Reservoir Permeability Research Articles

Research on the Adaptability of Packers for Integrated String Fracturing Operations in Low Porosity and Low Permeability Reservoirs

To study the failure of conventional packers in the fracturing and stimulation of low-porosity and low-permeability reservoirs and reduce the failure accidents of packers in the fracturing process, a suitable integrated string packers was selected in the process of fracturing and stimulation in an oilfield in the Middle East as a case study. Three different well types have been established. The wellbore temperature distribution and the axial force of the string can be calculated under the conditions of various wellhead pressures and different displacement, and it is found that the temperature at the bottom of the well can reach 130 °C, and the maximum axial force at the wellhead is 500 kN. At the same time, the applicability of retrievable tubing testing squeeze (RTTS) and hydraulic-set retrievable (RH) packer in different working conditions was evaluated, and it was found that only RTTS packers can meet the needs of the oil field. According to the calculated temperature field and axial force distribution, the stress on different components of the packer under different working conditions is established during the fracturing-stimulation operation. In the worst working conditions, the maximum stress of the packer occurs at the lower part of the central pipe, reaching 303.83 MPa, which is in a safe state. The contact stress on rubber rings can reach 30 MPa, indicating that the sealing performance can meet the requirements of on-site use. The temperature and axial force data calculated by the model provide a theoretical basis for safe well control. Through model evaluation, it was found that the RTTS packer can be suitable for the fracturing and stimulation needs of the oilfield. The research methods and achievements in the article provide theoretical guidance for evaluating the applicability of packers in the fracturing and stimulation process of low porosity and low permeability reservoirs.

Experimental study of ultra-low IFT foam flooding for low permeability reservoirs

Foam flooding is an effective oil displacement technique to improve fluid sweep efficiency and increase oil recovery. The objective of this paper is to investigate the applicability of ultra-low IFT foam flooding for low permeability oil recovery under the conditions of WX reservoir block in Tuha oilfield (84°C, 86,072 mg/L). A modified amphoteric hydroxy sulfobetaine surfactant (Cn-HSB) was formulated as a foaming agent based on the principle of compatibility with crude oil that could achieve the ultra-low interfacial tension (IFT) and strong foamability simultaneously. This is shown to reduce the oil/water dynamic IFT (DIFT) to an ultra-low value of the order of 10−5 mN/m (0.10wt%), as well as produce a foam volume and half-life of 448 mL and 2567 s, respectively. In addition, results of IFT and foam quality tests indicate that the modified Cn-HSB has good thermal stability and excellent salinity-resistance. Moreover, the ultra-low IFT foam flooding has an ideal injectivity and oil displacement efficiency in low permeability porous media that can mobilize the trapped oil in k = 1.50 × 10−3μm2 with a threshold pressure gradient of 0.115 MPa/m. This improves oil displacement efficiency about 15%OOIP. Fundamental knowledge gained from this research gives insight into the application of ultra-low IFT foam flooding in low-permeability reservoirs under a combination of specific reservoir conditions.

Transient H2O–CO2 wellbore leakage under evolving recharge conditions considering CO2 phase change

Abandoned wells are one of the dominant pathways of deep CO2 leakage, threatening the safety and effectiveness of CO2 geological storage. Although CO2 wellbore flow has been discussed in several studies, the analysis of the CO2 wellbore leakage under evolving recharge conditions based on the transient wellbore-reservoir fully coupled model, which can describe the CO2 gas-liquid phase change, has yet to be reported. Thus, a transient wellbore-reservoir fully coupled model is established in this study to investigate the interaction between CO2 injection and wellbore leakage. The results show that the fluid wellbore leakage may cause significant disturbance to the reservoir and injection well, and the fluid leakage process can be divided into different stages according to the leakage and recharge characteristics. Besides, the wellhead temperature of the abandoned well shows a different variation trend compared with previous studies, which is attributed to the evolving reservoir recharge. The parameter analysis indicates that the gap aperture in the plugs of the abandoned well, plug locations, CO2 injection rate, and reservoir permeability have apparent effects on the fluid leakage rates but have little impact on the leakage pattern. Finally, a dimensionless parameter, the ratio of leakage to injection mass, is proposed to generalize the leakage degree, and the empirical relationship of the ratio of leakage to injection mass with time is established to facilitate quick estimation. This study broadens the understanding of CO2 wellbore leakage and provides a simple method to predict similar leakage scenarios approximately.

