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14 pages, 2037 KiB

Open AccessArticle

Discussion on Transitional Shale Gas Accumulation Conditions from the Perspective of Source-Reservoir-Caprock Controlling Hydrocarbon: Examples from Permian Shanxi Formation and Taiyuan Formation in the Eastern Margin of Ordos Basin, NW China

by Qin Zhang, Wei Xiong, Xingtao Li, Congjun Feng, Zhen Qiu, Wen Liu, Xiang Li, Yufeng Xiao, Dan Liu and Haixing Yang

Energies 2023, 16(9), 3710; https://doi.org/10.3390/en16093710 - 26 Apr 2023

Cited by 1 | Viewed by 1252

Abstract

Transitional shale gas, rich in resources, is expected to be a practical contributor to the increase in shale gas reserves and production in China. Its exploration prospect has been demonstrated by several wells in the Daning-Jixian block on the eastern margin of the [...] Read more.

Transitional shale gas, rich in resources, is expected to be a practical contributor to the increase in shale gas reserves and production in China. Its exploration prospect has been demonstrated by several wells in the Daning-Jixian block on the eastern margin of the Ordos Basin. In this paper, the Lower Permian Shanxi Formation (P₁s) and Taiyuan Formation (P₁t) in the eastern margin of Ordos Basin were compared for organic geochemical parameters, revealing that the overflow fan + lagoon combination (OLC) of the third sub-member of the second member of Shanxi Formation (P₁s₂³) and the marine + lagoon combination (MLC) of the first member of Taiyuan Formation (P₁t₁) are the most favorable shale gas intervals. The two intervals were comparatively analyzed with respect to mineral composition, brittleness, caprocks, and preservation conditions. It is found that the OLC of P₁s₂³ has a similar porosity to and much lower permeability than the MLC of P₁t₁ (or MLC1) and a BET surface area of 10–15 m²/g, which is smaller than the MLC1 (15–20 m²/g). Moreover, OLC has a brittle mineral content equivalent to MLC1 but a brittleness index of 33.73–62.36 (avg. 49.86), smaller than MLC1 (53.34–58.27, or avg. 55.85). OLC contains sandstones at both the roof and floor, with a higher permeability than shale in the interval, which cannot serve as good physical seals. In contrast, MLC1 contains limestones with lower permeability at the roof and floor, which, together with the overlying coal seams, have hydrocarbon generation capacity and can physically seal the MLC1 shale but also fill it with hydrocarbons, making MLC1 have higher gas content and superior for shale gas exploration than the OLC shale. Due to the multi-lithologies developed in transitional facies, besides the organic matter enrichment, and reservoir characteristics, it is necessary to find a suitable lithological combination to ensure the gas in shale can be better preserved and retained. Full article

(This article belongs to the Special Issue Integrated Managements/Operations of Conventional and Unconventional Reservoirs)

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15 pages, 3669 KiB

Open AccessArticle

Influence of Molasses on the Explosion and Decomposition Properties of the Coal Dust Deposited in Underground Mines

by Jianguo Liu, Minglei Lin, Longzhe Jin, Gang Li, Shengnan Ou, Yapeng Wang, Tianyang Wang, Mulati Jueraiti, Yunqi Tian and Jiahui Wang

Energies 2023, 16(6), 2758; https://doi.org/10.3390/en16062758 - 16 Mar 2023

Cited by 2 | Viewed by 2071

Abstract

Coal dust endangers the health and safety of workers in underground coal mines. Therefore, developing coal dust suppressants with dust prevention and explosion-proof properties is critical. The influence of molasses on the explosion and decomposition of the coal dust deposited in underground mines [...] Read more.

