Special Issue "Development of Unconventional Reservoirs"

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

Deadline for manuscript submissions: closed (31 October 2019).

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A printed edition of this Special Issue is available here.

Special Issue Editor

Prof. Dr. Reza Rezaee
Website
Guest Editor
WA School of Mines: Minerals, Energy and Chemical Engineering, Curtin University, Perth, Australia
Interests: formation evaluation; petrophysics; unconventional gas (tight gas sand and shale gas); reservoir characterization and modeling
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Special Issue Information

Dear Colleagues,

The need for energy is increasing, and at the same time production from conventional reservoirs is declining quickly. This requires an economically and technically feasible source of energy for the coming years. Among some alternative future energy solutions, the most approachable source is from unconventional reservoirs. As the name “unconventional” implies it requires a different and challenging approach to characterize and to develop such a resource. This Special Issue will attempt to cover the most pressing technical challenges for developing unconventional energy sources from shale gas, shale oil, tight gas sand, coalbed methane, and gas hydrates.

Topics of interest for publication in this Special Issue include, but are not limited to:

  • Reservoir characterization of unconventional plays;
  • Petrophysical and well–log interpretation challenges of unconventional reservoirs;
  • Geomechanical and drilling aspects of unconventional reservoirs;
  • Hydraulic fracturing challenges;
  • Rock physics analysis of unconventional reservoirs;
  • Completion, reservoir management, and surveillance of unconventional reservoirs;
  • Unconventional reservoirs’ environmental issues and challenges.

Prof. Reza Rezaee
Guest Editor

Manuscript Submission Information

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Keywords

  • unconventional reservoirs
  • shale gas and oil
  • tight gas sand
  • coal bed methane
  • gas hydrates

Published Papers (25 papers)