Inspirations from Field-Reservoir CO2 Flooding with Different Miscible Degrees under Cross-Scale Oil Reservoir Conditions.

In recent years, CO2 flooding has become one of the main enhanced oil recovery (EOR) methods, especially for tight formations in different oilfields around the world. Most of the CO2 flooding projects carried out in the world are based on miscible flooding, however, this technique is less effective in China because of the depth of the reservoirs and the heavy components of the crude oil. Near-miscible flooding and immiscible flooding have also been gradually applied to China's domestic oil fields, and have achieved certain oil increase effects, but there are still some challenges such as gas channeling, corrosion, and solid phase deposition in the process of CO2 flooding. In this paper, through a detailed review of recent domestic and foreign cases of enhanced oil recovery, the effects of development methods of low permeability and ultralow permeability reservoirs under different miscible degrees are analyzed, and the solutions to some of the existing problems in field tests and experience are systematically summarized. According to the results of field tests, both miscible flooding and near-miscible flooding have similar effects and can achieve better recovery increment, with a long effect period and slow gas breakthrough speed. In addition, the problems of gas channeling, corrosion, and solid phase deposition occurring in the process of CO2 flooding are analyzed, and solutions such as a change in injection methods and coatings are put forward, which effectively promote the development of CO2 flooding technology. Those suggestions are of great significance for improving the oil recovery rate of unconventional oil reservoirs, ensuring the national energy supply, and low-carbon emissions reduction in China.

A Fully Coupled Gas–Water–Solids Mathematical Model for Vertical Well Drainage of Coalbed Methane

The coupling relationship between the deformation field, the diffusion field, and the seepage field is an important factor in fluid transport mechanisms in the long-term coalbed methane (CBM) exploitation process. A mathematical model of gas–water two-phase fluid–structure coupling in a double-porosity medium in coal reservoirs is established in this paper. Taking Hancheng Block, a typical production block in Qinshui Basin, as the geological background critical desorption pressure, reservoir permeability anisotropy is considered in the model. COMSOL Multiphysics (COMSOL_6.0) was used to create the model. The accuracy and rationality of the model were verified by comparing field production data with the results of the simulation. Using the simulation, the influence law of various reservoir geological characteristics parameters (Langmuir strain constant, ratio of critical desorption pressure to reservoir pressure of coal seam (CDPRP), elastic modulus, initial water saturation, Langmuir pressure, etc.) on CBM productivity, reservoir pressure, and permeability ratio was discussed, and a thorough analysis of the factors affecting productivity was obtained using the orthogonal test method. The findings of this study indicate that the change in permeability is the result of the superposition effect of many factors. Different stages of drainage have different primary regulating factors. Rock skeleton stress has a consequence on coal matrix permeability in the early drainage stage, and coal matrix shrinkage is primarily impacted in the later drainage stage. Besides the initial water saturation, other reservoir geological parameters (e.g., CDPRP, Langmuir volume, Langmuir strain constant, elastic modulus) have a strong relationship with productivity. When the value of coal geological parameters increases, the degree of productivity release is higher (as the initial water saturation increases, the production decreases correspondingly). Different coal and rock parameters have varying levels of impact on the drainage stage of CBM wells. The influences of the CDPRP, Langmuir volume, Langmuir strain constant, and elastic modulus on gas production are mainly concentrated in the initial and intermediate drainage stages and begin to fall off during the last drainage stage. Per the multi-factor analysis, the main coal–rock parameters affecting the productivity release are the Langmuir strain constant, followed by the CDPRP and other parameters. The analysis findings can offer theoretical guidance for CBM well selection and layer selection and enhance the block’s overall CBM development level. The improved productivity prediction model for CBM, which is based on fluid–structure coupling theory, can offer a new technical benchmark for CBM well productivity prediction.

