils but diminishes for higher-GOR oil. Viscosity reduction plays a minor role for low-GOR cases. As matrix permeability and fracture surface area increase, the importance of gas injection decreases because of the increased primary oil production. Changes to gas injection conditions that increase injection maturity (longer injection times, higher injection rates, and smaller fracture areas) result in more free gas and, for these cases, vaporization becomes important. Recovery mechanisms for cyclic gas injection are now better understood and can be adapted to varying conditions within unconventional plays, resulting in better EOR designs and improved recovery. Full article

(This article belongs to the Special Issue Advances in Shale Oil and Shale Gas Technologies)

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16 pages, 13739 KiB

Open AccessArticle

Machine Learning: A Useful Tool in Geomechanical Studies, a Case Study from an Offshore Gas Field

by Seyedalireza Khatibi and Azadeh Aghajanpour

Energies 2020, 13(14), 3528; https://doi.org/10.3390/en13143528 - 8 Jul 2020

Cited by 17 | Viewed by 3776

Abstract

For a safe drilling operation with the of minimum borehole instability challenges, building a mechanical earth model (MEM) has proven to be extremely valuable. However, the natural complexity of reservoirs along with the lack of reliable information leads to a poor prediction of geomechanical parameters. Shear wave velocity has many applications, such as in petrophysical and geophysical as well as geomechanical studies. However, occasionally, wells lack shear wave velocity (especially in old wells), and estimating this parameter using other well logs is the optimum solution. Generally, available empirical relationships are being used, while they can only describe similar formations and their validation needs calibration. In this study, machine learning approaches for shear sonic log prediction were used. The results were then compared with each other and the empirical Greenberg–Castagna method. Results showed that the artificial neural network has the highest accuracy of the predictions over the single and multiple linear regression models. This improvement is more highlighted in hydrocarbon-bearing intervals, which is considered as a limitation of the empirical or any linear method. In the next step, rock elastic properties and in-situ stresses were calculated. Afterwards, in-situ stresses were predicted and coupled with a failure criterion to yield safe mud weight windows for wells in the field. Predicted drilling events matched quite well with the observed drilling reports. Full article

(This article belongs to the Special Issue Advances in Shale Oil and Shale Gas Technologies)

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21 pages, 13955 KiB

Open AccessArticle

Effect of Complex Natural Fractures on Economic Well Spacing Optimization in Shale Gas Reservoir with Gas-Water Two-Phase Flow

by Cheng Chang, Yongming Li, Xiaoping Li, Chuxi Liu, Mauricio Fiallos-Torres and Wei Yu

Energies 2020, 13(11), 2853; https://doi.org/10.3390/en13112853 - 3 Jun 2020

Cited by 7 | Viewed by 3111

Abstract

At present, investigation of the effects of natural fractures on optimal well spacing of shale gas reservoirs from an economic perspective has been lacking. Traditional frameworks of fracture characterization, such as local grid refinement, make it unfeasible and inaccurate to study these effects of high-density natural fractures with complex geometries on well spacing. In this study, the non-intrusive EDFM (embedded discrete fracture model) method was presented to characterize fractures fast and accurately. The non-intrusiveness of EDFM removed the necessity of accessing the codes behind reservoir simulators, which meant it could simply create associated keywords that would correspondingly modify these fracture properties in separate files without information regarding the source codes. By implementing this powerful technology, a field-scale shale gas reservoir model was set up, including two-phase flow. The effective properties of hydraulic fractures were determined from the history matching process, and the results were entered into the well spacing optimization workflow. Different scenarios of natural fracture (NF) distributions and well spacing were designed, and the final economic analysis for each case was explored based on simulated productions. As a result, one of the findings of this study was that optimal well spacing tended to increase if more natural fractures were presented in the reservoir. Full article

(This article belongs to the Special Issue Advances in Shale Oil and Shale Gas Technologies)

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19 pages, 5303 KiB

Open AccessArticle

Surrogate Models for Studying the Wettability of Nanoscale Natural Rough Surfaces Using Molecular Dynamics

by Lingru Zheng, Maja Rücker, Tom Bultreys, Apostolos Georgiadis, Miranda M. Mooijer-van den Heuvel, Fernando Bresme, J. P. Martin Trusler and Erich A. Müller

Energies 2020, 13(11), 2770; https://doi.org/10.3390/en13112770 - 1 Jun 2020

Cited by 12 | Viewed by 3509

Abstract

A molecular modeling methodology is presented to analyze the wetting behavior of natural surfaces exhibiting roughness at the nanoscale. Using atomic force microscopy, the surface topology of a Ketton carbonate is measured with a nanometer resolution, and a mapped model is constructed with the aid of coarse-grained beads. A surrogate model is presented in which surfaces are represented by two-dimensional sinusoidal functions defined by both an amplitude and a wavelength. The wetting of the reconstructed surface by a fluid, obtained through equilibrium molecular dynamics simulations, is compared to that observed by the different realizations of the surrogate model. A least-squares fitting method is implemented to identify the apparent static contact angle, and the droplet curvature, relative to the effective plane of the solid surface. The apparent contact angle and curvature of the droplet are then used as wetting metrics. The nanoscale contact angle is seen to vary significantly with the surface roughness. In the particular case studied, a variation of over 65° is observed between the contact angle on a flat surface and on a highly spiked (Cassie–Baxter) limit. This work proposes a strategy for systematically studying the influence of nanoscale topography and, eventually, chemical heterogeneity on the wettability of surfaces. Full article

(This article belongs to the Special Issue Advances in Shale Oil and Shale Gas Technologies)

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