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Research

Open AccessArticle
Experimental Investigation on Injection and Production Pattern in Fractured-Vuggy Carbonate Reservoirs
Energies 2020, 13(3), 603; https://doi.org/10.3390/en13030603 - 29 Jan 2020
Abstract
To constitute and adjust the injection and production pattern in fractured-vuggy reservoirs, we extracted twelve fractured-cave structures, fabricated them into physical models with acrylic plates, and performed experiments via these models. The results show that utilizing oil/water gravity segregation sufficiently and forming valid [...] Read more.
To constitute and adjust the injection and production pattern in fractured-vuggy reservoirs, we extracted twelve fractured-cave structures, fabricated them into physical models with acrylic plates, and performed experiments via these models. The results show that utilizing oil/water gravity segregation sufficiently and forming valid flow channels should be emphasized. Preferentially exploiting the reservoir body containing intermediate-scaled or large-scaled caves, arranging injection wells in fractures or small-scaled caves while placing production wells in large-scaled caves, and separately putting injection wells and production wells in low/high parts of an intermediate-scaled or large-scaled cave, were found to benefit oil/water gravity segregation and thus gain a better water flooding effect in these experiments. Experiments with combined models also figured out that, after adjusting the injection and production pattern, the valid flow channel newly formed must pass through caves containing enough residual oil to improve the water flooding effect and could be obtained by shutting down the old production well while adding a new production well, adding a new production well, or switching the production well into an injection well while adding a new production well. In the actual field, adjusting the well location and altering the flow channel were proposed to conduct together. This study may provide references on the production management of analogous reservoirs. Full article
(This article belongs to the Special Issue Development of Unconventional Reservoirs) Printed Edition available
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Open AccessArticle
The Effect of Supercritical CO2 on Shaly Caprocks
Energies 2020, 13(1), 149; https://doi.org/10.3390/en13010149 - 27 Dec 2019
Cited by 1
Abstract
The effect of supercritical CO2 on the shaly caprocks is one of the critical issues to be considered in CO2 sequestration programs. Shale-scCO2 interactions can alter the seal integrity, leading to environmental problems and bringing into question the effectiveness of [...] Read more.
The effect of supercritical CO2 on the shaly caprocks is one of the critical issues to be considered in CO2 sequestration programs. Shale-scCO2 interactions can alter the seal integrity, leading to environmental problems and bringing into question the effectiveness of the program altogether. Several analytical studies were conducted on samples from Jurassic Eneabba Basal Shale and claystone rich facies of the Triassic Yalgorup Member (725–1417 m) in the Harvey CO2 sequestration site, Western Australia, to address the shale-scCO2 interactions and their effect on the petrophysical properties of the caprock. Shale samples saturated with NaCl brine were exposed to scCO2 under the reservoir condition (T = 60 °C, P = 2000 psi) for nine months and then tested to determine their altered mineralogical, petrophysical and geochemical properties. The experimental study examined changes to the mineralogical composition, capillary threshold pressure, and pore size distribution (PSD) of samples. The X-ray diffraction (XRD) results showed several changes in mineralogy because of rock-brine-CO2 reactions. Quartz, feldspars, kaolinite, and goethite were dissolved in most samples and muscovite, and halite were precipitated in general. Nuclear magnetic resonance (NMR), low-pressure nitrogen adsorption (LPNA), and mercury injection capillary pressure (MICP) tests indicate an increase in pore volume, except for relatively tighter, clay-rich samples. A reduction in capillary threshold pressures of samples after exposure to scCO2 is observed. Full article
(This article belongs to the Special Issue Development of Unconventional Reservoirs) Printed Edition available
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Open AccessArticle
Insight into the Pore Characteristics of a Saudi Arabian Tight Gas Sand Reservoir
Energies 2019, 12(22), 4302; https://doi.org/10.3390/en12224302 - 12 Nov 2019
Cited by 5
Abstract
The petrophysical characterization of tight gas sands can be affected by clay minerals, gas adsorption, microfractures, and the presence of high-density minerals. In this study, we conducted various petrophysical, petrographic, and high-resolution image analyses on Saudi Arabian tight sand in order to understand [...] Read more.
The petrophysical characterization of tight gas sands can be affected by clay minerals, gas adsorption, microfractures, and the presence of high-density minerals. In this study, we conducted various petrophysical, petrographic, and high-resolution image analyses on Saudi Arabian tight sand in order to understand how a complex pore system responds to measurement tools. About 140 plug samples extracted from six wells were subjected to routine core analyses including cleaning, drying, and porosity–permeability measurements. The porosity–permeability data was used to identify hydraulic flow units (HFU). In order to probe the factors contributing to the heterogeneity of this tight sand, 12 subsamples representing the different HFUs were selected for petrographic study and high-resolution image analysis using SEM, quantitative evaluation of minerals by scanning electron microscope (QEMSCAN), and micro-computed tomography (µCT). Nuclear magnetic resonance (NMR) and electrical resistivity measurements were also conducted on 56 subsamples representing various lithofacies. NMR porosity showed good agreement with other porosity measurements. The agreement was remarkable in specific lithofacies with porosity ranging from 0.1% to 7%. Above this range, significant scatters were seen between the porosity methods. QEMSCAN results revealed that samples with <7% porosity contain a higher proportion of clay than those with porosity >7%, which are either microfractured or contain partially dissolved labile minerals. The NMR T2 profiles also showed that samples with porosity <7% are dominated by micropores while samples with porosity >7% are dominated by macropores. Analysis of the µCT images revealed that pore throat sizes may be responsible for the poor correlation between NMR porosity and other porosity methods. NMR permeability values estimated using the Shlumberger Doll Research (SDR) method are fairly correlated with helium permeability (with an R2 of 0.6). Electrical resistivity measurements showed that the different rock types fall on the same slope of the formation factors versus porosity, with a cementation factor of 1.5. Full article
(This article belongs to the Special Issue Development of Unconventional Reservoirs) Printed Edition available
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Open AccessArticle
Pressure Transient Performance for a Horizontal Well Intercepted by Multiple Reorientation Fractures in a Tight Reservoir
Energies 2019, 12(22), 4232; https://doi.org/10.3390/en12224232 - 06 Nov 2019
Cited by 1
Abstract
A fractured horizontal well is an effective technology to obtain hydrocarbons from tight reservoirs. In this study, a new semi-analytical model for a horizontal well intercepted by multiple finite-conductivity reorientation fractures was developed in an anisotropic rectangular tight reservoir. Firstly, to establish the [...] Read more.
