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Molecular dynamics simulations have been widely used in exploring the nucleation behavior of many systems, including gas hydrates. Gas hydrates are ice-like solids in which gas molecules are trapped in water cages. During hydrate formation, a considerable amount of heat is released, and previous work has reported that the choice of temperature control scheme may affect the behavior of hydrate formation. The origins of this effect have remained an open question. To address this question, extensive NVE simulations and thermostatted (NPT and NVT) simulations with different temperature coupling strengths have been performed and compared for systems where a water nanodroplet is immersed in a H2S liquid. Detailed analysis of the hydrate structures and their mechanisms of formation has been carried out. Slower nucleation rates in NVE simulations in comparison to NPT simulations have been observed in agreement with previous studies. Probability distributions for various temperature measures along with their spatial distributions have been examined. Interestingly, a comparison of these temperature distributions reveals a small yet noticeable difference in the widths of the distributions for water. The somewhat reduced fluctuations in the temperature for the water species in the NVE simulations appear to be responsible for reducing the hydrate nucleation rate. We further conjecture that the NVE-impeded nucleation rate may be the result of the finite size of the surroundings (here the liquid H2S portion of the system). Additionally, a local spatial temperature gradient arising from the heat released during hydrate formation could not be detected. [ABSTRACT FROM AUTHOR]

The dew point pressure can be obtained by conventional condensate gas phase test in PVT cylinders. However, in condensate gas reservoirs, the fluid interacts with the fractured-vuggy porous media, which makes the depletion process of condensate gas in pores, fractures or vugs different from that in PVT cylinder. In order to study the mechanism of this difference, three different experimental models were made to carry out the condensate gas depletion production experiment. The results showed that the existence of fracture-vuggy porous media would affect the depletion production process. The pores, fractures and vugs increased the dew point pressure from 26.2 MPa to 26.6 MPa and decreased the condensate oil recovery from 72.8% to 70.7%. When the fractures, vugs and pores are filled with powered fine sand of carbonate rocks, the dew point pressure reaches 27.4 MPa and the condensate oil recovery reduces to 68.4%. The fractured-vuggy porous media will aggravate the retro condensation phenomenon, promote the accumulation of heavy hydrocarbon components on the pore surface and precipitate in the form of condensate oil and hinder the recovery of condensate oil. This work explains the mechanism of the influence of fractured-vuggy porous media on the phase behavior of condensate gas. [ABSTRACT FROM AUTHOR]

The Bozi 3 reservoir is an ultra-deep condensate reservoir (−7800 m) with a high temperature (138.24 °C) and high pressure (104.78 MPa), leading to complex phase behaviors. Few PVT studies could be referred in the literature to meet such high temperature and pressure conditions. Furthermore, it is questionable regarding the applicability of existing condensate production techniques to such a high temperature and pressure reservoir. This study first characterized the phase behavior via PVT experiments and EOS tuning. The operating conditions were then optimized through reservoir numerical simulation. Results showed that: (1) the critical condensate temperature and pressure of Bozi 3 condensate gas were 326.24 °C and 43.83 MPa, respectively; (2) four gases (methane, recycled dry gas, carbon dioxide, and nitrogen) were analyzed, and methane was identified as the optimal injection gas; (3) gas injection started when the production began to fall and achieved higher recovery than gas injection started when the pressure fell below the dew-point pressure; (4) simultaneous injection of methane at both the upper and lower parts of the reservoir can effectively produce condensate oil over the entire block. This scheme achieved 8690.43 m3 more oil production and 2.75% higher recovery factor in comparison with depletion production. [ABSTRACT FROM AUTHOR]

CO2 flooding is an effective technology for suppling condensate gas reservoir pressure and mitigating global warming. In this study, numerical simulation studies have been conducted to enhance gas recovery in Pen5 condensate gas reservoir using CO2 flooding. Pen5 reservoir has lasted 20 years of primary depletion, which affected by water invasion and retrograde condensation. In numerical simulation study, the GEM module is applied to implement history‐matching of production data, and good agreement has been achieved. Based on comprehensive geological understanding, production dynamics, and numerical simulation techniques, areas with minimal impact from water invasion and retrograde condensation contamination have been delineated. The comparison between continued depletion and the implementation of CO2 injection as a replacement technology in favorable areas has demonstrated the feasibility of CO2 flooding development in these regions. The analysis of the advantages and disadvantages of using miscible flooding and immiscible flooding was conducted, and the optimal development well pattern was evaluated. In the end, the plan of CO2 flooding of Pen5 reservoir has been designed and the gas production rate in the next 10 years has been predicted. The research findings of this study have reference significance for the practical application of CO2 flooding in developing condensate gas reservoirs. [ABSTRACT FROM AUTHOR]

Significant progress has recently been made in deep and ultra-deep oil and gas exploration globally, demonstrating enormous exploration potential of the deep and ultra-deep strata. However, the accumulation and preservation pattern of deep and ultra-deep oil and gas remains poorly understood, greatly impeding further petroleum exploration and development in the deep and ultra-deep strata. By taking the Bozi deep and ultra-deep condensate gas reservoirs in the Kuqa Depression, western China as an example, we attempt to reconstruct the hydrocarbon charge history in such deep reservoirs via an integrated investigation involving quantitative grain fluorescence, fluid inclusion petrography and microthermometry, micro-fluorescence spectroscopy, laser Raman spectroscopy, PVTx modelling, and basin modelling. The results show that: (1) The Bozi deep and ultra-deep reservoirs contain one group of gas inclusion assemblage, and two groups of oil inclusion assemblages, with one being characterized by near yellowish-whitish and blue-whitish diphasic or triphasic oil inclusions, and the other being featured by bright blue diphasic oil inclusions; (2) The first oil charge occurred during the Early Neogene (6.5-5.5 Ma), and the second oil charge occurred during the Late Neogene (4.4-3.5 Ma), under normal hydrostatic pressure or slightly weak overpressure; and (3) The gas charge occurred during the Pleistocene (∼1.6 Ma), with a corresponding reservoir pressure coefficient of approximately 1.7, transforming the reservoir fluid phase state from black oil or volatile oil to condensate gas. Our findings highlight that aside from the present burial depth, a favorable burial history model is crucial for the preservation of liquid hydrocarbons in deep and ultra-deep reservoirs. The occurrence of liquid hydrocarbons in the Bozi deep and ultra-deep condensate gas reservoirs with depths over 7,000 m is benefited from a prolonged period (>100 Ma) of shallow burial and a late-stage (since 10 Ma) rapid subsidence. [ABSTRACT FROM AUTHOR]

Quantum phenomena, including entanglement, superposition, tunneling, and spin-orbit interactions, among others, are foundational to the development of recent innovations in quantum computing, teleportation, encryption, sensing, and new modalities of electronics, such as spintronics, spinorbitronics, caloritronics, magnonics, twistronics, and valleytronics. These emerging technologies provide disruptive influences to global commercial markets. These remarkable advances in quantum technologies are nearly always enabled by the discovery of materials and their quantum behaviors. Such advances are governed by quantum principles that are strongly influenced by environmental, physical, topological, and morphological conditions such as very small length scales, short time durations, ultrahigh pressures, ultralow temperatures, etc., which lead to quantum behaviors that manifest as quantum tunneling, entanglement, superpositioning, superfluidity, low-dimensional, high-temperature and high-pressure superconductivity, quantum fluctuations, Bose-Einstein condensates, topological effects, and other phenomena that are not yet fully understood nor adequately explored. Here, we provide a review of quantum materials developed up to 2023. Remarkable advances in quantum materials occur daily, and therefore, by the time of publication, new and exciting breakthroughs will have occurred that are regrettably not covered herein. [ABSTRACT FROM AUTHOR]