Coal dust endangers the health and safety of workers in underground coal mines. Therefore, developing coal dust suppressants with dust prevention and explosion-proof properties is critical. The influence of molasses on the explosion and decomposition of the coal dust deposited in underground mines was investigated using 20 L explosion experiments and thermogravimetric and differential thermal analysis (TG-DTA). Findings reveal that, first, molasses can weakly promote the explosion of coal dust at low coal dust concentrations (<400 g/m³) but has no significant effect on the explosion at high coal dust concentrations (≥400 g/m³). Second, the decomposition process of the coal dust mixed with molasses has three stages: the moisture evaporation stage (0–150 °C), the molasses decomposition stage (150–300 °C), and the coal dust decomposition stage (300–500 °C). Molasses oxidation consumes oxygen and releases heat; at low coal dust concentrations, the released heat can promote coal dust decomposition to produce combustible gas, enhancing the coal dust explosion; at high coal dust concentrations, under the co-influence of the heat generation and oxygen consumption, molasses has no effect on the coal dust explosion. This is the mechanism of which molasses influences coal dust explosions. Full article

(This article belongs to the Special Issue Integrated Managements/Operations of Conventional and Unconventional Reservoirs)

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21 pages, 4935 KiB

Open AccessArticle

A Novel Performance Evaluation Method for Gas Reservoir-Type Underground Natural Gas Storage

by Qiqi Wanyan, Hongcheng Xu, Lina Song, Weiyao Zhu, Gen Pei, Jiayi Fan, Kai Zhao, Junlan Liu and Yubao Gao

Energies 2023, 16(6), 2640; https://doi.org/10.3390/en16062640 - 10 Mar 2023

Cited by 2 | Viewed by 2026

Abstract

The regulation of the seasonal energy supply for natural gas and the storage of fossil energy are important to society. To achieve it, storing a large amount of natural gas in porous underground media is one of the government’s choices. Due to the [...] Read more.

The regulation of the seasonal energy supply for natural gas and the storage of fossil energy are important to society. To achieve it, storing a large amount of natural gas in porous underground media is one of the government’s choices. Due to the successful lesson learned from the oil and gas industry, natural gas storage in underground porous media has been regarded as the most potential long−term energy storage method. In this paper, we developed a new workflow to evaluate the performance of gas reservoir−type underground natural gas storage (UGS). The theoretical background of this workflow includes the correction of the average formation pressure (AFP) and gas deviation factor by error theory and the analytical mathematical model of UGS wells. The Laplace transform, line source function, and Stehfest numerical inversion methods were used to obtain pressure solutions for typical vertical and horizontal wells in UGS. The pressure superposition principle and weighting method of the gas injection−withdrawal rate were used to obtain the AFP. Through the correction of the AFP and gas deviation factor in the material balance equation, the parameters for inventory, effective inventory (the movable gas volume at standard condition), working gas volume (the movable gas volume is operated from the upper limit pressure to the lower limit pressure), and effective gas storage volume (the available gas storage volume at reservoir condition) were determined. Numerical data from the numerical simulator was used to verify the proposed model pressure solution. Actual data from China’s largest Hutubi UGS was used to illustrate the reliability of the proposed workflow in UGS performance evaluation. The results show that large−scale gas injection and withdrawal rates lead to composite heterogeneity in gas storage wells. The nine injection and production cycles’ pressure and effective inventory changes from Hutubi UGS can be divided into a period of rapid pressure rise and a period of slow pressure increase. The final AFP is 32.8 MPa. The final inventory of the Hutubi UGS is 100.1 × 10⁸ m³, with a capacity filling rate (the ratio of effective inventory to designed gas storage capacity) of 93.6%. The effective inventory is 95.3 × 10⁸ m³, and the inventory utilization ratio (the ratio of effective inventory to inventory) is 95.2%. The working gas volume is 40.3 × 10⁸ m³. This study provides a new method for inventory evaluation of the gas reservoir−type UGS. Full article

(This article belongs to the Special Issue Integrated Managements/Operations of Conventional and Unconventional Reservoirs)

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11 pages, 3002 KiB

Open AccessArticle

Spontaneous Imbibition and Core Flooding Experiments of Enhanced Oil Recovery in Tight Reservoirs with Surfactants

by Shaojie Zhang, Feng Zhu, Jin Xu, Peng Liu, Shangbin Chen and Yang Wang

Energies 2023, 16(4), 1815; https://doi.org/10.3390/en16041815 - 11 Feb 2023

Cited by 2 | Viewed by 2435

Abstract

Despite the implementation of hydraulic fracturing technologies, the oil recovery in tight oil reservoirs is still poor. In this study, cationic, anionic, and nonionic surfactants of various sorts were investigated to improve oil recovery in tight carbonate cores from the Middle Bakken Formation [...] Read more.