A fractured horizontal well is an effective technology to obtain hydrocarbons from tight reservoirs. In this study, a new semi-analytical model for a horizontal well intercepted by multiple finite-conductivity reorientation fractures was developed in an anisotropic rectangular tight reservoir. Firstly, to establish the flow equation of the reorientation fracture, all reorientation fractures were discretized by combining the nodal analysis technique and the fracture-wing method. Secondly, through coupling the reservoir solution and reorientation fracture solution, a semi-analytical solution for multiple reorientation fractures along a horizontal well was derived in the Laplace domain, and its accuracy was also verified. Thirdly, typical flow regimes were identified on the transient-pressure curves. Finally, dimensionless pressure and pressure derivative curves were obtained to analyze the effect of key parameters on the flow behavior, including fracture angle, permeability anisotropy, fracture conductivity, fracture spacing, fracture number, and fracture configuration. Results show that, for an anisotropic rectangular tight reservoir, horizontal wells should be deployed parallel to the direction of principal permeability and fracture reorientation should be controlled to extend along the direction of minimum permeability. Meanwhile, the optimal fracture number should be considered for economic production and the fracture spacing should be optimized to reduce the flow interferences between reorientation fractures. Full article
(This article belongs to the Special Issue Development of Unconventional Reservoirs) Printed Edition available
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Open AccessArticle
The Characteristics of Oil Migration due to Water Imbibition in Tight Oil Reservoirs
Energies 2019, 12(21), 4199; https://doi.org/10.3390/en12214199 - 04 Nov 2019
Cited by 1
Abstract
In tight oil reservoirs, water imbibition is the key mechanism to improve oil production during shut-in operations. However, the complex microstructure and composition of minerals complicate the interpretation of oil migration during water imbibition. In this study, nuclear magnetic resonance (NMR) T2 [...] Read more.
In tight oil reservoirs, water imbibition is the key mechanism to improve oil production during shut-in operations. However, the complex microstructure and composition of minerals complicate the interpretation of oil migration during water imbibition. In this study, nuclear magnetic resonance (NMR) T2 spectra was used to monitor the oil migration dynamics in tight oil reservoirs. The factors influencing pore size distribution, micro-fractures, and clay minerals were systematically investigated. The results show that the small pores corresponded to a larger capillary pressure and a stronger imbibition capacity, expelling the oil into the large pores. The small pores had a more effective oil recovery than the large pores. As the soaking time increases, the water preferentially entered the natural micro-fractures, expelling the oil in the micro-fractures. Subsequently, the oil in the small pores was slowly expelled. Compared with the matrix pores, natural micro-fractures had a smaller flow resistance and were more conducive to water and oil flow. Clay minerals may have induced micro-fracture propagation, which can act as the oil migration channels during water imbibition. In contrary to the inhibitory effect of natural micro-fractures, the new micro-fractures could contribute to the oil migration from small pores into large pores. This study characterized the oil migration characteristics and provides new insight into tight oil production. Full article
(This article belongs to the Special Issue Development of Unconventional Reservoirs) Printed Edition available
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Open AccessArticle
Accumulation Conditions and an Analysis of the Origins of Natural Gas in the Lower Silurian Shiniulan Formation from Well Anye 1, Northern Guizhou Province
Energies 2019, 12(21), 4087; https://doi.org/10.3390/en12214087 - 26 Oct 2019
Cited by 2
Abstract
The origin of natural gas and the mechanisms that lead to gas accumulation in the marine calcareous mudstone of the Lower Silurian Shiniulan Formation in northern Guizhou province are special and complicated. According to a combination of qualitative and quantitative methods, including the [...] Read more.
The origin of natural gas and the mechanisms that lead to gas accumulation in the marine calcareous mudstone of the Lower Silurian Shiniulan Formation in northern Guizhou province are special and complicated. According to a combination of qualitative and quantitative methods, including the reconstruction of hydrocarbon generative potential and gas content’s measurement, in the context of some geochemistry information—the origins of the natural gas of Shiniulan Formation is suggested to be mixed gas. Furthermore, the accumulation of the natural gas can be proposed combined with some geological information. Results indicated that the volume of the in-place gas content of Shiniulan samples, reinstated by the formulas’ computation, reaches a yield of 3.67 m3·t−1 in rock. The theoretical gas content for Shiniulan Formation mudstone ranges from 1.6 to 5.8 m3·t−1 using the indirect calculation of gas content, and the total gas contents of those samples range from 0.065 to 0.841 m3/t, according to the United States Bureau of Mines’ (USBM) direct method. According to the combination of the reconstructed in-place gas content and the gas content, even mudstone in the Shiniulan Formation has potential to generating gas but could not satisfy the actual gas content in Shiniulan Formation. In addition, according to the composition, the carbon and hydrogen isotope charts of gaseous hydrocarbons further indicate that the gas origin of Shiniulan Formation is a mixed gas, which also means that the gas is not just generated in the layer, but has partly migrated from other formations, such as the Wufeng–Longmaxi Formation. The lower Shiniulan Formation in the study area is characterized by frequent interbed of limestone and calcareous mudstone. The geological information shows that well-developed fractures of mudstone and faults can be used as main pathways for the upward migration of gases from the underlying strata to the Shiniulan Formation. The limestone with fairly low porosity and permeability hinders the migration of natural gas as much as possible and keeps that efficiently reserved in the horizontal fractures of calcareous mudstone. This migration pattern implies that the interbedded rock association is also favorable for gas accumulation in the Shiniulan Formation. Full article
(This article belongs to the Special Issue Development of Unconventional Reservoirs) Printed Edition available
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Open AccessArticle
Numerical Investigation of Downhole Perforation Pressure for a Deepwater Well
Energies 2019, 12(19), 3795; https://doi.org/10.3390/en12193795 - 08 Oct 2019
Abstract
During the production of deepwater wells, downhole perforation safety is one of the key technical problems. The perforation fluctuating pressure is an important factor in assessing the wellbore safety threat. Due to difficulty in describing the downhole perforation pressure by using the existing [...] Read more.
During the production of deepwater wells, downhole perforation safety is one of the key technical problems. The perforation fluctuating pressure is an important factor in assessing the wellbore safety threat. Due to difficulty in describing the downhole perforation pressure by using the existing empirical correlations, a prediction model based on data fitting of a large number of numerical simulations has been proposed. Firstly, a numerical model is set up to obtain the dynamic data of downhole perforation, and the exponential attenuation model of perforation pressure in the wellbore is established. Secondly, a large number of numerical simulations have been carried out through orthogonal test design. The results reveal that the downhole perforation pressure is logarithmic to the total charge quantity, increases linearly to the wellbore initial pressure, shows an exponential relationship with downhole effective volume for perforation, and has a power relationship with the thickness of casing and cement as well as formation elastic modulus. Thirdly, the prediction of perforation peak pressure at different positions along the wellbore agrees well with the field measurement within a 10% error. Finally, the results of this study have been applied in the field case, and an optimization scheme for deepwater downhole perforation safety has been put forward. Full article
(This article belongs to the Special Issue Development of Unconventional Reservoirs) Printed Edition available
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Open AccessArticle
Experimental and Simulation Studies on Adsorption and Diffusion Characteristics of Coalbed Methane
Energies 2019, 12(18), 3445; https://doi.org/10.3390/en12183445 - 06 Sep 2019
Cited by 2
Abstract