Accurate assessment of the mechanical properties of organic matter, clay matrix, and bulk shale during maturation remains a challenge. Here, we aim to assess the mechanical properties of organic-rich shale during maturation using a combination of nanoindentation methods and various geochemical analyses, i.e., mineral composition, mass loss rate, chemical structure of organic matter, and Rock-Eval analyses. Results show that the evolution of mechanical properties of organic matter in shale during maturation can be divided into: the main oil-generation stage, and the condensate oil and gas generation stage. The stiffening of organic matter in the shale is mainly due to increased aromaticity and condensation of aromatic groups. The clay matrix experiences a slight decrease in hardness and Young's modulus at low maturity levels due to the generation of liquid hydrocarbons. However, overall, the clay matrix becomes stiffer as the shale matures due to shale dehydration, expulsion or cracking of liquid hydrocarbons, transformation of clay minerals, and hardening of organic matter. The Young's modulus and hardness of bulk shale generally increase with increasing maturity. This is closely related to the hardening of organic matter and clay matrix, as well as the development of the more compact and dense microstructure in the shale. [ABSTRACT FROM AUTHOR]

The shale formation, a common carbon-hydrogen reservoir, has numerous nanoscale pores that facilitate multiple gas transport mechanisms, including viscous flow, slip flow, Knudsen diffusion, and surface diffusion. Additionally, various action mechanisms involving effective stress, real gas effect, gas adsorption and desorption, and fracture-pore characteristics significantly influence gas transport. In this study, we conceptualize shale as a triple porosity medium comprising organic matrix, inorganic matrix, and microfractures. For each system, its hydraulic-mechanical coupled model with action mechanisms and gas transport mechanisms is derived based on fractal theory. After validating the model with Barnett and Marcellus data, the evolution of apparent permeability and gas pressure is studied, as well as the influences of pore fractal features, the real gas effect, and the number of hydraulic fractures on gas extraction. Simulation results indicate that, in comparison to organic matrix, inorganic pore fractal features exert a more noticeable effect on cumulative production. The real gas effect is critical in gas transport and reservoir reserve estimation; disregarding this effect results in a 17.4% underestimation of cumulative gas production by the 1600th day. Fracture interference attenuates the improvement in cumulative production gains from increased hydraulic fracture numbers. • A hydraulic-mechanical coupled triple porosity fractal model is established. • Inorganic matrix pore fractal features have a greater impact on gas transport than organic matrix. • Ignoring the real gas effect leads to an underestimation of gas productivity. • The hydraulic fracture interference significantly reduces gas productivity in the late stage of shale gas exploitation. [ABSTRACT FROM AUTHOR]

Fracturing operations can effectively improve the production of low-permeable reservoirs. The performance of fracturing fluids directly affects the fracturing efficiency and back flow capacity. As polymerbased fracturing fluids (such as guar gum (GG), polyacrylamide (HPAM), etc.) are high-viscosity fluids formed by viscosifiers and crosslinking agents, the degree of gel breakage after the fracturing operation directly influences the damage degree to the reservoir matrix and the mobility of oil angd gas produced from the reservoir into the wellbore. This study compared the viscosity, molecular weight, and particle size of the fracturing fluid after gel breakage prepared by GG and HPAM as viscosifiers, as well as evaluate their damage to the core. Results show that the viscosities of the gel-breaking fluid increased with the concentration of the viscosifier for both the HPAM-based and GG-based fracturing fluids. For the breaking fluid with the same viscosity, the molecular weight in the HPAM-based gel-breaking fluid was much larger than that in the GG-based system. Moreover, for the gel-breaking fluid with the same viscosity, the molecular particle size of the residual polymers in the HPAM-based system was smaller than that in the GG-based system. The damage to the core with the permeability of 1 × 10-3 μm² caused by both the HPAM-based and GG-based gel-breaking fluids decreased with the increase in the solution viscosity. For the gel-breaking fluid systems with the same viscosity (i.e., 2-4 mPa s), the damage of HPAM-based fracturing fluid to low-permeability cores was greater than the GG-based fracturing fluid (45.6%e80.2%) since it had a smaller molecular particle size, ranging from 66.2% to 77.0%. This paper proposed that the damage caused by hydraulic fracturing in rock cores was related to the partilce size of residual polymers in gel-breaking solution, rather than its molecular weight. It was helpful for screening and optimizing viscosifiers used in hydraulic fracturing process. [ABSTRACT FROM AUTHOR]

Reservoir characterization, assessing rock mechanical properties, and stress state are essential factors for exploration and development of a hydrocarbon or geothermal reservoir. Computing three-dimensional (3D) geospatial distribution of reservoir geomechanical properties on a reservoir scale becomes challenging, particularly when data are constrained to well locations and complex stress variation within the local anticline structure. To confront such challenges, advanced geostatistical techniques are essential to apply to capture the intrinsic spatial variation of reservoir geomechanical properties precisely. Therefore, this research examines the spatial variability of major mechanical rock parameters, pore pressure, principal stresses, and petrophysical properties of the Baikouquan Formation within the D1 well block, Mahu Sag, China. The dataset consists of seventeen wells and enables the construction of the reservoir's one-dimensional (1D) model, geomechanical parameters, and unified laboratory measurements for calibration of each well. Subsequently, a 3D model is developed via geostatistical simulation techniques, integrating well logs, seismic data, and core data reservoir geomechanical analysis. The modeling results show that the minimum and maximum horizontal stresses are 74–84 MPa and 95–106 MPa, respectively. However, the orientation of maximum horizontal stress was identified as northeast-southwest (NE- SW) and east-west (E-W). This investigation highlights the productiveness of 3D modeling by providing a detailed portrayal and knowledge of pre-production stress state and geomechanical parameters assessment to execute a variety of subsurface operations safely. In addition, it provides a platform for evaluating forthcoming strategies in the reservoir, such as determining the optimal spot and designing new well trajectory for field development and arbitrary scenarios. [ABSTRACT FROM AUTHOR]

Density–density correlation analysis is a convenient diagnostic tool to reveal the hidden order in the strongly correlated phases of ultracold atoms. We report on a study of the density–density correlations of ultracold bosonic atoms which were initially prepared in a Mott insulator (MI) state in one-dimensional optical lattices. For the atomic gases released from the deep optical lattice, we extracted the normalized density–density correlation function from the atomic density distributions of freely expanded atomic clouds. Periodic bunching peaks were observed in the density–density correlation spectra, as in the case of higher-dimensional lattices. Treating the bosonic gas within each lattice well as a subcondensate without quantum tunneling, we simulated the post-expansion density distribution along the direction of the 1D lattice, and the calculated density–density correlation spectra agreed with our experimental observations. [ABSTRACT FROM AUTHOR]