Despite the implementation of hydraulic fracturing technologies, the oil recovery in tight oil reservoirs is still poor. In this study, cationic, anionic, and nonionic surfactants of various sorts were investigated to improve oil recovery in tight carbonate cores from the Middle Bakken Formation in the Williston Basin. Petrophysical investigations were performed on the samples prior to the imbibition and core-flooding experiments. The composition of the minerals was examined using the XRD technique. To investigate the pore-size distribution and microstructures, nitrogen adsorption and SEM techniques were applied. The next step involved brine and surfactant imbibition for six Bakken cores and two Berea sandstone cores. The core samples were completely saturated with Bakken crude oil prior to the experiments. The core plugs were then submerged into the brine and surfactant solutions. The volume of recovered oil was measured using imbibition cells as part of experiments involving brine and surfactant ingestion into oil-filled cores. According to the findings, oil recovery from brine imbibition ranges from 4.3% to 15%, whereas oil recovery from surfactant imbibition can range from 9% to 28%. According to the findings, core samples with more clay and larger pore diameters produce higher levels of oil recovery. Additionally, two tight Bakken core samples were used in core-flooding tests. Brine and a separate surfactant solution were the injected fluids. The primary oil recovery from brine flooding on core samples is between 23% and 25%, according to the results. The maximum oil recovery by second-stage surfactant flooding is approximately 33% and 35%. The anionic surfactants appear to yield a better oil recovery in tight Bakken rocks, possibly due to their higher carbonate mineral concentrations, especially clays, according to both the core-scale imbibition and flooding experiments. For studied samples with larger pore sizes, the oil recovery is higher. The knowledge of the impacts of mineral composition, pore size, and surfactant types on oil recovery in tight carbonate rocks is improved by this study. Full article

(This article belongs to the Special Issue Integrated Managements/Operations of Conventional and Unconventional Reservoirs)

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18 pages, 6628 KiB

Open AccessArticle

An Integrated Approach to Reservoir Characterization for Evaluating Shale Productivity of Duvernary Shale: Insights from Multiple Linear Regression

by Gang Hui, Fei Gu, Junqi Gan, Erfan Saber and Li Liu

Energies 2023, 16(4), 1639; https://doi.org/10.3390/en16041639 - 7 Feb 2023

Cited by 4 | Viewed by 1935

Abstract

In the development of unconventional shale resources, production forecasts are fraught with uncertainty, especially in the absence of a full, multi-data study of reservoir characterization. To forecast Duvernay shale gas production in the vicinity of Fox Creek, Alberta, the multi-scale experimental findings are [...] Read more.

In the development of unconventional shale resources, production forecasts are fraught with uncertainty, especially in the absence of a full, multi-data study of reservoir characterization. To forecast Duvernay shale gas production in the vicinity of Fox Creek, Alberta, the multi-scale experimental findings are thoroughly evaluated. The relationship between shale gas production and reservoir parameters is assessed using multiple linear regression (MLR). Three hundred and five core samples from fifteen wells were later examined using the MLR technique to discover the fundamental controlling characteristics of shale potential. Quartz, clay, and calcite were found to comprise the bulk of the Duvernay shale. The average values for the effective porosity and permeability were 3.96% and 137.2 nD, respectively, whereas the average amount of total organic carbon (TOC) was 3.86%. The examined Duvernay shale was predominantly deposited in a gas-generating timeframe. As input parameters, the MLR method calculated the components governing shale productivity, including the production index (PI), gas saturation (S_g), clay content (V_cl), effective porosity (F), total organic carbon (TOC), brittleness index (BI), and brittle mineral content (BMC) (BMC). Shale gas output was accurately predicted using the MLR-based prediction model. This research may be extended to other shale reservoirs to aid in the selection of optimal well sites, resulting in the effective development of shale resources. Full article

(This article belongs to the Special Issue Integrated Managements/Operations of Conventional and Unconventional Reservoirs)

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26 pages, 7022 KiB

Open AccessArticle

Micro-Scale Lattice Boltzmann Simulation of Two-Phase CO₂–Brine Flow in a Tighter REV Extracted from a Permeable Sandstone Core: Implications for CO₂ Storage Efficiency

by Yidi Wan, Chengzao Jia, Wen Zhao, Lin Jiang and Zhuxin Chen

Energies 2023, 16(3), 1547; https://doi.org/10.3390/en16031547 - 3 Feb 2023

Cited by 1 | Viewed by 2128

Abstract

Deep saline permeable sandstones have the potential to serve as sites for CO₂ storage. However, unstable CO₂ storage in pores can be costly and harmful to the environment. In this study, we used lattice Boltzmann (LB) simulations to investigate the factors [...] Read more.