Coalbed methane (CBM) content is generally estimated using the isotherm theory between pressure and adsorbed amounts of methane. It usually determines the maximum content of adsorbed methane or storage capacity. However, CBM content obtained via laboratory experiment is not consistent with that in [...] Read more.
Coalbed methane (CBM) content is generally estimated using the isotherm theory between pressure and adsorbed amounts of methane. It usually determines the maximum content of adsorbed methane or storage capacity. However, CBM content obtained via laboratory experiment is not consistent with that in the in-situ state because samples are usually ground, which changes the specific surface area. In this study, the effect of the specific surface area relative to CBM content was investigated, and diffusion coefficients were estimated using equilibrium time analysis. The differences in adsorbed content with sample particle size allowed the determination of a specific surface area where gases can adsorb. Also, there was an equilibrium time difference between fine and lump coal, because more time is needed for the gas to diffuse through the coal matrix and adsorb onto the surface in lump coal. Based on this, we constructed a laboratory-scale simulation model, which matched with experimental results. Consequently, the diffusion coefficient, which is usually calculated through canister testing, can be easily obtained. These results stress that lump coal experiments and associated simulations are necessary for more reliable CBM production analysis. Full article
(This article belongs to the Special Issue Development of Unconventional Reservoirs) Printed Edition available
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Open AccessArticle
Numerical Simulation of Gas Production from Gas Shale Reservoirs—Influence of Gas Sorption Hysteresis
Energies 2019, 12(18), 3405; https://doi.org/10.3390/en12183405 - 04 Sep 2019
Cited by 4
Abstract
The true contribution of gas desorption to shale gas production is often overshadowed by the use of adsorption isotherms for desorbed gas calculations on the assumption that both processes are identical under high pressure, high temperature conditions. In this study, three shale samples [...] Read more.
The true contribution of gas desorption to shale gas production is often overshadowed by the use of adsorption isotherms for desorbed gas calculations on the assumption that both processes are identical under high pressure, high temperature conditions. In this study, three shale samples were used to study the adsorption and desorption isotherms of methane at a temperature of 80 °C, using volumetric method. The resulting isotherms were modeled using the Langmuir model, following the conversion of measured excess amounts to absolute values. All three samples exhibited significant hysteresis between the sorption processes and the desorption isotherms gave lower Langmuir parameters than the corresponding adsorption isotherms. Langmuir volume showed positive correlation with total organic carbon (TOC) content for both sorption processes. A compositional three-dimensional (3D), dual-porosity model was then developed in GEM® (a product of the Computer Modelling Group (CMG) Ltd., Calgary, AB, Canada) to test the effect of the observed hysteresis on shale gas production. For each sample, a base scenario, corresponding to a “no-sorption” case was compared against two other cases; one with adsorption Langmuir parameters (adsorption case) and the other with desorption Langmuir parameters (desorption case). The simulation results showed that while gas production can be significantly under-predicted if gas sorption is not considered, the use of adsorption isotherms in lieu of desorption can lead to over-prediction of gas production performances. Full article
(This article belongs to the Special Issue Development of Unconventional Reservoirs) Printed Edition available
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Open AccessFeature PaperArticle
Catalytic Effect of Cobalt Additive on the Low Temperature Oxidation Characteristics of Changqing Tight Oil and Its SARA Fractions
Energies 2019, 12(15), 2848; https://doi.org/10.3390/en12152848 - 24 Jul 2019
Cited by 1
Abstract
Air flooding is a potential enhanced oil recovery (EOR) method to economically and efficiently develop a tight oil reservoir due to its sufficient gas source and low operational costs, during which low temperature oxidation (LTO) is the key to ensuring the success of [...] Read more.
Air flooding is a potential enhanced oil recovery (EOR) method to economically and efficiently develop a tight oil reservoir due to its sufficient gas source and low operational costs, during which low temperature oxidation (LTO) is the key to ensuring the success of air flooding. In addition to inefficiency of conventional LTO, air flooding has seen its limited applications due to the prolonged reaction time and safety constraints. In this paper, a novel air injection technique based on the catalyst-activated low temperature oxidation (CLTO) is developed to improve the operational safety together with its oil recovery in tight oil reservoirs. Experimentally, static oxidation experiments are conducted to examine the influence of the catalyst on the LTO reaction kinetics of Changqing tight oil and its fractions. The catalytic oxidation characteristics are identified by applying a thermogravimetric analyzer coupled with Fourier transform infrared spectrometer (TG-FTIR) with respect to tight oil and its SARA (i.e., saturates, aromatics, resins, and asphaltenes) fractions. Accordingly, the catalyst can obviously decrease the LTO reaction activation energy of the Changqing tight oil and its SARA fraction. Cobalt additive can change the LTO reaction pathways of the SARA fractions, i.e., promoting the formation of hydroxyl-containing oxides and CO2 from the oxidation of saturates, aromatics and resins, while inhibiting the formation of ethers from the oxidation of aromatics and resins. The LTO of each SARA fraction contains both oxygen addition reaction and bond scission reaction that can be effectively promoted with the cobalt additive. The catalytic effect on the bond scission reaction is continuously enhanced and becomes gradually stronger than that on the oxygen addition reaction as the reaction proceeds. Full article
(This article belongs to the Special Issue Development of Unconventional Reservoirs) Printed Edition available
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Open AccessArticle
An Automatic Classification Method of Well Testing Plot Based on Convolutional Neural Network (CNN)
Energies 2019, 12(15), 2846; https://doi.org/10.3390/en12152846 - 24 Jul 2019
Cited by 1
Abstract
The precondition of well testing interpretation is to determine the appropriate well testing model. In numerous attempts in the past, automatic classification and identification of well testing plots have been limited to fully connected neural networks (FCNN). Compared with FCNN, the convolutional neural [...] Read more.
The precondition of well testing interpretation is to determine the appropriate well testing model. In numerous attempts in the past, automatic classification and identification of well testing plots have been limited to fully connected neural networks (FCNN). Compared with FCNN, the convolutional neural network (CNN) has a better performance in the domain of image recognition. Utilizing the newly proposed CNN, we develop a new automatic identification approach to evaluate the type of well testing curves. The field data in tight reservoirs such as the Ordos Basin exhibit various well test models. With those models, the corresponding well test curves are chosen as training samples. One-hot encoding, Xavier normal initialization, regularization technique, and Adam algorithm are combined to optimize the established model. The evaluation results show that the CNN has a better result when the ReLU function is used. For the learning rate and dropout rate, the optimized values respectively are 0.005 and 0.4. Meanwhile, when the number of training samples was greater than 2000, the performance of the established CNN tended to be stable. Compared with the FCNN of similar structure, the CNN is more suitable for classification of well testing plots. What is more, the practical application shows that the CNN can successfully classify 21 of the 25 cases. Full article
(This article belongs to the Special Issue Development of Unconventional Reservoirs) Printed Edition available