Comprehensive Analysis of Connectivity and Permeability of a Pore-Fracture Structure in Low Permeability Seam of Huainan-Huaibei Coalfield.

The connectivity and permeability of the coal seam pore structures control the occurrence and migration of coalbed methane. Coal samples were used from Huainan-Huaibei to reconstruct three-dimensional models of the pores and an equivalent pore network model, Statistical pore structure characteristic parameters. The pore structure of the coal reservoir was analyzed from the direction of multidimensional and multiangle. It shows that based on quantitative analysis, the representative Elementary volume of 500 × 500 × 500 was the most suitable experimental volume. The Y-axis direction of the Renlou sample had poor pore connectivity compared to that of other samples. Large volume connected pores dominated their pore systems. In terms of coal sample pore connectivity, the coal samples from the Liuzhuang and Qidong regions had pore connectivity better than those from the other regions. The pore connectivity of the Liuzhuang coal samples was the best. In terms of coal permeability, the Liuzhuang sample had better permeability than the other three samples, and the permeability was the best in the Y-axis direction. For all the combinations of the different types of throats, the shorter the throat, the greater the equivalent radius and the better the permeability. Conversely, the worse the permeability. During gas injection production, the closer the gas injection area was to the gas injection well, the poorer the connectivity and the lower the permeability over time. Near the production area, where the CO2 did not reach the production area, the fracture porosity and effective connected porosity of the coal reservoir increased over time. When CO2 reached the production area, the change in its connected pore structure was consistent with the change in the connected pores in the gas injection area. With this study, the coal seam pore structure on a microscale was characterized. A comprehensive analysis of the coal reservoir pore connectivity and permeability was completed. The study results are significant for the exploration and development of coalbed methane in the Huainan-Huaibei coalfield.

Permeability Prediction of Carbonate Reservoir Based on Nuclear Magnetic Resonance (NMR) Logging and Machine Learning

Reservoir permeability is an important parameter for reservoir characterization and the estimation of current and future production from hydrocarbon reservoirs. Logging data is an important means of evaluating the continuous permeability curve of the whole well section. Nuclear magnetic resonance logging measurement results are less affected by lithology and have obvious advantages in interpreting permeability. The Coates model, SDR model, and other complex mathematical equations used in NMR logging may achieve a precise approximation of the permeability values. However, the empirical parameters in those models often need to be determined according to the nuclear magnetic resonance experiment, which is time-consuming and expensive. Machine learning, as an efficient data mining method, has been increasingly applied to logging interpretation. XGBoost algorithm is applied to the permeability interpretation of carbonate reservoirs. Based on the actual logging interpretation data, with the proportion of different pore components and the logarithmic mean value of T2 in the NMR logging interpretation results as the input variables, a regression prediction model is established through XGBoost algorithm to predict the permeability curve, and the optimization of various parameters in XGBoost algorithm is discussed. The determination coefficient is utilized to check the overall fitting between measured permeability versus predicted ones. It is found that XGBoost algorithm achieved overall better performance than the traditional models.