Deep saline permeable sandstones have the potential to serve as sites for CO₂ storage. However, unstable CO₂ storage in pores can be costly and harmful to the environment. In this study, we used lattice Boltzmann (LB) simulations to investigate the factors that affect steady-state CO₂–brine imbibition flow in sandstone pores, with a focus on improving CO₂ storage efficiency in deep saline permeable sandstone aquifers. We extracted three representative element volumes (REVs) from a digital rock image of a sandstone core and selected a tighter REV in the upper subdomain so that its permeability would apparently be lower than that of the other two based on single-phase LB simulation for further analysis. The results of our steady-state LB simulations of CO₂–brine imbibition processes in the tighter REV under four differential pressures showed that a threshold pressure gradient of around 0.5 MPa/m exists at a differential pressure of 200 Pa, and that higher differential pressures result in a greater and more linear pressure drop and stronger channelization after the flow are initiated. Furthermore, we conducted simulations over a range of target brine saturations in the tighter REV at the optimal differential pressure of 400 Pa. Our findings showed that the relative permeability of CO₂ is greatly reduced as the capillary number falls below a certain threshold, while the viscosity ratio has a smaller but still significant effect on relative permeability and storage efficiency through the lubrication effect. Wettability has a limited effect on the storage efficiency, but it does impact the relative permeability within the initial saturation range when the capillary number is low and the curves have not yet converged. Overall, these results provide micro-scale insights into the factors that affect CO₂ storage efficiency in sandstones. Full article

(This article belongs to the Special Issue Integrated Managements/Operations of Conventional and Unconventional Reservoirs)

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18 pages, 10684 KiB

Open AccessArticle

Automatic Evaluation of an Interwell-Connected Pattern for Fractured-Vuggy Reservoirs Based on Static and Dynamic Analysis

by Dongmei Zhang, Wenbin Jiang, Zhijiang Kang, Anzhong Hu and Ruiqi Wang

Energies 2023, 16(1), 569; https://doi.org/10.3390/en16010569 - 3 Jan 2023

Viewed by 1871

Abstract

The types of fractured-vuggy reservoirs are diverse, with dissolution holes and fractures of different scales as the main reservoir spaces. Clarifying the connectivity between wells is crucial for improving the recovery rate of fractured-vuggy reservoirs and avoiding problems of poor water- flooding balance [...] Read more.

The types of fractured-vuggy reservoirs are diverse, with dissolution holes and fractures of different scales as the main reservoir spaces. Clarifying the connectivity between wells is crucial for improving the recovery rate of fractured-vuggy reservoirs and avoiding problems of poor water- flooding balance and serious water channeling. A traditional dynamic connected model hardly describes the geological characteristics of multiple media, such as karst caves and fractures, which cause multiple solutions from the calculation. The static analysis is the basis for connectivity evaluation. In this study, we designed an intelligent search strategy based on an improved A* algorithm to automatically find a large-scale fractured-vuggy connected path by seismic multi-attribute analysis. The algorithm automatically evaluates the interwell-connected mode and clarifies the relationship between the static connected channel and the fractured-vuggy space configuration. Restricted by various factors, such as seismic identification accuracy, a static connectivity study can hardly determine the filling and half-filling inside the channel effectively, even if it can identify the main connectivity channels. An injection-production response analysis based on dynamic production data can more accurately reflect the reservoir’s actual connectivity and degree of filling. This paper further studies dynamic response characteristics based on multifractals combined with production data. To reduce the evaluation uncertainty, we combined the static and dynamic connected analysis results to comprehensively evaluate the main connected modes, such as large fracture connectivity, cavern connectivity, and fractured-vuggy compound connectivity. We use the Tahe oilfield as an example to carry out an automatic evaluation of the connected pattern. The comprehensive evaluation results of the new algorithm were basically consistent with the tracer test results and can better reflect the interwell space-configuration relationship. Our model has certain guiding significance for the adjustment of working measures during waterflooding in fractured-vuggy reservoirs. Full article