Typical condensate reservoirs have been developed in the No.4 fault zone of the Shunbei area in the Tarim Basin. However, exploration expansion is restricted due to the unclear genetic mechanisms and main controlling factors of condensate accumulation. Through a comprehensive analysis of organic geochemical characteristics and the regional geological background, the genetic mechanisms and main controlling factors of condensate accumulation in the No.4 fault zone of the Shunbei area have been identified, and the following understandings are mainly obtained: (1) the condensate oil and gas reservoirs in the No.4 fault zone of the Shunbei area are mainly primary condensate reservoirs, and their formation is mainly affected by differential maturation of organic matter, multi-phase accumulation, and secondary alteration; (2) the overall secondary effects on the condensate oil and gas reservoirs in the Shunbei No.4 fault zone are relatively weak, however, the secondary effect experienced by the middle and southern sections is relatively stronger compared to the northern section; these secondary processes include oil cracking, gas invasion, and thermochemical sulfate reduction (TSR); and (3) the enrichment degree of condensate oil and gas reservoirs in the northern section of the Shunbei No.4 fault zone is significantly higher than in the middle and southern sections; the enrichment and high production of condensate oil and gas are mainly controlled by transport conditions and reservoir scale. Stronger fault activity, better transport conditions, larger reservoir size, and thinner gypsum-salt rock layers facilitate the upward migration of oil and gas along strike-slip faults, leading to higher production and enrichment of condensate. [ABSTRACT FROM AUTHOR]

Estimation of the reservoir parameters such as porosity, lithology and saturation from well logs and seismic data would require the shear wave velocity data. The high cost of shear wave well logging and subsequently the lack of the shear velocity log in most wells are the main reasons to estimate the shear velocity log. The routine methods for estimating the shear velocity are empirical relations, regression analysis, intelligent methods and rock physics models. Most of these methods do not include the impact of geometry of pore spaces and minerals (aspect ratio). Excluding geometry of pore spaces and minerals from the estimation procedure would create considerable estimation error in the oil and gas reservoirs, particularly in the carbonates. In the first step, shear velocity log is estimated using empirical relations, regression analysis and neural network methods. The estimated shear velocity log using neural network is better than empirical and regression methods. Subsequently, a new simple equation utilizing rock physics models is developed to estimate the shear velocity log. The Xu–White (Geophys Prospect 43: 91–118, 1995) and as reported by Gassmann (Elasticity of porous media, Vierteljahrsschrde Naturforchenden, Gesellschaft, 1951) relations were employed to include the impact of lithology, fluid, minerals and pore spaces. The estimated shear velocity log using new equation compares well with the original as reported by Gassmann (Elasticity of porous media, Vierteljahrsschrde Naturforchenden, Gesellschaft, 1951) and Xu–White (Geophys Prospect 43: 91–118, 1995) rock physics methods. The average difference between the measured and estimated velocity logs using new method is 12.6 m/s (or 0.41%). This equation includes the impact of major parameters in the rock physics model in the simple form; thus, it would be applicable in the carbonate and clastic reservoirs. [ABSTRACT FROM AUTHOR]

Deep condensate gas reservoirs exhibit highly complex and variable phase behaviors, making it crucial to understand the relationship between fluid phase states and flow patterns. This study conducts a comprehensive analysis of the actual production process of the deep condensate gas well A1 in a certain oilfield in China. Combining phase behavior analysis and CMG software simulations, the study systematically investigates phase transitions, viscosity, and density changes in the gas and liquid phases under different pressure conditions, with a reservoir temperature of 165°C. The research covers three crucial depletion stages of the reservoir: single-phase flow, two-phase transition, and two-phase flow. The findings indicate that retrograde condensation occurs when the pressure falls below the dew point pressure, reaching maximum condensate liquid production at around 25 MPa. As pressure decreases, gas phase density and viscosity gradually decrease, while liquid phase density and viscosity show an increasing trend. In the initial single-phase flow stage, maintaining a consistent gas-oil ratio is observed when both bottom-hole and reservoir pressures are higher than the dew point pressure. However, a sudden drop in bottom-hole pressure below the dew point triggers the production of condensate oil, significantly reducing subsequent gas and oil production. In the transitional two-phase flow stage, as the bottom-hole pressure further decreases, the reservoir exhibits a complex flow regime with coexisting areas of gas and liquid. In the subsequent two-phase flow stage, when both bottom-hole and reservoir pressures are below the dew point pressure, a significant increase in the gas-oil ratio is observed. The reservoir manifests a two-phase flow regime, devoid of single-phase gas flow areas. For low-pressure conditions in deep condensate gas reservoirs, considerations include gas injection, gas lift, and cyclic gas injection and production in surrounding wells. Additionally, techniques such as hot nitrogen or CO2injection can be employed to mitigate retrograde condensation damage. The implications of this study are crucial for developing targeted development strategies and enhancing the overall development of deep condensate gas reservoirs. [ABSTRACT FROM AUTHOR]

The efficient development of carbonate rock reservoirs with rich oil and gas resources has become a hot topic and a focal point in the current oil and gas industry. The development of carbonate rock oil and gas reservoirs differs from that of sandstone reservoirs. Although gas flooding, water flooding, and chemical flooding have been carried out in recent years, the development is still unsatisfactory, and the on-site application of technologies such as nanoparticles is on the rise. For the future development of acid fracturing technology, accurate reservoir geological description, core printing based on additive manufacturing technology, the development of new acid fracturing techniques, and the research and development of acid fracturing equipment will have great research potential and economic value in the development of carbonate rock oil and gas reservoirs. Under the development background of high-temperature deep reservoirs, this paper comprehensively reviews unconventional acidizing fracturing fluids in carbonate rock oil and gas reservoirs. We introduce the main components, corresponding mechanisms of action, current research achievements, and advantages of promising acid fracturing fluids, including thickened acids. We focus on the application and limitations under harsh conditions of high temperature and high salinity while also focusing on the development of thickened acid fracturing technology. The thickening agent is the core of a thickened acid solution. Therefore, this article fully reviews the structure, sources, advantages and disadvantages, as well as the current development status of biological, cellulose, and synthetic polymer thickeners. Synthetic polymers, low-molecular-weight polymers, and small-molecular compound crosslinkers provide clues for temperature and salt-resistant thickeners and also promote the development of tight reservoirs. [ABSTRACT FROM AUTHOR]

