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Shale and Tight Reservoir Characterization and Resource Assessment
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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 27901

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

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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. Minerals is an international peer-reviewed open access monthly 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 2400 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

  • 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

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Published Papers (11 papers)

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Research

25 pages, 9051 KiB  
Article
Characteristics of Canister Core Desorption Gas from Unconventional Reservoirs and Applications to Improve Assessment of Hydrocarbons-in-Place
by Xiaojun Cui, Chunqing Jiang, Brent Nassichuk and Jordan Wilson
Minerals 2022, 12(10), 1226; https://doi.org/10.3390/min12101226 - 28 Sep 2022
Cited by 2 | Viewed by 1912
Abstract
Canister core desorption has been successfully applied to coal-bed methane evaluation and exploitation as the technique eliminates the need for time-consuming down-hole fluid retrieval through flow testing. The technique has also been used for the evaluation and exploration of early-stage tight and shale [...] Read more.
Canister core desorption has been successfully applied to coal-bed methane evaluation and exploitation as the technique eliminates the need for time-consuming down-hole fluid retrieval through flow testing. The technique has also been used for the evaluation and exploration of early-stage tight and shale gas reservoirs in recent years, although its success and applicability are poorly understood. In this study, we analyzed a comprehensive canister desorption data set on 230 core samples from nine exploration wells drilled into the Montney Formation in northeastern British Columbia part of the Western Canada Sedimentary Basin (WCSB). The purpose of the study was to illustrate the desorption characteristics of tight rocks and the relationship to reservoir properties and operational parameters. Based on the measured core properties (e.g., porosity, fluid saturation, permeability, total organic carbon (TOC) content, and adsorption isotherms) of canister samples and adjacent core samples, non-isothermal gas transport in cores was modeled to quantify the lost gas during core recovery and lost gas time at the surface. Gas volumes were measured and subsampled by canister desorption tests. The results show that the gas contents measured by on-site canister desorption only accounts for a minor (but significant) portion (about 2 to 25%) of the total gas-in-place in the Montney Formation cores, with the lower percentages being associated with samples of better reservoir qualities (e.g., higher porosity). Over 60–90% (mainly free gas) of the total gas-in-place can be lost during core recovery, and up to 10% can be lost at surface, prior to canister desorption. The measured canister desorption gas is mainly from adsorbed gas, and hence shows strong positive correlation to TOC content. The study shows that the current canister desorption test method severely underestimates in-situ gas content because it fails to correctly estimate the total lost gas content, limiting the successful application of the desorption technique. Nevertheless, the bulk properties and molecular compositions of the desorption gases are strongly correlated to those of the gases produced in the same area, exhibiting distinctive gas composition profiles throughout core desorption for different reservoir types or thermal maturity, and thus can provide invaluable information for the initial evaluation of unconventional plays. A workflow of EOS-based PVT property and compositional modeling is proposed to integrate the core desorption gas test results with core analysis data and mud gas and/or produced gas data for improved characterization of in situ reservoir fluids, and hence, better assessments of hydrocarbons-in-place and evaluations of tight and shale reservoirs. Full article
(This article belongs to the Special Issue Shale and Tight Reservoir Characterization and Resource Assessment)
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40 pages, 13056 KiB  
Article
Produced Gas and Condensate Geochemistry of the Marcellus Formation in the Appalachian Basin: Insights into Petroleum Maturity, Migration, and Alteration in an Unconventional Shale Reservoir
by Christopher D. Laughrey
Minerals 2022, 12(10), 1222; https://doi.org/10.3390/min12101222 - 27 Sep 2022
Cited by 9 | Viewed by 3657
Abstract