(This article belongs to the Special Issue Integrated Managements/Operations of Conventional and Unconventional Reservoirs)

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27 pages, 11062 KiB

Open AccessArticle

Seawater Intrusion Risk and Prevention Technology of Coastal and Large-Span Underground Oil Storage Cavern

by Shengquan He, Dazhao Song, Lianzhi Yang, Xiaomeng Miao, Jiuzheng Liang, Xueqiu He, Biao Cao, Yingjie Zhao, Tuo Chen, Wei Zhong and Taoping Zhong

Energies 2023, 16(1), 339; https://doi.org/10.3390/en16010339 - 28 Dec 2022

Viewed by 1456

Abstract

The presence of a high concentration of Cl⁻ in saltwater will erode the structure and facilities, reducing the stability and service life of the underground oil storage cavern. In order to reduce the risk of seawater intrusion, this paper studies the risk [...] Read more.

The presence of a high concentration of Cl⁻ in saltwater will erode the structure and facilities, reducing the stability and service life of the underground oil storage cavern. In order to reduce the risk of seawater intrusion, this paper studies the risk and prevention technology of seawater intrusion based on a case study of a coastal and large-span underground oil storage cavern. A refined three-dimensional hydrogeological model that comprehensively considers permeability coefficient partitions, faults, and fractured zones are constructed. The seepage fields and seawater intrusion risks of the reservoir site in its natural state, during construction, and during operation are examined, respectively. The study quantifies the water inflow and optimizes the seawater intrusion prevention technology. The results indicate that there is no risk of seawater incursion into the cavern under natural conditions. The water inflows after excavating the top, middle, and bottom sections of the main cavern are predicted to be 6797 m³/day, 6895 m³/day, and 6767 m³/day, respectively. During the excavation period, the water supply from the water curtain system is lower than the water inflow of the cavern, providing the maximum water curtain injection of 6039 m³/day. The water level in the reservoir area decreased obviously in the excavation period, but the water flow direction is from the cavern to the sea. Additionally, the concentration of Cl⁻ in the cavern area is less than 7 mol/m³; hereby, there are no seawater intrusion risks. When only the horizontal water curtain system is deployed, seawater intrusion occurs after 18 years of cavern operation. The concentration of Cl⁻ in the southeast of the cavern group exceeds 50 mol/m³ in 50 years, reaching moderate corrosion and serious seawater intrusion. In addition to the horizontal curtain above the cavern, a vertical water curtain system could be added on the southeast side, with a borehole spacing of 10 m and extending to 30 m below the cavern group. This scheme can effectively reduce seawater intrusion risk and extend the service life of the cavern. The findings of this research can be applied as guidelines for underground oil storage caverns in coastal areas to tackle seawater intrusion problems. Full article

(This article belongs to the Special Issue Integrated Managements/Operations of Conventional and Unconventional Reservoirs)

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19 pages, 10344 KiB

Open AccessArticle

CO₂-Water-Rock Interaction and Pore Structure Evolution of the Tight Sandstones of the Quantou Formation, Songliao Basin

by Yue Zhao, Songtao Wu, Yongjin Chen, Cong Yu, Zhichao Yu, Ganlin Hua, Modi Guan, Minjie Lin and Xiaobo Yu

Energies 2022, 15(24), 9268; https://doi.org/10.3390/en15249268 - 7 Dec 2022

Cited by 2 | Viewed by 1706

Abstract

As an important part of carbon dioxide capture, utilization and storage (CCUS), the progress of injecting CO₂ into oil reservoirs could increase the recovery rate and achieve large-scale carbon storage. It has become one of the most important carbon storage methods around [...] Read more.

