Special Issue "Shale and Tight Reservoir Characterization and Resource Assessment"

A special issue of Minerals (ISSN 2075-163X). This special issue belongs to the section "Mineral Exploration Methods and Applications".

Deadline for manuscript submissions: closed (15 August 2022) | Viewed by 4562

Special Issue Editors

Dr. Chunqing Jiang
E-Mail Website
Guest Editor
Natural Resources Canada, Geological Survey of Canada, 3303-33 Street NW, Calgary, AB T2L 2A7, Canada
Interests: petroleum system, unconventional resources, organic geochemistry, shale gas and oil, flowback water, produced water, petroleum brine, lithium, critical metals, CCUS
Dr. Omid Ardakani
E-Mail Website
Guest Editor
Natural Resources Canada, Geological Survey of Canada, 3303 33 Street NW, Calgary, AB T2L 2A7, Canada
Interests: unconventional resources, organic petrography, shale reservoir characterization, shale diagenesis, sedimentary geochemistry, paleo-rodox proxies, CCUS
Dr. Tristan Euzen
E-Mail Website
Guest Editor
IFP Technologies (Canada) Inc., Calgary, AB T2P 3T4, Canada
Interests: unconventional resources; petroleum systems; sequence stratigraphy and sedimentology; hydrodynamics; oil and gas geochemistry

Special Issue Information

Dear Colleagues,

This Special Issue of Minerals aims to present a set of diversely themed articles from researches focused on economically efficient and environmentally sustainable exploitation of both energy and mineral resources hosted in the unconventional shale and tight gas/oil reservoirs. Topics of interest will include:

  • Reviews of shale and tight hydrocarbon resources on basinal, regional or global scales;
  • Reviews of petrophysical, geochemical and petrographic techniques and procedures for the characterization of shale and tight reservoirs and the associated hydrocarbon fluids;
  • Case studies of typical shale and tight gas/oil plays worldwide;
  • Phase behavior and production fractionation in shale and tight gas reservoirs;
  • Emerging methods and concepts for the exploration and appraisal of unconventional resources;
  • Hydrodynamics, pressure regime and petroleum system analysis of shale and tight gas resources;
  • Application of artificial intelligence (AI) and machine learning for effective and efficient extraction of valid reservoir property information from various types of geological and laboratory-generated data;
  • Mineral resources, especially critical metals contained in shale and tight formations as well as the operational flowback and produced water;
  • Potential utilization of geothermal energy associated with deep unconventional hydrocarbon production;
  • Application of CO2-EOR to shale and tight reservoirs, and its potential for carbon capture, utilization and storage (CCUS);
  • Origin and formation mechanism of hydrogen sulfide (H2S) associated shale and tight resource production and risk mitigation;
  • Shale diagensis, mineralogical evolution and its effect on shale reservoir characteristics.

Dr. Chunqing Jiang
Dr. Omid Ardakani
Dr. Tristan Euzen
Guest Editors

Manuscript Submission Information

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Keywords

  • shale gas
  • shale oil
  • shale and tight reservoir
  • unconventional reservoir
  • lithium
  • pore
  • porosity
  • permeability
  • CCUS
  • CO2-EOR
  • geothermal energy
  • H2S
  • flowback and produced water
  • hydrocarbon
  • pore size distribution
  • shale diagenesis
  • organic-hosted pores
  • thermal maturity
  • scanning electron microscopy (SEM)
  • shale mineralogy
  • clay minerals

Published Papers (7 papers)