The Middle Devonian Marcellus Formation of North America is the most prolific hydrocarbon play in the Appalachian basin, the second largest producer of natural gas in the United States, and one of the most productive gas fields in the world. Regional differences in [...] Read more.
The Middle Devonian Marcellus Formation of North America is the most prolific hydrocarbon play in the Appalachian basin, the second largest producer of natural gas in the United States, and one of the most productive gas fields in the world. Regional differences in Marcellus fluid chemistry reflect variations in thermal maturity, migration, and hydrocarbon alteration. These differences define specific wet gas/condensate and dry gas production in the basin. Marcellus gases co-produced with condensate in southwest Pennsylvania and northwest West Virginia are mixtures of residual primary-associated gases generated in the late oil window and postmature secondary hydrocarbons generated from oil cracking in the wet gas window. Correlation of API gravity and C7 expulsion temperatures, high heptane and isoheptane ratios, and the gas geochemical data confirm that the Marcellus condensates formed through oil cracking. Respective low toluene/nC7 and high nC7/methylcyclohexane ratios indicate selective depletion of low-boiling point aromatics and cyclic light saturates in all samples, suggesting that water washing and gas stripping altered the fluids. These alterations may be related to deep migration of hot basinal brines. Dry Marcellus gases produced in northeast Pennsylvania and northcentral West Virginia are mixtures of overmature methane largely cracked from refractory kerogen and ethane and propane cracked from light oil and wet gas. Carbon and hydrogen isotope distributions are interpreted to indicate (1) mixing of hydrocarbons of different thermal maturities, (2) high temperature Rayleigh fractionation of wet gas during redox reactions with transition metals and formation water, (3) isotope exchange between methane and water, and, possibly, (4) thermodynamic equilibrium conditions within the reservoirs. Evidence for thermodynamic equilibrium in the dry gases includes measured molecular proportions (C1/(C1 − C5) = 0.96 to 0.985) and δ13C1 values significantly greater than δ13CKEROGEN. Noble gas systematics support the interpretation of hydrocarbon–formation water interactions, constrain the high thermal maturity of the hydrocarbon fluids, and provide a method of quantifying gas retention versus expulsion in the reservoirs. Full article
(This article belongs to the Special Issue Shale and Tight Reservoir Characterization and Resource Assessment)
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13 pages, 1961 KiB  
Article
Unconventional Gas Geochemistry—An Emerging Concept after 20 Years of Shale Gas Development?
by Jaime Cesar
Minerals 2022, 12(10), 1188; https://doi.org/10.3390/min12101188 - 22 Sep 2022
Cited by 2 | Viewed by 1860
Abstract
Geochemical studies of gases from low-permeability reservoirs have raised new questions regarding the chemical and stable isotope systematics of gas hydrocarbons. For instance, the possibility of thermodynamic equilibrium is recurrently in discussion. However, it is not clear whether there is anything “unconventional” in [...] Read more.
Geochemical studies of gases from low-permeability reservoirs have raised new questions regarding the chemical and stable isotope systematics of gas hydrocarbons. For instance, the possibility of thermodynamic equilibrium is recurrently in discussion. However, it is not clear whether there is anything “unconventional” in the way these systems continue to be studied. Using molecular and stable carbon isotope data from North American unconventional and conventional reservoirs, this research has applied two parameters that well describe key transformation stages during gas generation. The δ13C of ethane and the C2/C3 ratio increase from baseline values (<1%Ro, prominent kerogen cracking) until a first inflexion at 1.5%Ro. The same inflexion leads to 13C depletion of ethane and a rapidly increasing C2/C3 ratio as hydrocarbon cracking becomes prominent. The transition between these two stages is proposed to be a crossover from equilibrium to non-equilibrium conditions. There is no evidence for these characteristics to be limited to low-permeability reservoirs. Unconventional gas geochemistry should represent an approach that acknowledges that chemical and isotope distributions are not ruled by only one mechanism but several and at specific intervals of the thermal history. Full article
(This article belongs to the Special Issue Shale and Tight Reservoir Characterization and Resource Assessment)
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14 pages, 8442 KiB  
Article
The Analysis of Bio-Precursor Organic Matter Compositions and Its Significance for Gas Shale Reservoir of Wufeng–Longmaxi Formation from Dingshan Area, Sichuan Basin