The geochemical properties of fracturing flowback fluids indirectly indicate the fracturing efficiency of the reservoir, the interaction between the reservoir and injected water, and the preservation of oil and gas, thereby offering robust data support for identifying fracturing flowback fluid sources, assessing fracturing effects, and proposing stimulation strategies. In this study, the ion characteristics, total salinity, and stable isotope ratio of fracturing flowback fluids of the Z202H1 and Z203 wells in Western Chongqing were measured. The findings suggest that with the extension of flowback time, the geochemical properties of fracturing flowback fluids evolve toward higher salinity and heavier stable isotope ratios, ultimately stabilizing. Upon comparing the water–rock reaction intensity and the rate of total salinity increase in the fracturing flowback fluids, it is concluded that fracturing flowback fluids contain a mixture of formation water. Because water–rock reactions elevate the total salinity of fracturing flowback fluids, we introduce the Water–Rock Reaction Intensity Coefficient (IR) to denote the intensity of these reactions. Based on the IR value, the binary mixture model for fracturing fluids in fracturing flowback fluids was adjusted. With the increase in flowback time, the content of fracturing fluids in fracturing flowback fluids of Z202H1 and Z203 stabilized at about 55% and 40% respectively. During the same flowback period, the fracturing flowback fluids of the Z203 well exhibit a higher total salinity, a heavier stable isotope ratio, a greater IR, and a lower fracturing fluid content in fracturing flowback fluids. This suggests that the fracturing effect of the Z203 well is superior to that of the Z202H1 well, leading to a higher production capacity of the Z203 well. [ABSTRACT FROM AUTHOR]

Due to the retrograde condensation phenomenon in the development process, the fluid phase change is complex, and it becomes particularly difficult to accurately describe the fluid flow characteristics and residual oil and gas distribution characteristics during the development of condensate gas reservoirs. It is difficult to select the development program and subsequent dynamic adjustment for the efficient, reasonable, and sustainable development of condensate gas reservoirs. In this paper, the phase characteristics of condensate gas reservoirs are clarified; the basic fluid model is created by using computer modeling, using Win-Prop; and in view of the characteristics of the target condensate gas reservoirs, the CMG (Computer Modeling Group) numerical simulation method is applied to study the effects of six factors, the thickness of the reservoir, permeability, porosity, rock compression coefficient, the ratio of the vertical permeability to the horizontal permeability, and the injection of different media, on the development effect through the study of different development parameters of gas condensate reservoirs. The purpose of this study is to provide guidance for the rational development of condensate gas reservoirs in practical production. [ABSTRACT FROM AUTHOR]

For reservoir fluids with strong volatile tendencies, such as gas condensate and volatile oil, the determination of the characteristic parameters of the equation of state has a great influence on the fluid phase behavior and subsequent reservoir engineering, production engineering, and surface facilities design calculations. However, the process of characterizing reservoir fluid lacks a unified and standardized procedure, and the methods are largely empirical and rather complicated. In this paper, three main stages are defined for the characterization of the equation of state parameters for these volatile reservoir fluids, including (1) determining the C7+ distribution, (2) calculating the equation of state parameters for the C7+ single-carbon component, and (3) lump components. The typical calculation methods in each step and their effects on the fluid phase behavior calculations are quantitatively analyzed and compared. Finally, the workflow and the suitable characterization methods for gas condensate and volatile oil phase behavior calculations are selected. The results show that C7+ distribution and C7+ single carbon component properties have a greater influence on the phase behavior prediction of condensate gas and volatile oil, while the lumping of C7+ single carbon component has relatively little influence. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Oilfield Development in Daqing is the property of Editorial Department of Petroleum Geology & Oilfield Development in Daqing and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Petroleum Geology & Oilfield Development in Daqing is the property of Editorial Department of Petroleum Geology & Oilfield Development in Daqing and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Natural Gas Geoscience is the property of Natural Gas Geoscience and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Natural Gas Geoscience is the property of Natural Gas Geoscience and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

A hallmark of biomolecular condensates formed via liquid-liquid phase separation is that they dynamically exchange material with their surroundings, and this process can be crucial to condensate function. Intuitively, the rate of exchange can be limited by the flux from the dilute phase or by the mixing speed in the dense phase. Surprisingly, a recent experiment suggests that exchange can also be limited by the dynamics at the droplet interface, implying the existence of an 'interface resistance'. Here, we first derive an analytical expression for the timescale of condensate material exchange, which clearly conveys the physical factors controlling exchange dynamics. We then utilize sticker-spacer polymer models to show that interface resistance can arise when incident molecules transiently touch the interface without entering the dense phase, i.e., the molecules 'bounce' from the interface. Our work provides insight into condensate exchange dynamics, with implications for both natural and synthetic systems. [ABSTRACT FROM AUTHOR]

A large number of publications have been devoted to the study of aerosol atmospheric transport, but the low-temperature transfer of metals and metalloids as a part of gas flow remains poorly understood. The present work is devoted to the study of gas stream composition using an approach based on the collection of nascent condensate upon cooling of the air flow formed over the surface of contaminated sites. A special laboratory unit was designed to collect the condensate followed by the study of its composition using atomic emission and mass spectrometry. The main novelty of this work consists of the application of the single-particle ICP‒MS technique to obtain qualitative information concerning the state of the elements in the condensates. Gold and silver are most likely present in the samples as nanoparticles; arsenic, selenium, tin and lead are present both as nanoparticles and as soluble forms; and barium and mercury are present only in soluble forms. The condensed phase contains As, Hg, Au, Ag, Pb and Sn at the ppb level, while the main elements of the tailings material (Fe, Ba, Cu, Zn and others) are present at the ppm level, which exceeds the background concentration. [ABSTRACT FROM AUTHOR]

To solve problems such as inadequate proppant carrying capacity, a complex viscosity changing process, and limited environmental friendliness associated with traditional slick water fracturing fluids, a variable viscosity friction reducer called Jianghan friction reducer (JHFR) with low damage, high drag reduction, and strong proppant‐carrying capacity is prepared by inverse emulsion polymerization. The properties of JHFR are investigated by viscometer, JHFR‐II high‐temperature and high‐pressure slick water drag reduction rate tester, surface tension meter, and JHCQ Core dynamic damage evaluation device. The result shows that the dissolution time of JHFR is less than 120 s. The drag reduction of 0.08 wt% JHFR (4.83 mPa s) is 80.3%. When the concentration of JHFR increases from 0.08 to 0.8 wt %, the viscosity of the JHFR increases from 4.83to 97.41 mPa s. After sheared at 90°C and 170 s−1 for 60 min, the viscosity of 0.8 wt% JHFR still maintains 51 mPa s. The damage rate of JHFR to core matrix permeability is lower than 30%. JHFR also shows the advantages of easy breakage and low residue. It provides guidance for the design and selection of fracturing fluid for unconventional oil and gas reservoir development. [ABSTRACT FROM AUTHOR]

This document provides an overview of recent advancements in petroleum and gas engineering. It highlights the importance of oil and natural gas resources as crucial energy sources, although they are considered non-renewable. The document discusses the global trends in natural gas development and ongoing research in coal mining. It also emphasizes the need for research in key aspects of oil and gas engineering, such as logging, reservoir properties, drilling, and pipeline safety. The document further summarizes recent research papers in the field, covering topics such as reservoir characteristics, logging techniques, extraction techniques, geological characteristics, pipeline safety, and crude oil quality enhancement. It concludes by suggesting future research directions in oil and gas engineering, including intelligent and automated technologies and advanced equipment development. [Extracted from the article]