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Research

Article
Investigation on Oil Physical States of Hybrid Shale Oil System: A Case Study on Cretaceous Second White Speckled Shale Formation from Highwood River Outcrop, Southern Alberta
Minerals 2022, 12(7), 802; https://doi.org/10.3390/min12070802 - 24 Jun 2022
Viewed by 334
Abstract
Nine samples collected from the Upper Cretaceous Second White Speckled Shale Formation at the Highwood River outcrop in southern Alberta were geochemically characterized for their oil contents, physical states, and chemical compositions. Cold extraction was performed on 8–10 mm and 2–5 mm chips [...] Read more.
Nine samples collected from the Upper Cretaceous Second White Speckled Shale Formation at the Highwood River outcrop in southern Alberta were geochemically characterized for their oil contents, physical states, and chemical compositions. Cold extraction was performed on 8–10 mm and 2–5 mm chips sequentially to obtain the first and second extractable organic matter (EOM-1 and EOM-2), while Soxhlet extraction was performed on powder from previously extracted chips to obtain the third extract (EOM-3). EOM-1 can be roughly regarded as free oil and EOM-2 is weakly adsorbed on mineral surfaces, while EOM-3 may represent the oil strongly adsorbed on kerogen. While both extraction yields and Rock-Eval pyrolysates differed from their original values due to the evaporative loss during outcropping, there was a generally positive correlation between the total EOM and total oil derived from Rock-Eval pyrolysis. EOM-1 was linearly correlated with Rock-Eval S1, while the extractable S2 content was well correlated with the loss of TOC, suggesting that TOC content was the main constraint for adsorbed oils. A bulk composition analysis illustrated that EOM-1 contained more saturated hydrocarbons, while EOM-3 was enriched in resins and asphaltenes. More detailed fractionation between the free and adsorbed oils was demonstrated by molecular compositions of each extract using quantitative GC-MS analysis. Lower-molecular-weight n-alkanes and smaller-ring-number aromatic compounds were preferentially concentrated in EOM-1 as compared to their higher-molecular or greater-ring-number counterparts and vice versa for EOM-3. Fractionation between isoprenoids and adjacent eluted n-alkanes, isomers of steranes, hopanes, alkylnaphthalenes, alkylphenanthrenes and alkyldibenzothiophenes was insignificant, suggesting no allogenic charge from deep strata. Strong chemical fractionation between saturated and aromatic hydrocarbon fractions was observed with EOM-1 apparently enriched in n-alkanes, while EOM-3 retained more aromatic hydrocarbons. However, the difference between free and adsorbed state oils was less dramatic than the variation from shales and siltstones. Lithological heterogeneities controlled both the amount and composition of retained fluids. Oil that resided in shales (source rock) behaved more similar to the EOM-3, with diffusive expulsion leading to the release of discrete molecules from a more adsorbed or occluded phase to a more free phase in siltstones with more connected pores and/or fractures (reservoir). Under current technical conditions, only the free oil can flow and will be the recoverable resource. Therefore, the highest potential can be expected from intervals adjacent to organic-rich beds. The compositional variations due to expulsion and primary migration from source rocks to reservoirs illustrated in the present study will contribute to a better understanding of the distribution of hydrocarbons generated and stored within the shale plays. Full article
(This article belongs to the Special Issue Shale and Tight Reservoir Characterization and Resource Assessment)
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Article
CO2-Enhanced Oil Recovery Mechanism in Canadian Bakken Shale
Minerals 2022, 12(6), 779; https://doi.org/10.3390/min12060779 - 19 Jun 2022
Viewed by 551
Abstract
The recovery factor in unconventional reservoirs is typically 5–10%, with extensive hydraulic fracturing and infill drilling to maintain the production rate. Concurrently, the rush towards decarbonization is opening up new possibilities for CO2 utilization, enhanced oil recovery (EOR) being one example. CO [...] Read more.
The recovery factor in unconventional reservoirs is typically 5–10%, with extensive hydraulic fracturing and infill drilling to maintain the production rate. Concurrently, the rush towards decarbonization is opening up new possibilities for CO2 utilization, enhanced oil recovery (EOR) being one example. CO2-EOR in unconventional reservoirs presents an opportunity for both financial gain through improved recovery factors, as well as reducing the carbon footprint of the produced oil. In this work, we examine the CO2-EOR potential in 4 organic-rich shale samples from the Canadian Bakken Formation. A number of characterization tests alongside CO2 extraction experiments were performed to gain insight into the controlling factors of CO2-EOR in these ultra-tight formations. The results show CO2 can penetrate the tight rock matrix and recover a substantial amount of hydrocarbon. Concentration gradient driven diffusion is the dominant form of recovery. Full article