As an important part of carbon dioxide capture, utilization and storage (CCUS), the progress of injecting CO₂ into oil reservoirs could increase the recovery rate and achieve large-scale carbon storage. It has become one of the most important carbon storage methods around the world. This paper selected the tight sandstone of the fourth member of the Quantou Formation in the southern Songliao Basin to carry out a CO₂ storage physical simulation experiment. Representative samples were collected at 24 h, 72 h, 192 h and 432 h to study the CO₂ water-rock interaction and to analyze the mineral composition, pore structure and the evolutionary characteristics of physical reservoir properties over time. Physical property analysis, Ion analysis, X-ray diffraction mineral analysis, QEMSCAN mineral analysis, scanning electron microscopy and high-resolution CT scanning techniques were adopted. The main points of understanding were: (i) It shows a differential evolution of different minerals following the storage time of CO₂, and carbonate minerals are mainly dissolved with ankerite as a typical representation; a small amount of calcite is formed in 24 h, and dissolved in the later period; feldspar and quartz were partially dissolved; clay mineral precipitation blocked the pores and gaps; (ii) The evolution in mineral variation leads to the complexity of pore structure evolution, following a trend of “small pores decreasing and large pores increasing” with extending storage time. The final porosity and permeability ratios gradually increase from 4.07% to 21.31% and from 2.97% to 70.06% respectively; (iii) There is a negative correlation between the increasing ratio and the original physical properties of the tight stones due to the dissolution of ankerite. Relevant research could provide scientific guidance and technical support for the geological storage of CO₂ in lacustrine tight continental sandstones and the development of CCUS technology. Full article

(This article belongs to the Special Issue Integrated Managements/Operations of Conventional and Unconventional Reservoirs)

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14 pages, 2876 KiB

Open AccessArticle

Study on the Compatibility between Combined Control of Channel Plugging and Foam Flooding and Heterogeneous Reservoirs—Taking Bohai Z Oilfield as an Example

by Yunbao Zhang, Chengzhou Wang, Ming Liu, Zhen Zhou, Jiamei Quan, Xulin Zheng and Zhaohai Zhan

Energies 2022, 15(17), 6203; https://doi.org/10.3390/en15176203 - 26 Aug 2022

Cited by 3 | Viewed by 1338

Abstract

With the oilfield developed to a later stage and its heterogeneity gradually becoming more serious, the adaptability of conventional profile control technologies for the reservoir becomes worse and worse. Therefore, the fitness of compatibility between combined patterns of profile control and target reservoir [...] Read more.

With the oilfield developed to a later stage and its heterogeneity gradually becoming more serious, the adaptability of conventional profile control technologies for the reservoir becomes worse and worse. Therefore, the fitness of compatibility between combined patterns of profile control and target reservoir becomes an important factor for the efficient development of the oil field. Due to the importance of compatibility between the profile control and reservoir property, research on the remaining oil recovery with combined patterns of profile control and foam flooding were carried out. The experimental results showed that the combined profile control is highly consistent with the target reservoir. With a little lower initial viscosity (28.3–40.9 mPa·s), the channel plugging system is easy to inject. Due to the addition of a polymer, the reinforced foam is not easy to defoam when transporting in the pore throats of the core sample, and its spontaneous adaptability makes it match with the porous media of the formation automatically, which effectively prolongs the transporting distance for the foam in the deep part of the core sample. The segment plug with a gel-type profile control agent injected at the front stage is of great significance to the non-homogeneous reservoir, so it is necessary to inject a sufficient gel-type profile control agent into the high permeability layer to make it produce a seal. When the permeability differential was equal to 10, the maximum increase of oil recovery degree was 29.69%, and the development effect became worse after increasing or decreasing the permeability differential. Full article

(This article belongs to the Special Issue Integrated Managements/Operations of Conventional and Unconventional Reservoirs)

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15 pages, 7136 KiB

Open AccessArticle

New Model of Granite Buried-Hill Reservoir in PL Oilfield, Bohai Sea, China

by Daji Jia, Xiaomin Zhu, Laiming Song, Xu Liang, Li Li, Haichen Li and Zhandong Li

Energies 2022, 15(15), 5702; https://doi.org/10.3390/en15155702 - 5 Aug 2022

Cited by 1 | Viewed by 1647

Abstract

The geological estimated hydrocarbon reserves of the Mesozoic granite buried-hill reservoir in the PL oilfield exceed 200 million tons. During the exploration stage, it was commonly considered that the PL buried-hill reservoir should demonstrate a “layered” edge water reservoir mode, because of weathering [...] Read more.