Commonly used brine-based completion fluids are calcium chloride, sodium chloride, and potassium chloride. Our main objective for this study is to overcome the rheological performance and density limitations of existing brine-based completion fluid for workover and completion in oil and gas reservoirs. Magnesium Bromide-based completion fluid exhibits a high-density 13.41-lb/gal, with a specific gravity of 1.61. Existing, calcium chloride, potassium chloride, and sodium chloride-based completion fluid exhibit a density of 11.64-lb/gal (specific gravity 1.39), 9.6-lb/gal, (specific gravity 1.15), and 10.02-lb/gal (specific gravity 1.20), respectively. Results suggest that a high-density and solid-free novel magnesium bromide-based completion fluid show suitable optimum rheology avoid formation damage, plugging, and eroding of tubular and completion equipment. In this study, we have investigated the rheological properties such as apparent viscosity, plastic viscosity, yield point, and gel strength 10 sec and 10 min of formulated completion fluid at the varying temperature of 84 °F (28.8 °C) to 192 °F (88.8 °C). We have found that magnesium bromide-based completion fluid shows lower apparent viscosity and plastic viscosity as compared to calcium chloride-based completion fluid. A low value of apparent viscosity is desired for the design and development of the completion fluid. [ABSTRACT FROM AUTHOR]

• Gas-solid coupling corrosion of steels under Cl-containing environment is studied. • The gas–solid coupling corrosion is much stronger than the independent gas corrosion. • Two layers of corrosion products with huge different characteristics are observed. • FeCl 2 &CrCl 2 amalgamate with the chloride salts form a low-melting liquid phase layer. • The O and Cl elements react with the metal substrate through the molten layer. The fast development of the waste incineration industry requires deeper insights into heating surface corrosion behavior at higher operating parameters with complex corrosion sources. This research investigates the corrosion behaviors of three types of plates, namely SA210-C, TP310, and 12CrMoV, when subjected to simulated flue gas and fly ash deposition simultaneously at temperatures ranging from 500℃ to 620℃. The results indicate that the weight loss due to coupling corrosion was 2.5 to 84.5 times higher than that of gas-phase corrosion under the same operating conditions. Among the three stainless-steels, TP310 demonstrates superior corrosion resistance. It is worth noting that, under the gas–solid coupling corrosion conditions, we observed a distinct two-layer structure of corrosion products. Despite the fly ash simulants detaching over time, the two-layer structure remained unchanged. Based on the theory of eutectic molten salt formation, we propose that alkali metal chlorides only initiate the formation of the molten layer in the initial stage of corrosion. Furthermore, we offer additional suggestions for the mechanism of sustaining the molten layer in the absence of alkali metal chlorides. [ABSTRACT FROM AUTHOR]

The usage of nanoparticles is effectively enhanced in industries and technologies because of their intensified thermal performance. Nanomaterials innovatively play a significant role in technological applications such as biosensors, the petroleum related industry and biofuels. Due to such exceptional performance of nanomaterials, the magneto-hydrodynamics squeezed nanofluid flow is examined through the parallel walls. The transportation phenomenon of heat and mass with viscous dissipation and double stratification is also investigated under Cattaneo–Christov phenomenon. The constitutive equations (PDEs) are transmuted with precise similarity variable into dimensionless equations (ODEs). The acquired ODEs are evaluated through the assistance of Homotopic technique. The impacts of the emerging parameters are described graphically on the concerned profiles. The graphical discussion clarifies that both stratification parameters diminish both profiles (thermal & solutal). Concentration field is decreased by the thermophoresis parameter. The relaxation time parameters decrease the heat and mass transport. Moreover, both Brownian and thermophoresis parameters raise the temperature. [ABSTRACT FROM AUTHOR]

Most of the implemented marine gas hydrate test exploitation in the world adopt the depressurization method to break down the hydrate in the reservoir into natural gas and then extract it, but because the gas production results are still a certain distance away from the commercial exploitation, and it mainly stays in the stage of theoretical research and trial exploitation. Based on two trial productions in the Shenhu area of the South China Sea, this study established a model for hydrate exploitation and investigated the impact of different well types on the recovery rates of hydrates and free gas in different development layers during depressurization. For the Class 1 hydrate reservoirs, horizontal wells are the optimal solution to extract hydrate and free gas simultaneously when exploiting the hydrate three-phase layer. Meanwhile, the effect of different well spacing in vertical wells on the recovery rate of hydrate and free gas was studied. It is found that the best recovery efficiency is achieved when the spacing between two wells is 80 m. The lower the bottom flow pressure of the well, the higher the production capacity, but its influence is limited. [ABSTRACT FROM AUTHOR]

Granite buried hill oil and gas reservoirs are relatively scarce worldwide, and the fine prediction and characterization of their fractures have always been a significant industry challenge. Particularly in the South China Sea region, large and thick granite buried-hill reservoirs are influenced by various geological processes such as weathering and tectonics, resulting in a complex internal fracture system. The seismic reflection characteristics exhibit high steepness, discontinuity, and significant amplitude differences, posing significant difficulties for the fine characterization of fractures. A systematic and comprehensive research approach has not yet been established. Therefore, this study considers the large granite-buried hill A reservoir in the South China Sea as a typical case study and proposes a multi-scale fracture fine prediction and characterization methodology system. The method starts with analyzing the fracture scale and genesis to refine the fracture scales identifiable by conventional seismic data. Based on this, the U-SegNet model and transfer learning are utilized to achieve fine detection of large-scale fractures. Meanwhile, using highresolution ant tracking technology based on MVMD frequency division and sensitive attribute preferences realizes a fine prediction of medium-to-small-scale fractures. Furthermore, the discrete fracture network is used for fracture deterministic modeling, ranging from geometric morphology to percolation behavior. Ultimately, a post-stack seismic multi-scale fracture prediction and characterization workflow is established. The results indicate that the buried hill in the study area exhibits a high degree of fracture development with evident multi-scale characteristics. Among them, large-scale fractures have a relatively low development density, primarily oriented in the NW and NE directions; medium-to-small-scale fractures exhibit high-density and omnidirectional development. The development of fractures significantly improves the storage space and fluid flow capacity of the buried hill. Compared with traditional methods, the proposed method notably enhances the accuracy of characterizing the degree of fracture development, spatial morphology, and percolation behavior in the buried hill reservoir, providing a scientific basis for oil and gas exploration and development. [ABSTRACT FROM AUTHOR]

The Dina 2 gas field in the Kuqa Depression of the Tarim Basin is one of China's most critical oil and gas exploration areas. Natural fractures have played an important role in the low-permeability reservoirs in the Tarim area. Tectonic fractures are dominant in such reservoirs. In fact, the factors influencing tectonic fracture development have always been the source of important issues in tight reservoirs. Cores, thin sections, and borehole image logs were used to analyze the types, basic characteristics, and factors influencing tectonic fractures in the tight sandstone reservoirs of the Dina 2 gas field in the Tarim Basin. The results showed that the tectonic fractures are dominated by high-angle and upright shearing fractures, and they mainly show ENE–WSW strikes. The thin sections suggest that 60% of the fractures are fully filled with minerals, 20% are unfilled, and 20% are partially filled. The analysis also shows that lithology, faults, and in situ stress are the main factors controlling the development of the tectonic structures. Furthermore, the correlation between the unimpeded flow from a single well and the apertures of the tectonic fractures indicates that tectonic fractures play an important role in the production of hydrocarbons. [ABSTRACT FROM AUTHOR]