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Open AccessArticle
Study of Downhole Shock Loads for Ultra-Deep Well Perforation and Optimization Measures
Energies 2019, 12(14), 2743; https://doi.org/10.3390/en12142743 - 17 Jul 2019
Cited by 3
Abstract
Ultra-deep well perforation is an important direction for the development of unconventional oil and gas resources, the security with shock loads is a difficult technical problem. Firstly, the theoretical analysis of perforated string is carried out, the dynamics models of which are established [...] Read more.
Ultra-deep well perforation is an important direction for the development of unconventional oil and gas resources, the security with shock loads is a difficult technical problem. Firstly, the theoretical analysis of perforated string is carried out, the dynamics models of which are established in the directions of axial, radial and circumferential. Secondly, the process of perforating with hundreds of bullets is simulated by using the software of LS-DYNA (ANSYS, Inc, Pennsylvania, USA). The propagation attenuation model of shock loads is established, and a calculation model to predict shock loads at different positions of the tubing interval has been fitted by considering multiple factors. The dynamic response of perforated string is studied, and the vulnerable parts of which are found out. Thirdly, the optimization measures are put forward for ultra-deep well perforation by the design of shock adsorption and safety distance of the packer. Finally, the field case of an ultra-deep well shows that the research method in this paper is practical, and the optimization measures are reasonable and effective. This study can provide important guidance to reduce shock damage and improve security for ultra-deep well perforation. Full article
(This article belongs to the Special Issue Development of Unconventional Reservoirs) Printed Edition available
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Open AccessArticle
Study on the Impacts of Capillary Number and Initial Water Saturation on the Residual Gas Distribution by NMR
Energies 2019, 12(14), 2714; https://doi.org/10.3390/en12142714 - 16 Jul 2019
Cited by 2
Abstract
The determination of microscopic residual gas distribution is beneficial for exploiting reservoirs to their maximum potential. In this work, both forced and spontaneous imbibition (waterflooding) experiments were performed on a high-pressure displacement experimental setup, which was integrated with nuclear magnetic resonance (NMR) to [...] Read more.
The determination of microscopic residual gas distribution is beneficial for exploiting reservoirs to their maximum potential. In this work, both forced and spontaneous imbibition (waterflooding) experiments were performed on a high-pressure displacement experimental setup, which was integrated with nuclear magnetic resonance (NMR) to reveal the impacts of capillary number (Ca) and initial water saturation (Swi) on the residual gas distribution over four magnitudes of injection rates (Q = 0.001, 0.01, 0.1 and 1 mL/min), expressed as Ca (logCa = −8.68, −7.68, −6.68 and −5.68), and three different Swi (Swi = 0%, 39.34% and 62.98%). The NMR amplitude is dependent on pore volumes while the NMR transverse relaxation time (T2) spectrum reflects the characteristics of pore size distribution, which is determined based on a mercury injection (MI) experiment. Using this method, the residual gas distribution was quantified by comparing the T2 spectrum of the sample measured after imbibition with the sample fully saturated by brine before imbibition. The results showed that capillary trapping efficiency increased with increasing Swi, and above 90% of residual gas existed in pores larger than 1 μm in the spontaneous imbibition experiments. The residual gas was trapped in pores by different capillary trapping mechanisms under different Ca, leading to the difference of residual gas distribution. The flow channels were mainly composed of micropores (pore radius, r < 1 μm) and mesopores (r = 1–10 μm) at logCa = −8.68 and −7.68, while of mesopores and macropores (r > 10 μm) at logCa = −5.68. At both Swi= 0% and 39.34%, residual gas distribution in macropores significantly decreased while that in micropores slightly increased with logCa increasing to −6.68 and −5.68, respectively. Full article
(This article belongs to the Special Issue Development of Unconventional Reservoirs) Printed Edition available
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Open AccessArticle
Investigation of Analysis Methods for Pulse Decay Tests Considering Gas Adsorption
Energies 2019, 12(13), 2562; https://doi.org/10.3390/en12132562 - 03 Jul 2019
Cited by 4
Abstract
The pulse decay test is the main method employed to determine permeability for tight rocks, and is widely used. The testing gas can be strongly adsorbed on the pore surface of unconventional reservoir cores, such as shale and coal rock. However, gas adsorption [...] Read more.
The pulse decay test is the main method employed to determine permeability for tight rocks, and is widely used. The testing gas can be strongly adsorbed on the pore surface of unconventional reservoir cores, such as shale and coal rock. However, gas adsorption has not been well considered in analysis pulse decay tests. In this study, the conventional flow model of adsorbed gas in porous media was modified by considering the volume of the adsorbed phase. Then, pulse decay tests of equilibrium sorption, unsteady state and pseudo-steady-state non-equilibrium sorption models, were analyzed by simulations. For equilibrium sorption, it is found that the Cui-correction method is excessive when the adsorbed phase volume is considered. This method is good at very low pressure, and is worse than the non-correction method at high pressure. When the testing pressure and Langmuir volume are large and the vessel volumes are small, a non-negligible error exists when using the Cui-correction method. If the vessel volumes are very large, gas adsorption can be ignored. For non-equilibrium sorption, the pulse decay characteristics of unsteady state and pseudo-steady-state non-equilibrium sorption models are similar to those of unsteady state and pseudo-steady-state dual-porosity models, respectively. When the upstream and downstream pressures become equal, they continue to decay until all of the pressures reach equilibrium. The Langmuir volume and pressure, the testing pressure and the porosity, affect the pseudo-storativity ratio and the pseudo-interporosity flow coefficient. Their impacts on non-equilibrium sorption models are similar to those of the storativity ratio and the interporosity flow coefficient in dual-porosity models. Like dual-porosity models, the pseudo-pressure derivative can be used to identify equilibrium and non-equilibrium sorption models at the early stage, and also the unsteady state and pseudo-steady-state non-equilibrium sorption models at the late stage. To identify models using the pseudo-pressure derivative at the early stage, the suitable vessel volumes should be chosen according to the core adsorption property, porosity and the testing pressure. Finally, experimental data are analyzed using the method proposed in this study, and the results are sufficient. Full article
(This article belongs to the Special Issue Development of Unconventional Reservoirs) Printed Edition available
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Open AccessArticle
Applicability Analysis of Klinkenberg Slip Theory in the Measurement of Tight Core Permeability
Energies 2019, 12(12), 2351; https://doi.org/10.3390/en12122351 - 19 Jun 2019
Cited by 2
Abstract
The Klinkenberg slippage theory has widely been used to obtain gas permeability in low-permeability porous media. However, recent research shows that there is a deviation from the Klinkenberg slippage theory for tight reservoir cores under low-pressure conditions. In this research, a new experimental [...] Read more.