Influence of non-intersecting cemented natural fractures on hydraulic fracture propagation behavior

Fractures in deeply buried or formerly deeply buried rocks commonly contain mineral deposits having varying degrees of strength. Understanding how cement deposits in fractures interact with hydraulic fractures (HFs) is important for hydraulic fracture design for practical engineering applications such as enhanced geothermal fluid circulation or oil and gas production. Using discrete element methods, we describe a fully fluid-solid coupling numerical model simulating hydraulic fracture propagation to investigate the influence of cemented natural fractures (CNFs) that do not intersect the predicted path of hydraulic fractures on HF propagation morphology. The fracture morphology depicted by the numerical model aligns well with analytical solutions, indicating the reliability of the simulation results. Using this model, we delved into the effects of fracture cement strength and position, fracturing fluid viscosity, and induced stress field on the interactive propagation patterns of fractures. The simulation results indicate that the HF is captured by weakly non-intersecting CNF, causing the activation of the CNF and the development of cracks primarily caused by tensile failure. As the HF approaches the CNF, the induced tensile stress region at the fracture tip offsets toward the CNF, resulting in fracture reorientation. When the cementing strength ratio between pre-existing natural fracture and reservoir matrix is less than 0.5, it is beneficial to activate CNF and enhance reservoir permeability. The seepage of low-viscosity fracturing fluid into the reservoir significantly enhances the ability of the HF and non-intersecting CNF to communicate with each other, thereby providing favorable pathways for oil and gas flow. The research findings offer valuable insights into fracture network connectivity and permeability enhancement, contributing to enhanced reservoir stimulation strategies.

An environmental-benign method to enhance hydrate production in clayey silty reservoir via splitting grouting

During the pivotal period of energy transition between carbon neutrality and carbon peaking, it is crucial to develop the natural gas hydrate (NGH) due to the advantages of high energy density and non-pollution. However, the NGH production also faces several significant environmental challenges that need to be addressed such as seawater intrusion, methane leakage, and submarine landslides. Therefore, an environmental-benign method to enhance hydrate production in clayey silty reservoir via splitting grouting was introduced. As a novel method for achieving the two goals of both reservoir skeleton reinforcement and permeability enhancement, is proposed to stimulate NGH reservoir. Herein, the formulation based on foamed ultrafine cement-based grout was established. The results showed that the grout has good fluidity with initial viscosity ∼500 mPa·s and consolidation time in the range of 28–50 min. Meanwhile, the consolidation performance evaluation was studied, and it showed that the consolidation is with porosity in the range of 9.41%–46.59%, permeability in the range of 51.23 mD-789.07 mD, and compressive strength in the range of 3.31 MPa–3.88 MPa. The internal pore channels are uniformly distributed with a large number of stomatal strings, which can be used as a multistage seepage channel for gas and water production from hydrate decomposition. To further examine the stimulating behavior, the effect of hydrate saturation, grouting well diameter, grouting flow rate, and in-situ stress on splitting pressure and grouting volume were analyzed, and it was found that the grout has good ability to split fracturing and grout diffusion under the conditions of axial pressure of 5 MPa, confining pressure of 4 MPa, and hydrate saturation not more than 0.30. In addition, an environmental-benign high-efficient reservoir stimulation method on a laboratory scale was proposed. The findings could provide fundamental insights and recommendations for the implementation of splitting grouting in NGH reservoirs.

A two-phase, multi-component model for efficient CO2 storage and enhanced gas recovery in low permeability reservoirs

Introduction: Carbon dioxide (CO2) enhanced gas recovery represents a viable strategy for sequestering CO2 while concurrently augmenting gas production from subsurface reservoirs. Gas reservoirs, as inherent geological formations, are optimal repositories for gaseous compounds, rendering them suitable for CO2 storage. Nevertheless, the economic viability of pure CO2 storage necessitates integration with oil and gas recovery mechanisms to facilitate widespread CO2 utilization.Method: This study addresses the complexities of CO2 enhanced gas recovery through a comprehensive approach that combines theoretical model and numerical simulations. A numerical model is developed to simulate three-component diffusion involving CO2, and methane (CH4) in a two-phase system comprising gas and water.Results: The investigation systematically explores the process of enhanced CH4 extraction and CO2 injection into the reservoir and examines the influencing factors on extraction. Simulation results reveal a power-law decrease in CH4 production rate, stabilizing at a constant extraction rate. Enhanced CH4 extraction benefits from increased porosity, with higher porosity levels leading to greater CH4 extraction. Permeability augmentation positively influences CH4 production, although with diminishing returns beyond a certain threshold. The CO2 injection rate shows a direct proportionality to CH4 production. However, elevated CO2 injection rates may increase reservoir pressure, potentially causing cap rock damage and CO2 gas flushing.Discussion: This study contributes valuable theoretical insights to the field of CO2 enhanced gas recovery engineering, shedding light on the intricate dynamics of multi-component fluid transport processes and their implications for sustainable CO2 utilization.