Multiple types of reservoirs, including volatile oil reservoirs, condensate gas reservoirs, and dry gas reservoirs, have been discovered in ultra-deep layers buried at depths greater than 7500 m. Understanding the genetic types of natural gas is of utmost importance in evaluating oil and gas exploration potential. The cumulative proved reserves of the super deep layer in the Shuntuoguole low uplift area of the Tarim Basin exceed 1 × 108 t (oil equivalent). The origin, source, and accumulation characteristics of natural gas still remain a subject of controversy. By analyzing the composition and carbon isotope of natural gas, a detailed investigation was conducted to examine the unique geochemical and reservoir formation characteristics of the Ordovician ultra-deep natural gas within different fault zones in the middle region of the Shuntuoguole low uplift. It was determined that most of the natural gas in this area is displaying a characteristic of wet gas with a drying coefficient ranging from 0.41 to 0.99. The carbon isotope composition of methane in the gas reservoir shows relatively light values, ranging from −49.4‰ to −42‰. The carbon and hydrogen isotopes of the components are distributed in a positive order. The natural gas is oil type gas, which is derived from marine sapropelic organic matter and has a good correspondence with the lower Yuertusi formation. The maturity of natural gas in Shunbei No. 1 and No. 5 fault zones is about 1.0%, which is the associated gas of normal crude oil, while the maturity of No. 4 and No. 8 fault zones is higher than 1.0%, which is the mixture of kerogen pyrolysis gas and crude oil pyrolysis gas. The variations in the drying coefficient and carbon isotope composition of the natural gas provide evidence for the migration patterns within the Shuntuoguole low uplift central region. It indicates that the Shunbei No. 5 and No. 8 fault zones have likely migrated from south to north, while the No. 4 fault zone has migrated from the middle to both the north and south sides. These migration patterns are primarily controlled by high and steep strike-slip faults, which facilitate the vertical migration of natural gas along fault planes. Consequently, the gas accumulates in fractured and vuggy reservoirs within the Ordovician formation. [ABSTRACT FROM AUTHOR]

In tight reservoir development, traditional enhanced oil recovery (EOR) methods are incapable of effectively improving oil recovery in tight reservoirs. Given this, inter-fracture flooding is proposed as a new EOR method, and physical model simulation and numerical simulation are performed for inter-fracture water flooding. Compared with inter-fracture water flooding, inter-fracture gas flooding has a higher application prospect. However, few studies on inter-fracture gas flooding have been reported, and its EOR mechanisms and performance are unclear. This paper used the geological model of the actual tight reservoir to carry out numerical simulations for two horizontal wells in the Changqing Yuan 284 block. The results showed that (1) inter-fracture gas flooding can effectively supplement formation energy and increase formation pressure; (2) inter-fracture gas flooding delivers simultaneous displacement, which can effectively increase the swept area in tight reservoirs; (3) injected CO2 dissolves into the reservoir fluid, reduces fluid viscosity, and improves fluid flow through the reservoir; and (4) the recovery factor increment of the CO2 injection is higher than those of natural gas injection and N2 injection. The findings of this research provide references for the production and development of tight reservoirs. [ABSTRACT FROM AUTHOR]

Although considerable laboratory and modeling activities were performed to investigate the enhanced oil recovery (EOR) mechanisms and potential in unconventional reservoirs, only limited research has been reported to investigate actual EOR implementations and their surveillance in fields. Eleven EOR pilot tests that used CO2, rich gas, surfactant, water, etc., have been conducted in the Bakken unconventional play since 2008. Gas injection was involved in eight of these pilots with huff 'n' puff, flooding, and injectivity operations. Surveillance data, including daily production/injection rates, bottomhole injection pressure, gas composition, well logs, and tracer testing, were collected from these tests to generate time-series plots or analytics that can inform operators of downhole conditions. A technical review showed that pressure buildup, conformance issues, and timely gas breakthrough detection were some of the main challenges because of the interconnected fractures between injection and offset wells. The latest operation of co-injecting gas, water, and surfactant through the same injection well showed that these challenges could be mitigated by careful EOR design and continuous reservoir monitoring. Reservoir simulation and machine learning were then conducted for operators to rapidly predict EOR performance and take control actions to improve EOR outcomes in unconventional reservoirs. [ABSTRACT FROM AUTHOR]

The Albian–Aptian Goru Formation represents a fluvio-deltaic reservoir in both the Central and Southern Indus Basin, Pakistan. Using high-resolution core data, this study provides comprehensive insights into the depositional environment and its role in influencing reservoir heterogeneities in the studied formation. The sedimentological investigations demonstrate five lithofacies, namely, (i) massive sandstone (Sm), (ii) horizontal to low-angle planar laminated sandstone (Sl), (iii) planar cross-laminated sandstone (Sc), (iv) heterolithic beds (Hw and Hr), and (v) massive mudstone (Mm). Facies associations reflect shallow marine depositional settings varying from deltaic in the NE to strand plain in the SW. The framework grains of the established lithofacies exhibit quartzo-feldspathic petrofabrics, which have been sourced from stable craton-continental block settings. The petrophysical data in the core depth zone show high shale content in Well-A and lower parts of Well-B. In Well-A, the crossover between the density and neutron logs is not observed, which suggests unsaturated sands, while Well-B exhibits a permeable zone as indicated by neutron-density crossover, low gamma ray values, and relatively high porosity. The petrographic analysis and scanning electron microscopy indicate high effective porosities contributed by both primary (intergranular and intercrystalline) and secondary porosity (owing to fracturing and dissolution). The upper part of Well-B shows high porosity values up to 28% due to highly fractured quartz. Porosity values are low in the lower parts of the Well-A and Well-B due to intensive calcite cementation, chlorite recrystallization, proto matrix as well as pseudo matrix. This suggests that both Well-A and Well-B have a common source but the reservoir properties can be attributed to the depositional and post-depositional variations in the petrofabric of the studied lithological units. The Cretaceous Goru Formation in Southern Indus Basin, the Pariwar formations in Jaisalmar Basin, and Bhuj Formation in Kutch Basin share same geological history and sedimentary processes. Thus, these studies can be utilized in the exploration of Cretaceous reservoirs in these basins. [ABSTRACT FROM AUTHOR]