by Zhihong Wang, Xiaomin Xie, Zhigang Wen, Yaohui Xu and Yan Liu
Minerals 2022, 12(9), 1176; https://doi.org/10.3390/min12091176 - 19 Sep 2022
Cited by 1 | Viewed by 1468
Abstract
In order to analyze the organic matter (OM) composition, this study carefully identified the OM types of 66 samples from Well A in the Dingshan area under microscope, and made an effort to obtain the semi-quantitative statistics contents of different bio-precursor derived OM. [...] Read more.
In order to analyze the organic matter (OM) composition, this study carefully identified the OM types of 66 samples from Well A in the Dingshan area under microscope, and made an effort to obtain the semi-quantitative statistics contents of different bio-precursor derived OM. The results of OM content obtained under microscope showed a strong positive relationship (R2 = 0.85) with the TOC content analyzed by carbon–sulfur analyzer. The OM contained bethic algae debris, phytoplankton amorphous organic matter (AOM), acritarch, vitrinite-like particles, zooplankton (including graptolite, chitinozoa and others) and solid bitumen which was secondary formation OM. The phytoplankton AOM, graptolite and solid bitumen were the dominated OM in this interval. Solid bitumen (8%~11%) was filled at the bottom of the Wufeng Formation, which could be one reason for the high shale gas production in the lower part of this shale interval. N2 adsorption results showed that micropores and mesopores were predominant in this shale gas system, while pore volumes illustrated better positive relationships with organic matter than minerals, especially AOM content. Thus, both solid bitumen and AOM kerogen were the main sources for shale gas generation in this shale gas system. Full article
(This article belongs to the Special Issue Shale and Tight Reservoir Characterization and Resource Assessment)
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23 pages, 5521 KiB  
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
by Hong Zhang, Haiping Huang and Mengsha Yin
Minerals 2022, 12(7), 802; https://doi.org/10.3390/min12070802 - 24 Jun 2022
Cited by 4 | Viewed by 2128
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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19 pages, 11504 KiB  
Article
CO2-Enhanced Oil Recovery Mechanism in Canadian Bakken Shale
by Majid Bizhani, Omid Haeri Ardakani, Steven B. Hawthorne, Jaime Cesar, Bethany Kurz and Jeanne B. Percival
Minerals 2022, 12(6), 779; https://doi.org/10.3390/min12060779 - 19 Jun 2022
Cited by 9 | Viewed by 3586
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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29 pages, 7426 KiB  
Article
Modeling of Brine/CO2/Mineral Wettability Using Gene Expression Programming (GEP): Application to Carbon Geo-Sequestration
by Jafar Abdi, Menad Nait Amar, Masoud Hadipoor, Thomas Gentzis, Abdolhossein Hemmati-Sarapardeh and Mehdi Ostadhassan
Minerals 2022, 12(6), 760; https://doi.org/10.3390/min12060760 - 15 Jun 2022
Cited by 5 | Viewed by 2518
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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18 pages, 1392 KiB  
Article
Reservoir Characterization of a Tight Gas Field Using New Modified Type Curves for Production Data Analysis—A Case Study from Ordos Basin
by Chang Su, Kefeng Lu, Wanju Yuan and Gang Zhao
Minerals 2022, 12(6), 675; https://doi.org/10.3390/min12060675 - 27 May 2022
Viewed by 1772
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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31 pages, 13529 KiB  
Article
Semi-Analytical Modeling of Geological Features Based Heterogeneous Reservoirs Using the Boundary Element Method
by Chang Su, Gang Zhao, Yee-Chung Jin and Wanju Yuan
Minerals 2022, 12(6), 663; https://doi.org/10.3390/min12060663 - 24 May 2022
Cited by 1 | Viewed by 1819
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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26 pages, 8705 KiB  
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
by Yijun Zheng, Yuhong Liao, Yunpeng Wang, Yongqiang Xiong and Ping’an Peng
Minerals 2022, 12(5), 539; https://doi.org/10.3390/min12050539 - 26 Apr 2022
Cited by 1 | Viewed by 1818
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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24 pages, 14980 KiB  
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
by Erfan Salehi, Mohammad-Reza Mohammadi, Abdolhossein Hemmati-Sarapardeh, Vahid Reza Mahdavi, Thomas Gentzis, Bo Liu and Mehdi Ostadhassan
Minerals 2022, 12(2), 252; https://doi.org/10.3390/min12020252 - 16 Feb 2022
Cited by 16 | Viewed by 3906
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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