Preparation and Properties of Reversible Emulsion Drilling Fluid Stabilized by Modified Nanocrystalline Cellulose.

Reversible emulsion drilling fluids can concentrate the advantages of water-based drilling fluids and oil-based drilling fluids. Most of the existing reversible emulsion drilling fluid systems are surfactant-based emulsifier systems, which have the disadvantage of poor stability. However, the use of modified nanoparticles as emulsifiers can significantly enhance the stability of reversible emulsion drilling fluids, but ordinary nanoparticles have the disadvantages of high cost and easily causing environmental pollution. In order to solve the shortcomings of the existing reversible emulsion drilling fluid system, the modified nanocrystalline cellulose was considered to be used as an emulsifier to prepare reversible emulsion drilling fluid. After research, the modified nanocrystalline cellulose NWX-3 can be used to prepare reversible emulsions, and on this basis, reversible emulsion drilling fluids can be constructed. Compared with the reversible emulsion drilling fluid stabilized by HRW-DMOB (1.3 vol.% emulsifier), the reversible emulsion drilling fluid stabilized by the emulsifier NWX-3 maintained a good reversible phase performance, filter cake removal, and oily drill cuttings treatment performance with less reuse of emulsifier (0.8 vol.%). In terms of temperature resistance (150 °C) and stability (1000 V < W/O emulsion demulsification voltage), it is significantly better than that of the surfactant system (temperature resistance 120 °C, 600 V < W/O emulsion demulsification voltage < 650 V). The damage of reservoir permeability of different types of drilling fluids was compared by physical simulation, and the damage order of core gas permeability was clarified: water-based drilling fluid > reversible emulsion drilling fluid > oil-based drilling fluid. Furthermore, the NMR states of different types of drilling fluids were compared as working fluids, and the main cause of core permeability damage was the retention of intrusive fluids in the core.

Simulation of reservoir dynamic damage and influencing factors of horizontal wells in heterogeneous carbonate reservoirs

AbstractAs the development of well types for low permeability reservoirs shifts from vertical to highly inclined/horizontal wells, targeted studies of oil and gas reservoir damage must be conducted for such well types to improve the science and effectiveness of acidification conversion. Taking into account the formation of mud cake and the dynamic damage factors caused by drilling fluid on the reservoir during horizontal well drilling, a refined dynamic description model for nonuniform damage in horizontal wells was established. The coupled simulation accounts for the dynamical destruction of the skin factor of the reservoir and the dynamical generation of the slurry. The coupled model consists of a radial mud cake dynamic formation model, a reservoir damage radius model, a permeability distribution model, and a horizontal well inhomogeneous skin factor model. It captures the dynamic evolution of reservoir damage due to drilling fluid contamination during horizontal well drilling and provides a real‐time representation of changes in the reservoir skin factor of horizontal wells, measuring the depth and extent of radial reservoir damage. Clarifying the extent of reservoir damage and its impact in horizontal well sections can help select appropriate acidification methods, improve acid distribution processes, and ultimately improve the effectiveness of mitigating reservoir damage and increasing oil and gas well productivity.