The stratum can be modelled as a horizontal transversely isotropic medium when a single set of vertically parallel fractures embedded in an isotropic background medium, which facilitates efficient study for fractured reservoirs. Elastic parameters and fracture weaknesses are important parameters to describe the characteristics of fractured reservoirs, and seismic inversion plays a significant role in parameters estimation. The commonly used deterministic inversion methods do not fully utilize the prior information and fails to present the uncertainty analysis of inversion results. To address these shortcomings, we propose a Bayesian linearized amplitude variation with offset and azimuth inversion method tailored for horizontal transversely isotropic media, enabling a more robust analysis of uncertainty. Within the framework of Bayesian inversion, the proposed method successfully derives analytical expressions for the posterior mean and covariance of both elastic parameters and fracture weaknesses. The response characteristics of the anisotropic reflection coefficient are analysed, and it is found that the perturbations of elastic parameters have a greater effect on reflection coefficient compared to fracture weaknesses. Synthetic data examples confirm that the accuracy of estimated P‐ and S‐wave velocities and density surpasses that of fracture weaknesses, and the proposed method still performs well for the case of moderate noise. A field data example demonstrates that the inverted profiles agree well with the logging curve, and the estimated fracture weaknesses display significantly high values in the reservoir area. The estimated reservoir parameters not only contribute to a more accurate representation of the fractured gas‐bearing reservoir but also provide insights into the target gas reservoir through its posterior distribution. Both synthetic and field data examples demonstrate the stability and reliability of the proposed method in characterizing fractured reservoirs. We determine that the proposed method provides an available tool for nuanced evaluation of uncertainty for the inversion results, and it is helpful for the fine description of fractured hydrocarbon‐bearing reservoirs. [ABSTRACT FROM AUTHOR]

This study addresses the critical challenge of excessive water production in mature oil and gas reservoirs. It focuses on the effectiveness of polymer gel injection into porous media as a solution, with an emphasis on understanding its impact at the pore scale. A step-wise Lattice Boltzmann Method (LBM) is employed to simulate polymer gel injection into a 2D Berea sample, representing a realistic porous media. The non-Newtonian, time-dependent characteristics of polymer gel fluid necessitate this detailed pore-scale analysis. Validation of the simulation results is conducted at each procedural step. The study reveals that the methodology is successful in predicting the effect of polymer gel on reducing permeability as the gel was mainly formed in relatively larger pores, as it is desirable for controlling water cut. Mathematical model presented in this study accurately predicts permeability reductions up to 100% (complete blockage). In addition, simulations conducted over a wide range of gelation parameters, TD_factor from 1 to 1.14 and Threshold between 0.55 and 0.95, revealed a quadratic relationship between permeability reduction and these parameters. The result of this research indicates LBM can be considered as promising tool for investigating time-dependant fluids on porous media. [ABSTRACT FROM AUTHOR]

Condensate blockage significantly impairs gas production in low-permeability reservoirs by reducing gas relative permeability and increasing condensate saturation near the wellbore. Particularly acute in reservoirs with low pressure and permeability, effective solutions are required to mitigate this formation damage. This study introduces a novel acid treatment strategy aimed at enhancing the injectivity index in gas reservoirs afflicted by condensate blockage. Leveraging mineralogical analysis, Hydrochloric Acid (HCl) was identified as the optimal acidizing agent. The most effective concentrations of HCl for rock dissolution—15% and 7.5%—were determined through dissolution tests. The research further advances by adding methanol to the acid mix, resulting in three distinct formulations: HCl 15 wt%, HCl 15 wt% + methanol, and HCl 7.5 wt% + methanol. Comprehensive wettability alteration tests and coreflood experiments were conducted to evaluate the efficacy of these systems in permeability enhancement. The HCl 7.5 wt% + methanol formulation demonstrated superior performance in permeability improvement and condensate blockage reduction, outshining the other systems. Notably, this new acid system effectively altered wettability from hydrophobic to hydrophilic, facilitating the passage of condensate through the pore throats and thus aiding in the removal of blockages. The integration of methanol with HCl, particularly at a 7.5 wt% concentration, represents a significant advancement in the treatment of condensate blockage in gas reservoirs, promising to improve gas recovery rates by addressing the challenges posed by low-permeability formations. [ABSTRACT FROM AUTHOR]

Tight sandstone reservoirs are significant sources of natural gas reserves. As traditional reserves become increasingly scarce and costly, optimizing the development of these reservoirs becomes crucial. This study introduces a novel two-phase gas–water flow model for single wells, incorporating both Darcy and non-Darcy flow equations. These equations are derived from mass conservation and momentum principles for both gas and water phases. Using data from a real tight gas well, our model, which includes stress-sensitive phases for gas and water, outperforms traditional Darcy flow models. Specifically, the average relative deviations in daily production rates were 0.1815% for gas and − 0.2677% for water, which are significantly smaller compared to traditional Darcy flow models. Further application of the non-Darcy flow model reveals strategies to enhance well performance. For example, mitigating liquid lock damage within a 2 m radius near the well could restore the permeability from 0.045 to 0.143 mD, thereby tripling the daily gas production. This non-Darcy flow model is easy to implement and shows significant potential in forecasting production yields in tight sandstone reservoirs, highlighting its importance in the petroleum and natural gas industry. [ABSTRACT FROM AUTHOR]

Liquid carry-over phenomenon, where liquid droplets escape with gas, is a prevalent operational challenge in gas–liquid separators. Liquid carry-over leads to foaming issue and performance reduction within separator downstream absorption processes. In order to ascertain whether liquid carry-over is inducing foaming within the gas sweetening process's absorption tower at Iraq's Khor Mor gas-condensate processing plant, this study initiated an evaluation of the liquid droplet size distribution in the gas product and gas/liquid separation efficiency of upstream Alpha, Bravo #1, Bravo #2, and Charlee separators that feed into the aforementioned tower by using the Horizontal Vessel and ProSeparator correlations in Aspen HYSYS v.11 software. The study revealed that Alpha and Bravo #2 experienced liquid carry-over issues. In response to these challenges, an innovative smart separator design, referred to as an adjustable separator, was proposed, employing the Arnold-Stewart semi-empirical procedure. This design allows for easy adjustment to accommodate changes in feed composition and operational conditions, mitigating the liquid carry-over problem. The smart design demonstrated a significant increase in gas/liquid separation efficiency for Alpha separator, improving by 31.11% under current conditions and 77.65% under future conditions. Similarly, under both current and future conditions, the smart design of Bravo #2 separator yielded an enhancement of 21.31% and 28.23%, respectively. These results suggest that the smart design can be considered an optimal solution for controlling liquid carry-over. This innovation not only maintains high gas/liquid separation efficiency but also prevents foaming, offering a robust solution for ensuring sustained operational performance and productivity in gas–liquid separation processes. [ABSTRACT FROM AUTHOR]

This work is focused on developing a computational model to predict the production rate and pressure evolution of natural gas from unconventional reservoirs, particularly shale gas deposits. The model is based on the principle of conservation of mechanical energy and was developed from the transient solution of Bernoulli's equation. This solution was obtained by computing the pressure evolution in the well resulting from the combined action of extracting the free gas and of gasification from kerogen. The transient behavior of gas production by hydraulic fracturing was calculated by numerically integrating Bernoulli's equation. The curves representing gas flow evolution were considered as a series of stepwise steady states under a constant gas flow rate, similar to the pressure–time curves. These time steps were connected by instantaneous drops in pressure or gas flow rates. On the other hand, the delayed release of the adsorbed and dissolved gas in the kerogen was accurately calculated by introducing a semi-empirical gas pressure source term into the gas well pressure equation. The effect of this source is to gradually increase the gas pressure in the reservoir, emulating the gas release mechanisms from the organic matter. Model validation was based on production data from the unconventional reservoirs Eagle Ford, U.S.A., and Burgos basin, México. The initial measured gas production rate was used to determine a global friction factor of the gas flowing out from soil cracks and ducts. Additionally, measured production rate data were used to determine the coefficients of the source term function. Pearson correlation coefficients of 0.97 and 0.96 were obtained for Eagle Ford and Burgos basins data, respectively. In contrast, the corresponding coefficients calculated from the traditional Arps' model were 0.89 and 0.5, respectively. The present pressure source model (PSM) represents a new approach to characterize the process of gas production from unconventional reservoirs, proving to be accurate in forecasting both the gas flow rate and pressure evolution during gas production. The postulated pressure source term was shown to mimic the desorption and diffusion kinetics, which release free gas from the kerogen. [ABSTRACT FROM AUTHOR]