The Klinkenberg slippage theory has widely been used to obtain gas permeability in low-permeability porous media. However, recent research shows that there is a deviation from the Klinkenberg slippage theory for tight reservoir cores under low-pressure conditions. In this research, a new experimental device was designed to carry out the steady-state gas permeability test with high pressure and low flowrate. The results show that, unlike regular low-permeability cores, the permeability of tight cores is not a constant value, but a variate related to a fluid-dynamic parameter (flowrate). Under high-pressure conditions, the relationship between flowrate and apparent permeability of cores with low permeability is consistent with Klinkenberg slippage theory, while the relationship between flowrate and apparent permeability of tight cores is contrary to Klinkenberg slip theory. The apparent permeability of tight core increases with increasing flowrate under high-pressure conditions, and it is significantly lower than the Klinkenberg permeability predicted by Klinkenberg slippage theory. The difference gets larger when the flowrate becomes lower (back pressure increases and pressure difference decreases). Therefore, the Klinkenberg permeability which is obtained by the Klinkenberg slippage theory by using low-pressure experimental data will cause significant overestimation of the actual gas seepage capacity in the tight reservoir. In order to evaluate the gas seepage capacity in a tight reservoir precisely, it is necessary to test the permeability of the tight cores directly at high pressure and low flowrate. Full article
(This article belongs to the Special Issue Development of Unconventional Reservoirs) Printed Edition available
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Open AccessArticle
Comparative Porosity and Pore Structure Assessment in Shales: Measurement Techniques, Influencing Factors and Implications for Reservoir Characterization
Energies 2019, 12(11), 2094; https://doi.org/10.3390/en12112094 - 31 May 2019
Cited by 9
Abstract
Porosity and pore size distribution (PSD) are essential petrophysical parameters controlling permeability and storage capacity in shale gas reservoirs. Various techniques to assess pore structure have been introduced; nevertheless, discrepancies and inconsistencies exist between each of them. This study compares the porosity and [...] Read more.
Porosity and pore size distribution (PSD) are essential petrophysical parameters controlling permeability and storage capacity in shale gas reservoirs. Various techniques to assess pore structure have been introduced; nevertheless, discrepancies and inconsistencies exist between each of them. This study compares the porosity and PSD in two different shale formations, i.e., the clay-rich Permian Carynginia Formation in the Perth Basin, Western Australia, and the clay-poor Monterey Formation in San Joaquin Basin, USA. Porosity and PSD have been interpreted based on nuclear magnetic resonance (NMR), low-pressure N2 gas adsorption (LP-N2-GA), mercury intrusion capillary pressure (MICP) and helium expansion porosimetry. The results highlight NMR with the advantage of detecting the full-scaled size of pores that are not accessible by MICP, and the ineffective/closed pores occupied by clay bound water (CBW) that are not approachable by other penetration techniques (e.g., helium expansion, low-pressure gas adsorption and MICP). The NMR porosity is largely discrepant with the helium porosity and the MICP porosity in clay-rich Carynginia shales, but a high consistency is displayed in clay-poor Monterey shales, implying the impact of clay contents on the distinction of shale pore structure interpretations between different measurements. Further, the CBW, which is calculated by subtracting the measured effective porosity from total porosity, presents a good linear correlation with the clay content (R2 = 0.76), implying that our correlated equation is adaptable to estimate the CBW in shale formations with the dominant clay type of illite. Full article
(This article belongs to the Special Issue Development of Unconventional Reservoirs) Printed Edition available
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Open AccessArticle
Volumetric Measurements of Methane-Coal Adsorption and Desorption Isotherms—Effects of Equations of State and Implication for Initial Gas Reserves
Energies 2019, 12(10), 2022; https://doi.org/10.3390/en12102022 - 27 May 2019
Cited by 4
Abstract
This study presents the effects of equations of state (EOSs) on methane adsorption capacity, sorption hysteresis and initial gas reserves of a medium volatile bituminous coal. The sorption experiments were performed, at temperatures of 25 °C and 40 °C and up to 7MPa [...] Read more.
This study presents the effects of equations of state (EOSs) on methane adsorption capacity, sorption hysteresis and initial gas reserves of a medium volatile bituminous coal. The sorption experiments were performed, at temperatures of 25 °C and 40 °C and up to 7MPa pressure, using a high-pressure volumetric analyzer (HPVA-II). The measured isotherms were parameterized with the modified (three-parameter) Langmuir model. Gas compressibility factors were calculated using six popular equations of state and the results were compared with those obtained using gas compressibility factors from NIST-Refprop® (which implies McCarty and Arp’s EOS for Z-factor of helium and Setzmann and Wagner’s EOS for that of methane). Significant variations were observed in the resulting isotherms and associated model parameters with EOS. Negligible hysteresis was observed with NIST-refprop at both experimental temperatures, with the desorption isotherm being slightly lower than the adsorption isotherm at 25 °C. Compared to NIST-refprop, it was observed that equations of state that gave lower values of Z-factor for methane resulted in “positive hysteresis”, (one in which the desorption isotherm is above the corresponding adsorption curve) and the more negatively deviated the Z-factors are, the bigger the observed hysteresis loop. Conversely, equations of state that gave positively deviated Z-factors of methane relatively produced “negative hysteresis” loops where the desorption isotherms are lower than the corresponding adsorption isotherms. Adsorbed gas accounted for over 90% of the calculated original gas in place (OGIP) and the larger the Langmuir volume, the larger the proportion of OGIP that was adsorbed. Full article
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Open AccessArticle
Design and Evaluation of a Surfactant–Mixed Metal Hydroxide-Based Drilling Fluid for Maintaining Wellbore Stability in Coal Measure Strata
Energies 2019, 12(10), 1862; https://doi.org/10.3390/en12101862 - 16 May 2019
Cited by 3
Abstract
Co-exploitation of coal measure gases (coalbed gas, shale gas, and tight sandstone gas) puts a higher requirement on drilling fluids. Conventional drilling fluids have disadvantages, such as causing problems of borehole collapse, formation damage, and water blockage. This paper proposes a set of [...] Read more.
Co-exploitation of coal measure gases (coalbed gas, shale gas, and tight sandstone gas) puts a higher requirement on drilling fluids. Conventional drilling fluids have disadvantages, such as causing problems of borehole collapse, formation damage, and water blockage. This paper proposes a set of high inhibitive and low-damage drilling fluids that function by electrical inhibition and neutral wetting. Zeta potential results showed that the negative electrical property of Longtan coal in Bijie, Guizhou, can be reversed by organic mixed metal hydroxide (MMH) and the cationic surfactant alkyl trimethylammonium bromide (CS-5) from −3.63 mV to 19.75 mV and 47.25 mV, respectively. Based on the contact angle and Fourier Transform Infrared Spectroscopy (FT-IR) results, it can be concluded that chemical adsorption dominates between the Longmaxi shale and surfactants, and physical adsorption between the Longtan coal and surfactants. A compound surfactant formula (0.001 wt% CS-4 + 0.001 wt% CS-1 + 0.001 wt% CS-3), which could balance the wettability of the Longmaxi shale and the Longtan coal, making them both appear weakly hydrophilic simultaneously, was optimized. After being treated by the compound surfactants, the contact angles of the Longmaxi shale and the Longtan coal were 89° and 86°, respectively. Pressure transmission tests showed that the optimized combination of compound surfactants and inorganic MMH (MMH-1) could effectively reduce permeability of the Longmaxi shale and the Longtan coal, thus retarding pore pressure transmission in coal measure strata. Then, the proposed water-based drilling fluid (WBDF) system (4 wt% sodium bentonite + 1.5 wt% sodium carboxymethyl cellulose + 2 wt% lignite resin + 5 wt% potassium chloride + 3 wt%MMH-1 + 0.001 wt% CS-4 + 0.001 wt% CS-1 + 0.001 wt% CS-3) was evaluated based on parameters including rheology, American Petroleum Institute (API) filtration, electrical property, wettability, inhibition capability, reservoir protection characteristics, and anti-pollution performance. It had an API filtration of 7 mL, reservoir damage rate of 10%, moderate and acceptable viscosity, strong inhibition capability to coal measure strata rocks, good tolerance to inorganic pollutants and drilling cuttings, and environmentally friendly properties. It could meet wellbore stability and reservoir protection requirements in the co-exploitation of coal measure gases. Full article