Study on the Mechanism of Stress Sensitivity Changes in Ultra-Deep Carbonate Reservoirs

Quantitative evaluation of stress sensitivity of ultra-deep carbonate reservoirs has been one of the challenges in exploration and development, and the problem of permeability loss law in ultra-deep carbonates under variable stress conditions has not been solved so far and further research is urgently needed. Through experimental and numerical simulation methods, the stress-sensitive evaluation equations were established based on matrix-type carbonate and fractured carbonate reservoirs, the stress-sensitive changes under different Young’s modulus were discussed, and the degree of permeability loss under different stresses was evaluated. Finally, the dual-media model of ultra-deep carbonate was established, and the practical application was carried out in the Shunbei area of the Tarim Basin. Studies have shown that (1) under the same effective stress, the stress sensitivity of matrix-type and fracture-type carbonate reservoirs is related to the Young’s modulus of the rock skeleton. In matrix-type carbonate reservoirs, rocks with a larger Young’s modulus have smaller rigidity and stronger stress sensitivity. In fracture-type carbonate reservoirs, the stress sensitivity is relatively weak under a smaller Young’s modulus, and relatively strong under a larger Young’s modulus. (2) Measured under the conditions of 87 MPa of peripheral pressure, 50 MPa of flow pressure, and 120 °C, the effective stress of matrix-type carbonate reservoirs has an exponential relationship with the permeability of reservoirs. The degree of stress sensitivity for fracture-type is generally higher than that of matrix-type reservoirs, and the smaller the Young’s modulus, the larger the difference in stress sensitivity. (3) The stress sensitivity of typical ultra-deep carbonates in the Shunbei area of the Tarim Basin is higher by establishing a dual-porosity model based on the initiating pressure gradient, which supports new evidence for the characteristics of ultra-deep carbonates with high-stress sensitivity. In actual production, the impact of stress sensitivity on the reservoir volume calculation and efficient development of ultra-deep carbonate reservoirs requires critical attention.

β-Cyclodextrin modified SiO2 nanofluid for enhanced oil recovery

Recently, with the deterioration of oil storage conditions, the extraction of oil has been limited. In this experiment, β-cyclodextrin (β-CD) was grafted onto the surface of SiO2 nanoparticles. The structure and morphology of nanoparticles were analyzed by various characterization tools to effectively validate the synthesis of nanomaterials. In addition, it was experimentally demonstrated that the developed β-CD-SiO2 nanofluid has excellent stability and salt resistance. Finally, the comparative studies of the nanofluids were carried out by wettability, interfacial tension (IFT), Pickering emulsion, viscosity, and core flooding experiments. The results showed that β-CD-SiO2 nanofluid exhibited better performance: β-CD-SiO2 nanofluid changed the contact angle (CTA) of carbonate plate from 131.5º to 90.1º; the IFT was significantly reduced from about 35 mN/m to 22.5 mN/m; the emulsion droplets formed were fine and dense; the viscosity increased and viscosity not changed with shear rate; and total crude oil recovery up to 59.2%, 23.9% higher than using water drives. Overall, these results showed the great potential of β-CD-SiO2 nanofluid in ultra-low permeability reservoirs.

Study on optimization and mechanism of CO2 injection to enhance oil recovery in mid-deep heavy oil reservoirs

In order to improve the oil recovery of mid-deep heavy oil reservoirs, this study investigates the efficiency of enhanced oil recovery and the mechanisms of oil displacement in mid-deep heavy oil reservoirs using different injected gases (N2, CH4, CO2) and development approaches (gas flooding and gas huff-n-puff) through a series of experiments. These experiments include high-pressure physical properties tests of crude oil after gas injection, displacement efficiency tests of gas injection, and displacement efficiency tests of gas huff-n-puff. The results indicate that for mid-deep heavy oil reservoirs, the preferred optimal injection gas is CO2, with gas huff-n-puff being the most effective development method. Furthermore, a numerical simulation study was conducted to explore the adaptability parameters of CO2 huff-n-puff development in different well patterns, encompassing variables such as the amount of gas injected per cycle, crude oil viscosity, reservoir permeability, and oil layer thickness.