The B6 metamorphic buried hill condensate gas reservoir exhibits a highly compact matrix, leading to a rapid decline in bottom-hole pressure during initial production. The minimal difference between formation and saturation pressures results in severe retrograde condensation, with multiphase flow further increasing resistance. Conventional numerical simulations often overestimate reservoir energy supply due to their failure to account for this additional resistance, leading to inaccuracies in bottom-hole pressure predictions and gas–oil ratio during history matching. To address these challenges, this study conducted research on nonlinear numerical simulation for buried hill condensate gas reservoirs and established a method for calculating a multiphase pressure sweep range based on the well testing theory. By correcting and fitting the pressure propagation boundaries with numerical simulation, the nonlinear flow parameters applicable to the B6 gas field were inversed. This study revealed that conventional Darcy flow is inadequate for predicting pressure propagation boundaries and that it is possible to reasonably characterize the pressure sweep range through nonlinear flow. This approach resulted in an improvement in the accuracy of historical matching for bottom-hole pressure and gas–oil ratio, which improve the historical fitting accuracy to 85%, providing valuable insights for the development of similar reservoirs. [ABSTRACT FROM AUTHOR]

The prediction of the liquid build-up height in gas wells is a crucial aspect of reservoir development and is essential for the efficient execution of drainage and gas extraction operations. Excessive liquid accumulation can lead to well flooding and operational shutdowns, resulting in significant economic losses. To prevent such occurrences, accurate estimation of the liquid height in gas well tubing is necessary. However, existing petroleum engineering models face numerous challenges in predicting liquid height, including complex theoretical solution steps and reliance on fundamental well parameters and extensive empirical data. The paper proposes an innovative blend of the Crayfish Optimization Algorithm (COA) with the eXtreme Gradient Boosting (XGBoost) methodology to forecast the liquid loading heights in gas wells. The COA is employed to optimize eight hyperparameters of the XGBoost, including the number of trees, maximum depth, minimum child weight, learning rate, minimum loss reduction, subsample, L1 regularization, and L2 regularization. After fine-tuning the hyperparameters, the XGBoost undergoes a retraining process, followed by an evaluation. Through comparative analysis with actual measurements from 32 wells in a gas field as well as support vector regression (SVR), XGBoost, random forest (RF), and PLATA (which predict liquid volume in the tubing and annulus), the proposed COA–XGBoost demonstrates a high degree of alignment with the measured values. It provides the most accurate predictions, with a mean relative error of only 2.25%. Compared with the traditional XGBoost, the COA–XGBoost reduced the mean relative error in predicting gas well tubing liquid loading height by 32.63%. Compared with the previous PLATA, the proposed model achieved a 3.52% decrease in mean relative error, enabling more accurate assessment of the severity of liquid loading in gas wells. [ABSTRACT FROM AUTHOR]

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Fracture geometries and drainage radius are essential parameters for developing a reasonable development plan for a single fractured well. However, owing to fracture hits, the complex fracture geometries bring challenges for parameter estimations. This paper establishes a well testing based model for a finite-conductivity fractured vertical well in radial composite reservoirs with dynamic supply and fracture networks. Based on the successive steady-state method, the point source function, pressure superposition principle, and boundary element method are used to solve the reservoir model, and the methods of discrete fracture and pressure superposition are used to solve the fracture model. By introducing the rate-normalized pseudopressure and material balance time, the variable fluid flux is equivalent to the constant fluid flux. The drainage radius value and fracture geometries are solved by fitting the log-log curves of pressure response, and case studies are performed. The results show that the drainage radius increases with the increase of production time and finally tends to a specific value, and it has an excellent exponential relationship with time. Also, the fracture geometries of the typical well are multiple-radial fracture networks. Through the study of dynamic drainage radius, the controlled reserves of single wells in unconventional gas reservoirs can be better determined, and it can also provide a theoretical basis for fracture evaluation, productivity prediction, and enhanced recovery study of the same type of tight gas reservoir. [ABSTRACT FROM AUTHOR]

This paper focuses on phase and aggregation behavior for linear chains composed of blocks of hydrophilic and hydrophobic segments. Phase and conformational transitions of patterned chains are relevant for understanding liquid–liquid separation of biomolecular condensates, which play a prominent role in cellular biophysics and for surfactant and polymer applications. Previous studies of simple models for multiblock chains have shown that, depending on the sequence pattern and chain length, such systems can fall into one of two categories: displaying either phase separation or aggregation into finite-size clusters. The key new result of this paper is that both formation of finite-size aggregates and phase separation can be observed for certain chain architectures at appropriate conditions of temperature and concentration. For such systems, a bulk dense liquid condenses from a dilute phase that already contains multi-chain finite-size aggregates. The computational approach used in this study involves several distinct steps using histogram-reweighting grand canonical Monte Carlo simulations, which are described in some level of detail. [ABSTRACT FROM AUTHOR]

AbstractIn this paper, an excellent foaming formula for natural gas well deliquification was developed, which was based on the synthesized dodecyl ethylethanolamine (DEEA), commercially obtained cocamidopropyl betaine (CAPB) and sodium lauryl glutamate (SLG). The foaming properties and liquid unloading properties were studied, which showed that the optimal molar ratio of DEEA/CAPB/SLG ternary complex turned out to be 14:21:15. At a total concentration of 15 mM in the liquid phase, the optimal DEEA/CAPB/SLG mixture exhibited excellent foaming and liquid unloading capability at various conditions of methanol, condensate oil and salts contents and temperatures. At the methanol content of 45%, the foaming efficiency and liquid unloading efficiency of the DEEA/CAPB/SLG mixture were measured to be 100% and 25.5 ± 2.2%, respectively. When the condensate oil content was 10–30%, the liquid unloading efficiency ranged from 18.0 ± 2.1% to 25.0 ± 2.5%, which was much higher than that (8.3 ± 0.9%) obtained without condensate. The presence of salts retarded the performance of the DEEA/CAPB/SLG mixture, however, the addition of a chelating agent, trisodium nitrilotriacetic acid (NTA), to DEEA/CAPB/SLG could enhance the foaming efficiency and unloading performance at a salinity level of up to 41 × 104 mg/L, which might be the highest salt-resistant level of the gas well foaming mixture. The introduction of 10% methanol exhibited a positive effect on the DEEA/CAPB/SLG mixture’s foaming and liquid unloading performance against temperature (up to 90 °C). At 90 °C, the DEEA/CAPB/SLG foam could remove almost all the liquid from the column. [ABSTRACT FROM AUTHOR]