(This article belongs to the Special Issue Development of Unconventional Reservoirs) Printed Edition available
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Open AccessArticle
Visual Experimental Study on Gradation Optimization of Two-Stage Gravel Packing Operation in Unconventional Reservoirs
Energies 2019, 12(8), 1519; https://doi.org/10.3390/en12081519 - 22 Apr 2019
Abstract
During the development of unconventional reservoirs with high sand production rate and fine silt content such as heavy oil and hydrate reservoirs, silt sand blockage problem is a serious issue. A two-stage gravel-packing sand control technique is applied to solve the silt sand [...] Read more.
During the development of unconventional reservoirs with high sand production rate and fine silt content such as heavy oil and hydrate reservoirs, silt sand blockage problem is a serious issue. A two-stage gravel-packing sand control technique is applied to solve the silt sand blockage now. However, traditional experiments on this technique could not obtain the dynamic distribution law of intrusive sand in the gravel pack. In this study, a new visualization experiment based on hydrodynamic similarity criterion for studying particle blockage in gravel packs was conducted. Real-time monitoring of sand particle migration in the gravel pack could be achieved. Also, the stable penetration depth and the distributing disciplinarian of invaded particles could be determined. The results show that when the gravel-to-sand median size ratio of gravel bed I is less than five, the sand bridge can be formed at the front end of the gravel pack. This could prevent sand from further intruding. As the grain size of gravel bed II is increased, the flow velocity is reduced. Thus, the sand invading into gravel bed II tends to settle at the interface. A large amount of sand intrusion can happen to gravel pack II when the pore filling front breaks through the gravel bed I. Full article
(This article belongs to the Special Issue Development of Unconventional Reservoirs) Printed Edition available
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Open AccessFeature PaperArticle
Total Organic Carbon Enrichment and Its Impact on Pore Characteristics: A Case Study from the Niutitang Formation Shales in Northern Guizhou
Energies 2019, 12(8), 1480; https://doi.org/10.3390/en12081480 - 18 Apr 2019
Cited by 2
Abstract
This study analyzes samples from the Lower Cambrian Niutitang Formation in northern Guizhou Province to enable a better understanding of total organic carbon (TOC) enrichment and its impact on the pore characteristics of over-mature marine shale. Organic geochemical analysis, X-ray diffraction, scanning electron [...] Read more.
This study analyzes samples from the Lower Cambrian Niutitang Formation in northern Guizhou Province to enable a better understanding of total organic carbon (TOC) enrichment and its impact on the pore characteristics of over-mature marine shale. Organic geochemical analysis, X-ray diffraction, scanning electron microscopy, helium porosity, and low-temperature nitrogen adsorption experiments were conducted on shale samples. Their original TOC (TOCo) content and organic porosity were estimated by theoretical calculation, and fractal dimension D was computed with the fractal Frenkel–Halsey–Hill model. The results were then used to consider which factors control TOC enrichment and pore characteristics. The samples are shown to be dominated by type-I kerogen with a TOC content of 0.29–9.36% and an equivalent vitrinite reflectance value of 1.72–2.72%. The TOCo content varies between 0.64% and 18.17%, and the overall recovery coefficient for the Niutitang Formation was 2.16. Total porosity of the samples ranged between 0.36% and 6.93%. TOC content directly controls porosity when TOC content lies in the range 1.0% to 6.0%. For samples with TOC < 1.0% and TOC > 6.0%, inorganic pores are the main contributors to porosity. Additionally, pore structure parameters show no obvious trends with TOC, quartz, and clay mineral content. The fractal dimension D1 is between 2.619 and 2.716, and D2 is between 2.680 and 2.854, illustrating significant pore surface roughness and structural heterogeneity. No single constituent had a dominant effect on the fractal characteristics. Full article
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Open AccessArticle
Variation of Petrophysical Properties and Adsorption Capacity in Different Rank Coals: An Experimental Study of Coals from the Junggar, Ordos and Qinshui Basins in China
Energies 2019, 12(6), 986; https://doi.org/10.3390/en12060986 - 13 Mar 2019
Cited by 5
Abstract
The petrophysical properties of coal will vary during coalification, and thus affect the methane adsorption capacity. In order to clarify the variation rule and its controlling effect on methane adsorption, various petrophysical tests including proximate analysis, moisture measurement, methane isothermal adsorption, mercury injection, [...] Read more.
The petrophysical properties of coal will vary during coalification, and thus affect the methane adsorption capacity. In order to clarify the variation rule and its controlling effect on methane adsorption, various petrophysical tests including proximate analysis, moisture measurement, methane isothermal adsorption, mercury injection, etc. were carried out on 60 coal samples collected from the Junggar, Ordos and Qinshui basins in China. In this work, the boundary values of maximum vitrinite reflectance (Ro,m) for dividing low rank, medium rank and high rank coals are set as 0.65% and 2.0%. The results show that vitrinite is the most abundant maceral, but the maceral contents are controlled by sedimentation without any relation to coal rank. Both the moisture content and porosity results show higher values in the low ranks and stabilized with Ro,m beyond 1%. Ro,m and VL (daf) show quadratic correlation with the peak located in Ro,m = 4.5–5%, with the coefficient (R2) reaching 0.86. PL decrease rapidly before Ro,m = 1.5%, then increase slowly. DAP is established to quantify the inhibitory effect of moisture on methane adsorption capacity, which shows periodic relationship with Ro,m: the inhibitory effect in lignite is the weakest and increases during coalification, then remains constant at Ro,m = 1.8% to 3.5%, and finally increases again. In the high metamorphic stage, clay minerals are more moisture-absorbent than coal, and the inherent moisture negatively correlates with the ratio of vitrinite to inertinite (V/I). During coalification, micro gas pores gradually become dominant, fractures tends to be well oriented and extended, and clay filling becomes more common. These findings can help us better understand the variation of petrophysical properties and adsorption capacity in different rank coals. Full article
(This article belongs to the Special Issue Development of Unconventional Reservoirs) Printed Edition available
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Open AccessArticle
A Prediction Model for Methane Adsorption Capacity in Shale Gas Reservoirs
Energies 2019, 12(2), 280; https://doi.org/10.3390/en12020280 - 16 Jan 2019
Cited by 3
Abstract
Estimation of methane adsorption capacity is crucial for the characterization of shale gas reservoirs. The methane adsorption capacity in shales is measured using high-pressure methane adsorption to obtain the adsorption isotherms, which can be fitted by Langmuir model. The determined Langmuir parameters can [...] Read more.