Pore-scale water–gas distribution and gas permeability of natural gas hydrate reservoirs in the South China Sea

Challenges in water drainage within natural gas hydrate reservoirs in the Shenhu area of the South China Sea, characterized by high clay content and strong hydrophilicity, significantly hinder natural gas recovery. Examining the effects of gas pressure and liquid/gas saturation on gas permeability reveals essential insights for increasing gas production potential. We report gas displacement experiments on clayey-silt sediment samples, alongside X-ray computed tomography imaging, that reveal critical findings: a notable increase in flow rate and permeability as displacement pressure nears compaction pressure, highlighting the role of pressure management in enhancing recovery; water displacement from varying pore sizes under different pressures, highlighting the influence of pore size on fluid dynamics, and structural changes, including microfracture formation and a significant fracture that enlarges total pore space by about 15%, which collectively suggest methods to improve gas flow and recovery. Moreover, our analysis identifies average throat length, fractal dimension, and succolarity as principal controls on gas permeability, indicating the substantial impact of microstructural properties on extraction efficiency. These outcomes offer valuable strategies for optimizing natural gas hydrate reservoir development in the South China Sea, emphasizing the need for meticulous pressure and saturation control and in applying a deep understanding of microstructural dynamics.

Declining magma supply to a poroelastic magma mush explains long-term deformation at Soufrière Hills Volcano

Volcano deformation studies traditionally consider melt-dominated magma reservoirs, often overlooking the significant role of poroelastic mush in modifying surface deformation. Here, we analyze the deformation of Soufrière Hills Volcano (SHV) with a focus on a mush-dominated, poroelastic magma reservoir, drawing on temporal deformation data from 14 continuous GPS stations during the ongoing intra-eruptive unrest period. We implemented a 3D Finite Element model and optimization to simulate the observed deformation. Our results reveal that the deformation is likely driven by ongoing, melt injection (Q = 1.1 m³ sec⁻¹) into a low permeability (k = 4.7 × 10⁻¹⁰ m²) reservoir with the injection to the base of the reservoir at 16.5 km depth below sea level. Our findings highlight temporal variations in the melt injection rate to fit the decreasing GPS-recorded deformation rates. An initial injection rate Qi = 1.9 m³ sec⁻¹ inferred at the start of our study period decreases to Qf = 0.3 m³ sec⁻¹ over a 12-year period (2010–2022). Exploratory forward modeling suggests that if current trends continue, the end of magma supply to our modelled reservoir could occur around June 2024 ± 2 years. However, this does not imply the end of associated volcanic hazards at SHV, as the poroelastic diffusion of melt will continue, causing redistribution of melt, surface deformation, and potentially initiating reservoir rupture. While our models offer new insights, inherent limitations in our simulations include interdependencies among our explored model parameters that would benefit from further refinement. Despite these limitations, the study offers crucial guidance on understanding and forecasting volcano deformation dynamics, particularly for volcanoes like SHV with crystal-rich magma reservoirs.

The effects of fractures on porous flow and heat transfer in a reservoir of a U-shaped closed geothermal system

In geothermal reservoirs, fractures, serving as preferential channels for heat transfer fluid circulation, can cause complicated migration patterns and heat transfer characteristics of the fluids. However, the crucial issue of whether and how fractures within a hydrothermal reservoir of a closed geothermal system (CGS) affect reservoir heat transfer fluid migration and the system’s heat transfer is still poorly understood. In this study, we construct a thermo-hydraulic coupling finite-element model to investigate the effects of fractures on fluid flow and heat transfer enhanced by natural convection in a U-shaped closed geothermal system (UCGS) with a horizontal well. We systematically analyze the responses of fluid migration and heat extraction in the system to key factors, such as fracture aperture, fracture azimuth, fracture distribution, and reservoir permeability. The results show that, in a high permeability reservoir (such as 2 × 10−13 m2), the fracture with an aperture of a millimeter scale can greatly strengthen and control the natural convection induced by heat transfer around the horizontal well in a UCGS, achieving a heat recovery efficiency of six times higher than conduction alone within the reservoir. The fracture azimuth can control the heat production region by guiding the evolution of natural convection. Intersecting network-distributed fractures can effectively improve heat recovery area and performance (more than 15%) compared to a single fracture. Some specific fracture segments within a fracture network may exhibit synergy or inhibition in different heat extraction stages, while a fracture connecting in the deep reservoir and orienting to the horizontal well may lead to heat breakthrough. In addition, a low-permeability interlayer below the horizontal well can restrict the heat recovery (nearly 20% drop in our models), but a fracture penetrating the layer can compensate for this hindrance. The findings of this study can contribute to understanding the thermodynamic mechanisms of fluid flow and heat transfer in a fractured reservoir, and then utilizing them to maximize heat recovery rather than considering conduction only, thus providing scientific insights into engineering practices of the UCGS.