The geological estimated hydrocarbon reserves of the Mesozoic granite buried-hill reservoir in the PL oilfield exceed 200 million tons. During the exploration stage, it was commonly considered that the PL buried-hill reservoir should demonstrate a “layered” edge water reservoir mode, because of weathering and tectonics. However, during a later stage, the formation of water was found at structurally high locations, which does not fit the intuition. Therefore, a suitable model is still lacking. Based on the comprehensive information of thin-section, core plug, well logging, and seismic data, etc., the buried-hill of the PL oilfield was re-divided into three northeast–southwest-trending zones. In this model, the reservoir is layered, with each layer having the characteristics of bottom water and two kinds of horizontal and vertical seepage. This new model fits the field-drilling test very well. These insights can effectively guide the exploration and development practice for this kind of buried-hill. Full article

(This article belongs to the Special Issue Integrated Managements/Operations of Conventional and Unconventional Reservoirs)

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12 pages, 4076 KiB

Open AccessArticle

The Influence of Movable Water on the Gas-Phase Threshold Pressure Gradient in Tight Gas Reservoirs

by Weiyao Zhu, Guodong Zou, Yuwei Liu, Wenchao Liu and Bin Pan

Energies 2022, 15(14), 5309; https://doi.org/10.3390/en15145309 - 21 Jul 2022

Cited by 10 | Viewed by 1963

Abstract

Threshold pressure gradient (TPG) is a key parameter determining the pore-scale fluid dynamics. In tight gas reservoirs, both gas and water exist in the porous rock, and the existing water can be divided into irreducible and movable water. However, how movable water saturation [...] Read more.

Threshold pressure gradient (TPG) is a key parameter determining the pore-scale fluid dynamics. In tight gas reservoirs, both gas and water exist in the porous rock, and the existing water can be divided into irreducible and movable water. However, how movable water saturation will influence TPG has not yet been investigated. Therefore herein, nuclear magnetic resonance (NMR) and high-pressure mercury intrusion (HPMI) experiments were performed to determine pore-scale water distribution, movable water saturation, and pore throat distribution in the core plugs. Subsequently, the air bubble method was used to measure TPG as a function of movable water saturation and permeability inside tight gas core plugs, finding that TPG increased from 0.01 MPa/m to 0.25 MPa/m with the movable saturation increased from 2% to 35%. Finally, a semi-empirical model was derived to describe the correlation between TPG, movable water saturation, and permeability, which performed better than previous models in the literature. These insights will advance the fundamental understanding of TPG in tight gas reservoirs and provide useful guidance on tight gas reservoirs development. Full article

(This article belongs to the Special Issue Integrated Managements/Operations of Conventional and Unconventional Reservoirs)

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Review

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17 pages, 3887 KiB

Open AccessReview

A Review of Mineral and Rock Wettability Changes Induced by Reaction: Implications for CO₂ Storage in Saline Reservoirs

by Ting Chen, Laiming Song, Xueying Zhang, Yawen Yang, Huifang Fan and Bin Pan

Energies 2023, 16(8), 3484; https://doi.org/10.3390/en16083484 - 17 Apr 2023

Cited by 5 | Viewed by 1840

Abstract

Wettability in CO₂-brine-mineral/rock systems is an important parameter influencing CO₂ storage capacities and leakage risks in saline reservoirs. However, CO₂ tends to react with various minerals and rocks at subsurface conditions, thus causing temporal and spatial wettability changes. Although [...] Read more.

Wettability in CO₂-brine-mineral/rock systems is an important parameter influencing CO₂ storage capacities and leakage risks in saline reservoirs. However, CO₂ tends to react with various minerals and rocks at subsurface conditions, thus causing temporal and spatial wettability changes. Although many relevant research works have been published during past years, a thorough overview of this area is still lacking. Therefore herein, reaction-induced wettability changes are reviewed, and the underlying mechanisms are discussed. Current research gaps are identified, future outlooks are suggested, and some conclusions are drawn. The fundamental understanding of reaction-induced mineral and rock wettability changes during CO₂ storage in saline reservoirs is analyzed and the guidance for long-term CO₂ containment security evaluations is provided. Full article

(This article belongs to the Special Issue Integrated Managements/Operations of Conventional and Unconventional Reservoirs)

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