Estimation of methane adsorption capacity is crucial for the characterization of shale gas reservoirs. The methane adsorption capacity in shales is measured using high-pressure methane adsorption to obtain the adsorption isotherms, which can be fitted by Langmuir model. The determined Langmuir parameters can provide the methane adsorption capacity under actual reservoir conditions. In this study, a prediction model for the methane adsorption in shales was constructed based on 66 samples from 6 basins in China and Western Australia. The model was established in four steps: a model of Langmuir volume at experimental temperature, the temperature dependence of Langmuir volume, a model of Langmuir pressure, the temperature dependence of Langmuir pressure. In the model of Langmuir volume at experimental temperature, total organic carbon (TOC) and clay content (Vsh) were considered. A positive relationship was observed between the TOC and the temperature effect on the Langmuir volume. As the Langmuir pressure is sensitive to various factors, the Langmuir pressure at experimental temperature shows no trend with the TOC, clay content and thermal maturity, but a positive trend with the Langmuir volume. The results of this study can help log analysts to quantify adsorbed gas from well-log data since TOC and Vsh, which are the measure inputs of the introduced models, can be obtained from well-log data as well. Full article
(This article belongs to the Special Issue Development of Unconventional Reservoirs) Printed Edition available
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Open AccessArticle
Numerical Analysis of Transient Pressure Behaviors with Shale Gas MFHWs Interference
Energies 2019, 12(2), 262; https://doi.org/10.3390/en12020262 - 15 Jan 2019
Cited by 4
Abstract
After the large-scale horizontal well pattern development in shale gas fields, the problem of fast pressure drop and gas well abandonment caused by well interference becomes more serious. It is urgent to understand the downhole transient pressure and flow characteristics of multi-stage fracturing [...] Read more.
After the large-scale horizontal well pattern development in shale gas fields, the problem of fast pressure drop and gas well abandonment caused by well interference becomes more serious. It is urgent to understand the downhole transient pressure and flow characteristics of multi-stage fracturing horizontal well (MFHW) with interference. Therefore, the reservoir around the MFHW is divided into three regions: fracturing fracture, Stimulated reservoir volume (SRV), and unmodified matrix. Then, multi-region coupled flow model is established according to reservoir physical property and flow mechanism of each part. The model is numerically solved using the perpendicular bisection (PEBI) grids and the finite volume method. The accuracy of the model is verified by analyzing the measured pressure recovery data of one practical shale gas well and fitting the monitoring data of the later production pressure. Finally, this model is used to analyze the effects of factors, such as hydraulic fractures’ connectivity, well distance, the number of neighboring wells and well pattern arrangement, on the transient pressure and seepage characteristics of the well. The study shows that the pressure recovery double logarithmic curves fall in later part when the well is disturbed by a neighboring production well. The earlier and more severe the interference, the sooner the curve falls off and the larger the amplitude shows. If the well distance is closer, and if there are more neighboring wells and interconnected corresponding fracturing segments, the more severe interference appears among the wells. Moreover, the well interference may still exist even without interlinked fractures or SRV. Especially, severe interference will affect production when the hydraulic fractures are connected directly, and the interference is weaker when only SRV induced fracture network combined between wells, which is beneficial to production sometimes. When severe well interference occurs, periodic well shut-in is needed to help restore the reservoir pressure and output capacity. In the meanwhile, the daily output should be controlled reasonably to prolong the stable production time. This research will help to understand the impact of well interference to gas production, and to optimize the well spacing and achieve satisfied performance. Full article
(This article belongs to the Special Issue Development of Unconventional Reservoirs) Printed Edition available
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Open AccessArticle
Stress-Dependent Permeability of Fractures in Tight Reservoirs
Energies 2019, 12(1), 117; https://doi.org/10.3390/en12010117 - 29 Dec 2018
Cited by 3
Abstract
Permeability is one of the key factors involved in the optimization of oil and gas production in fractured porous media. Understanding the loss in permeability influenced by the fracture system due to the increasing effective stress aids to improve recovery in tight reservoirs. [...] Read more.
Permeability is one of the key factors involved in the optimization of oil and gas production in fractured porous media. Understanding the loss in permeability influenced by the fracture system due to the increasing effective stress aids to improve recovery in tight reservoirs. Specifically, the impacts on permeability loss caused by different fracture parameters are not yet clearly understood. The principal aim of this paper is to develop a reasonable and meaningful quantitative model that manifests the controls on the permeability of fracture systems with different extents of fracture penetration. The stress-dependent permeability of a fracture system was studied through physical tests and numerical simulation with the finite element method (FEM). In addition, to extend capability beyond the existing model, a theoretical stress-dependent permeability model is proposed with fracture penetration extent as an influencing factor. The results presented include (1) a friendly agreement between the predicted permeability reduction under different stress conditions and the practical experimental data; (2) rock permeability of cores with fractures first reduces dramatically due to the closure of the fractures, then the permeability decreases gradually with the increase in effective stress; and (3) fracture penetration extent is one of the main factors in permeability stress sensitivity. The sensitivity is more influenced by fracture systems with a larger fracture penetration extent, whereas matrix compaction is the leading influencing factor in permeability stress sensitivity for fracture systems with smaller fracture penetration extents. Full article
(This article belongs to the Special Issue Development of Unconventional Reservoirs) Printed Edition available
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Open AccessArticle
Performance Evaluation of CO2 Huff-n-Puff Gas Injection in Shale Gas Condensate Reservoirs
Energies 2019, 12(1), 42; https://doi.org/10.3390/en12010042 - 24 Dec 2018
Cited by 6
Abstract
When the reservoir pressure is decreased lower than the dew point pressure in shale gas condensate reservoirs, condensate would be formed in the formation. Condensate accumulation severely reduces the commercial production of shale gas condensate reservoirs. Seeking ways to mitigate condensate in the [...] Read more.
When the reservoir pressure is decreased lower than the dew point pressure in shale gas condensate reservoirs, condensate would be formed in the formation. Condensate accumulation severely reduces the commercial production of shale gas condensate reservoirs. Seeking ways to mitigate condensate in the formation and enhance both condensate and gas recovery in shale reservoirs has important significance. Very few related studies have been done. In this paper, both experimental and numerical studies were conducted to evaluate the performance of CO2 huff-n-puff to enhance the condensate recovery in shale reservoirs. Experimentally, CO2 huff-n-puff tests on shale core were conducted. A theoretical field scale simulation model was constructed. The effects of injection pressure, injection time, and soaking time on the efficiency of CO2 huff-n-puff were examined. Experimental results indicate that condensate recovery was enhanced to 30.36% after 5 cycles of CO2 huff-n-puff. In addition, simulation results indicate that the injection period and injection pressure should be optimized to ensure that the pressure of the main condensate region remains higher than the dew point pressure. The soaking process should be determined based on the injection pressure. This work may shed light on a better understanding of the CO2 huff-n-puff- enhanced oil recovery (EOR) strategy in shale gas condensate reservoirs. Full article
(This article belongs to the Special Issue Development of Unconventional Reservoirs) Printed Edition available
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