Physical simulation study on production characteristics and mechanism of connate water in gas reservoirs

The late-stage development of gas reservoirs often encounters the paradox of significant remaining formation pressure coupled with low wellhead pressure, which indicates small drainage volume, low gas production rate, and low recovery efficiency, reducing gas supply and economic benefit. Owing to the lack of experimental research, the reasons behind this contradiction between gas production and producing pressure differential are unclear. The key factors affecting the development outcomes are reservoir permeability and initial water saturation, while the evaluation parameters include gas and water production rates, reservoir pressure, and recovery efficiency. Based on the characteristic properties of typical gas fields, physical simulation experiments of constant-rate gas production are conducted on spliced long cores with average permeabilities of 2.300, 0.486, and 0.046 millidarcy (mD). Furthermore, leveraging the multi-point embedded pressure measurement technique, the pressure drawdown propagations and the macroscopic and microscopic characteristics of connate water production at the initial water saturations of 0%, 20%, 40%, and 55% are investigated. By connate water, we mean water that occurs naturally within the pores of rock. Pre- and post-experiment core weighing and nuclear magnetic resonance testing are performed. In addition to the mercury injection tests, the results indicate that during gas reservoir depletion, connate water primarily stems from macropores and mesopores, with micropores and nanopores capturing water through capillary imbibition. Moreover, lower permeability and higher initial water saturation lead to greater pressure gradients, increased connate water production, and reduced recovery efficiency. Reservoirs with permeabilities below 0.1 mD are significantly affected by connate water, exhibiting steep pressure profiles. Owing to connate water, the near-wellbore pressure quickly decreases, while distant reservoir pressure barely decreases, implying a limited drainage area. To enhance the recovery efficiency, measures like infill drilling and reservoir stimulation are recommended for low-permeability gas reservoirs.

Well perforation optimization using an abrasive jet technique to create oriented slotted channels in terrigenous reservoirs

Various casing perforation methods are used to ensure a hydrodynamic reservoir-to-well connection. However, perforated wells often do not perform satisfactorily during production. This is largely due to a decrease in the permeability of the near-wellbore formation as a result of casing perforation work. Studies and analysis of existing casing perforation methods have shown the effectiveness of abrasive jet perforation. The paper presents the results of numerical modeling to optimize the layout of slot channels during the abrasive jet perforation (AJP) of terrigenous productive object. Geomechanics analysis of the influence the formation scheme and orientation of the slotted channels in the productive layer during abrasive jet perforation on the permeability of terrigenous reservoirs of the oil fields in the Perm Krai was performed. The disadvantages of widespread methods of exposing perforation are described and the advantages of abrasive jet perforation based on geomechanical modeling are revealed. The calculations carried out on the placement of slotted channels showed that the distance between the systems of slotted channels is not important, since they weakly interact with each other in height with standard schemes. It was established that the best placement scheme for jet slot channels is a system of four slot channels shifted along the length of the well to the height of the slot channel with a phasing of 90°. Comparative calculations of the reservoir permeability of the near-well zone for various perforation methods have been performed.