(This article belongs to the Special Issue Shale and Tight Reservoir Characterization and Resource Assessment)
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Article
Modeling of Brine/CO2/Mineral Wettability Using Gene Expression Programming (GEP): Application to Carbon Geo-Sequestration
Minerals 2022, 12(6), 760; https://doi.org/10.3390/min12060760 - 15 Jun 2022
Viewed by 442
Abstract
Carbon geo-sequestration (CGS), as a well-known procedure, is employed to reduce/store greenhouse gases. Wettability behavior is one of the important parameters in the geological CO2 sequestration process. Few models have been reported for characterizing the contact angle of the brine/CO2/mineral [...] Read more.
Carbon geo-sequestration (CGS), as a well-known procedure, is employed to reduce/store greenhouse gases. Wettability behavior is one of the important parameters in the geological CO2 sequestration process. Few models have been reported for characterizing the contact angle of the brine/CO2/mineral system at different environmental conditions. In this study, a smart machine learning model, namely Gene Expression Programming (GEP), was implemented to model the wettability behavior in a ternary system of CO2, brine, and mineral under different operating conditions, including salinity, pressure, and temperature. The presented models provided an accurate estimation for the receding, static, and advancing contact angles of brine/CO2 on various minerals, such as calcite, feldspar, mica, and quartz. A total of 630 experimental data points were utilized for establishing the correlations. Both statistical evaluation and graphical analyses were performed to show the reliability and performance of the developed models. The results showed that the implemented GEP model accurately predicted the wettability behavior under various operating conditions and a few data points were detected as probably doubtful. The average absolute percent relative error (AAPRE) of the models proposed for calcite, feldspar, mica, and quartz were obtained as 5.66%, 1.56%, 14.44%, and 13.93%, respectively, which confirm the accurate performance of the GEP algorithm. Finally, the investigation of sensitivity analysis indicated that salinity and pressure had the utmost influence on contact angles of brine/CO2 on a range of different minerals. In addition, the effect of the accurate estimation of wettability on CO2 column height for CO2 sequestration was illustrated. According to the impact of wettability on the residual and structural trapping mechanisms during the geo-sequestration of the carbon process, the outcomes of the GEP model can be beneficial for the precise prediction of the capacity of these mechanisms. Full article
(This article belongs to the Special Issue Shale and Tight Reservoir Characterization and Resource Assessment)
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Article
Reservoir Characterization of a Tight Gas Field Using New Modified Type Curves for Production Data Analysis—A Case Study from Ordos Basin
Minerals 2022, 12(6), 675; https://doi.org/10.3390/min12060675 - 27 May 2022
Viewed by 430
Abstract
Using data from 56 tight gas wells from the study field (Y field) in the Ordos basin of China, this paper presents performance-based reservoir characterization of the study field from production data and geophysical data. Post-fracturing evaluation is realized by applying our new [...] Read more.
Using data from 56 tight gas wells from the study field (Y field) in the Ordos basin of China, this paper presents performance-based reservoir characterization of the study field from production data and geophysical data. Post-fracturing evaluation is realized by applying our new modified production decline type curves for fractured wells. Compared to traditional type curves, our newly proposed modified dimensionless type curves help identify field data diagnostics for various flow regimes of fractured wells and also facilitate the curve matching process with real data to obtain fruitful and crucial reservoir and fractured well information, including key parameters such as reservoir flowing capacity (kh), well productivity, fracture length, drainage area and original gas in place. This paper intends to promote the extensive application of this new technique. With the support of the reservoir information provided by production decline analysis using our modified type curves, the commercial flow units are delineated in terms of interrelated porosity-permeability of sandstone based on pore throat aperture crossplotting and corresponding flow unit productivity. Furthermore, two crossplots of well logging interpreted porosity versus resistivity are constructed, suggesting their good correlated relationships with relative flow unit productivity and initial gas abundance in place, respectively. The two crossplots enable qualitative evaluation of formation penetrated by well, which makes them very useful and practical as wireline logging is basically available for every well. The well production routine is also analyzed systematically by considering a well’s inflow performance, tubing performance and minimal liquid-carrying gas flow rate to investigate if a gas well is producing at optimal conditions or if a measure should be taken to improve the well’s production. Through analysis of the Y field, this study introduces an integrated workflow with the support of the new modified type curves to effectively help understand the reservoir characteristics and the flow behaviors of the tight gas field. The key takeaway from this study is that the new modified dimensionless production decline curves in terms of qDM vs. tDM can be applied in field practice to achieve a systematically comparable understanding of the performance of MHFHWs globally. Full article
(This article belongs to the Special Issue Shale and Tight Reservoir Characterization and Resource Assessment)
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Article
Semi-Analytical Modeling of Geological Features Based Heterogeneous Reservoirs Using the Boundary Element Method
Minerals 2022, 12(6), 663; https://doi.org/10.3390/min12060663 - 24 May 2022
Viewed by 492
Abstract
The objective of this work is to innovatively apply the boundary element method (BEM) as a general modeling strategy to deal with complicated reservoir modeling problems, especially those related to reservoir heterogeneity and fracture systems, which are common challenges encountered in the practice [...] Read more.
The objective of this work is to innovatively apply the boundary element method (BEM) as a general modeling strategy to deal with complicated reservoir modeling problems, especially those related to reservoir heterogeneity and fracture systems, which are common challenges encountered in the practice of reservoir engineering. The transient flow behaviors of reservoirs containing multi-scale heterogeneities enclosed by arbitrarily shaped boundaries are modeled by applying BEM. We demonstrate that a BEM-based simulation strategy is capable of modeling complex heterogeneous reservoirs with robust solutions. The technology is beneficial in making the best use of geological modeling information. The governing differential operator of fluid flow within any locally homogeneous domain is solved along its boundary. The discretization of a reservoir system is only made on the corresponding boundaries, which is advantageous in closely conforming to the reservoir’s geological description and in facilitating the numerical simulation and computational efforts because no gridding within the flow domain is needed. Theoretical solutions, in terms of pressure and flow rate responses, are validated and exemplified for various reservoir–well systems, including naturally fractured reservoirs with either non-crossing fractures or crossing fractures; fully compartmentalized reservoirs; and multi-stage, fractured, horizontal wells with locally stimulated reservoir volumes (SRVs) around each stage of the fracture, etc. A challenging case study for a complicated fracture network system is examined. This work demonstrates the significance of adapting the BEM strategy for reservoir simulation due to its flexibility in modeling reservoir heterogeneity, analytical solution accuracy, and high computing efficiency, in reducing the technical gap between reservoir engineering practice and simulation capacity. Full article
(This article belongs to the Special Issue Shale and Tight Reservoir Characterization and Resource Assessment)
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Article
Effects of Regional Differences in Shale Floor Interval on the Petrophysical Properties and Shale Gas Prospects of the Overmature Niutitang Shale, Middle-Upper Yangtz Block
Minerals 2022, 12(5), 539; https://doi.org/10.3390/min12050539 - 26 Apr 2022
Viewed by 532
Abstract
The lower Cambrian Niutitang/Qiongzhusi shale gas in the Middle-Upper Yangtz Block had been regarded as a very promising unconventional natural gas resource due to its high total organic carbon, great thickness, and large areal distribution. However, no commercial shale gas fields have yet [...] Read more.
The lower Cambrian Niutitang/Qiongzhusi shale gas in the Middle-Upper Yangtz Block had been regarded as a very promising unconventional natural gas resource due to its high total organic carbon, great thickness, and large areal distribution. However, no commercial shale gas fields have yet been reported. From the northwest to the southeast there are considerable differences in the sedimentary environments, lithology, and erosive nature of the underlying interval (the floor interval) of the Niutitang shale. However, systematic research on whether and how these regional differences influence shale petrophysical properties and shale gas preservation in the Niutitang shale is lacking. A comparison of Niutitang shale reservoirs as influenced by different sedimentary and tectonic backgrounds is necessary. Samples were selected from both the overmature Niutitang shales and the floor interval. These samples cover the late Ediacaran and early Cambrian, with sedimentary environments varying from carbonate platform and carbonate platform marginal zone facies to continental shelf/slope. Previously published data on the lower Cambrian samples from Kaiyang (carbonate platform), Youyang (carbonate platform marginal zone) and Cen’gong (continental shelf/slope) sections were integrated and compared. The results indicate that the petrophysical properties of the floor interval can affect not only the preservation conditions (sealing capacity) of the shale gas, but also the petrophysical properties (pore volume, porosity, specific surface area and permeability) and methane content of the Niutitang shale. From the carbonate platform face to the continental shelf/slope the sealing capacity of the floor interval gradually improves because the latter gradually passes from high permeability dolostone (the Dengying Formation) to low permeability dense chert (the Liuchapo Formation). In addition, in contrast with several unconformities that occur in the carbonate platform face in the northern Guizhou depression, no unconformity contact occurs between the Niutitang shale and the floor interval on the continental shelf/slope developed in eastern Chongqing Province and northwestern Hunan Province. Such regional differences in floor interval could lead to significant differences in hydrocarbon expulsion behaviour and the development of organic pores within the Niutitang shale. Therefore, shale gas prospects in the Niutitang shales deposited on the continental shelf/slope should be significantly better than those of shales deposited on the carbonate platform face. Full article
(This article belongs to the Special Issue Shale and Tight Reservoir Characterization and Resource Assessment)
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Article
Modeling Interfacial Tension of N2/CO2 Mixture + n-Alkanes with Machine Learning Methods: Application to EOR in Conventional and Unconventional Reservoirs by Flue Gas Injection
Minerals 2022, 12(2), 252; https://doi.org/10.3390/min12020252 - 16 Feb 2022
Cited by 1 | Viewed by 1032
Abstract
The combustion of fossil fuels from the input of oil refineries, power plants, and the venting or flaring of produced gases in oil fields leads to greenhouse gas emissions. Economic usage of greenhouse and flue gases in conventional and unconventional reservoirs would not [...] Read more.
The combustion of fossil fuels from the input of oil refineries, power plants, and the venting or flaring of produced gases in oil fields leads to greenhouse gas emissions. Economic usage of greenhouse and flue gases in conventional and unconventional reservoirs would not only enhance the oil and gas recovery but also offers CO2 sequestration. In this regard, the accurate estimation of the interfacial tension (IFT) between the injected gases and the crude oils is crucial for the successful execution of injection scenarios in enhanced oil recovery (EOR) operations. In this paper, the IFT between a CO2/N2 mixture and n-alkanes at different pressures and temperatures is investigated by utilizing machine learning (ML) methods. To this end, a data set containing 268 IFT data was gathered from the literature. Pressure, temperature, the carbon number of n-alkanes, and the mole fraction of N2 were selected as the input parameters. Then, six well-known ML methods (radial basis function (RBF), the adaptive neuro-fuzzy inference system (ANFIS), the least square support vector machine (LSSVM), random forest (RF), multilayer perceptron (MLP), and extremely randomized tree (extra-tree)) were used along with four optimization methods (colliding bodies optimization (CBO), particle swarm optimization (PSO), the Levenberg–Marquardt (LM) algorithm, and coupled simulated annealing (CSA)) to model the IFT of the CO2/N2 mixture and n-alkanes. The RBF model predicted all the IFT values with exceptional precision with an average absolute relative error of 0.77%, and also outperformed all other models in this paper and available in the literature. Furthermore, it was found that the pressure and the carbon number of n-alkanes would show the highest influence on the IFT of the CO2/N2 and n-alkanes, based on sensitivity analysis. Finally, the utilized IFT database and the area of the RBF model applicability were investigated via the leverage method. Full article
(This article belongs to the Special Issue Shale and Tight Reservoir Characterization and Resource Assessment)
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