Articles de revues : « Water-gas-rock interaction »

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Pang, Zhonghe, Jie Li et Jiao Tian. « Noble gas geochemistry and chronology of groundwater in an active rift basin in central China ». E3S Web of Conferences 98 (2019) : 01040. http://dx.doi.org/10.1051/e3sconf/20199801040.

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Stable noble gas isotopes are excellent groundwater tracers. Radioactive noble gases are emerging new tools in the study of groundwater circulation dynamics. Among these, the 85Kr and 81Kr, and 39Ar have advanced very fast in recent years and exhibit strong potential in the reconstruction of the history of groundwater recharge and evolution in sedimentary basins at different scales. Here, we report the findings in groundwater circulation dynamics as relative to intensive water-rock interactions, heat transfer and He gas flux in Guanzhong Basin located in Xi’an, the geographical centre of China, which is a rift basin created by collision between the Eurasia and Indian plates, with active neotectonic activities. The recent technological breakthrough in noble gas isotope measurements, i.e. the atomic trap trace analysis (ATTA) techniques on Kr and Ar gas radionuclei, has revolutionized groundwater dating. Noble gas samples from shallow and deep wells to 3000 m depth have been collected to study isotope variations to reconstruct the history of groundwater recharge and understand the water-rock interaction processes. Stable isotopes of water show strong water-rock interaction in the formation, creating a strong positive O-isotope shift up to 10 ‰, a phenomenon that is rarely seen in a fairly low temperature environment. Analysis of 85Kr and 81Kr show groundwater ages up to 1.3 million years old along both North-South and a West-East cross sections, which offers strong evidence about the slow moving flow, strong water-rock interaction, rich geothermal resources as well as He gas resources.

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Pavlov, S. Kh. « Structural features and formation processes of a complex hydrogeochemical section in the Baikal rift zone ». Earth sciences and subsoil use 44, n^o 2 (17 juin 2021) : 159–66. http://dx.doi.org/10.21285/2686-9993-2021-44-2-159-166.

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The purpose of the work is to study the effect of organic matter on the formation of ion-salt and gas composition of nitrogen-methane and methane thermal water occurring in the sedimentary rocks of deep horizons of artesian basins. The object of research is the Tunka intermountain artesian basin of the Baikal rift zone and the Tungor gas and oil field of the Okhotsk-Sakhalin basin, in the deep horizons of which soda (inversion) low- and high-mineralized groundwater is common. The study combines the results of the traditional study of the composition of natural solutions and the quantitative research of physical and chemical interactions in the “water – rock” system conducted using the Selector software package according to the degree of the hydrogeochemical process, which was set by the value of the rock/water ratio. Chemically pure water and rocks of medium chemical composition were used in interaction. With the use of physicochemical modeling the formation of thermal water composition in sedimentary rocks depending on the interaction degree between water and rock and the amount of organic matter was unravelled. As a result, it was determined that the organic matter present in the rock has the dominant influence on the intensity of the hydrogeochemical process determining the amount of mineralization, the ratio of components, and the amount of methane, nitrogen, and carbon dioxide produced. The correspondent compositions of the model and natural solutions showed the possibility to form low- and high-mineralized sodium bicarbonate groundwater of different gas-saturation degree in the conditions of deep horizons of sedimentary basins due to the internal reserves of the “water – rock” system not involving any components from external sources.

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Krykovskyi, Oleksandr, Viktoriia Krykovska et Serhii Skipochka. « Interaction of rock-bolt supports while weak rock reinforcing by means of injection rock bolts ». Mining of Mineral Deposits 15, n^o 4 (décembre 2021) : 8–14. http://dx.doi.org/10.33271/mining15.04.008.

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Purpose is to analyze changes in shape and dimensions of a rock mass area, fortified with the help of a polymer, depending upon the density of injection rock bolts as well as the value of initial permeability of enclosing rocks to substantiate optimum process solutions to support roofs within the unstable rocks and protect mine workings against water inflow and gas emission. Methods. Numerical modeling method for coupled processes of rock mass strain and filtration of liquid components of a polymer has been applied. The model is based upon fundamental ideas of mechanics of solids and filtration theory. The problem has been solved using a finite element method. Its solution took into consideration both the initial permeability and the permeability stipulated by mine working driving, injection time of reagents and their polymerization, and effect of po-lymer foaming in the process of mixing of its components. Changes in physicomechanical and filtration characteristics of rock mass during polymer hardening were simulated. It has been taken into consideration that a metal delivery pipe starts operating as a reinforcing support element only after the polymer hardening. Findings. If three and five injection rock bolts are installed within a mine working section then stresses, permeability coefficients, pressure of liquid polymeric composition, and geometry of the fortified area of rock mass have been calculated. It has been shown that rock bolt location is quite important to form a rock-bolt arch. It has been demonstrated for the assumed conditions that if five injection rock bolts are installed within the mine working roof then close interaction between rock-bolt supports takes place; moreover, the integral arch is formed within the mine working roof. Originality. Dependence of change in the polymer reinforced area upon a value of initial permeability of enclosing rocks has been derived. It has been shown that in terms of low values of initial permeability, geometry of rock-bolt supports as well as its size is identified only by means of a value of the unloaded zone around the mine working. In this context, initial permeabi-lity increase results in the enlarged diameter of the reinforced rock mass area in the neighbourhood of the injection rock bolt. Practical implications. The findings are recommended to be applied while improving a method to support the mine working roof and decrease water inflow as well as gas emission from the rocks, being undermined, into the working.

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KURODA, Yoshihiro, Yasuhiro YAMADA, Akira UEDA, Toshifumi MATSUOKA et Norikazu YAMADA. « Experimental research of plagioclase (rock)-gas-water interaction at hydrothermal conditions for CO2 mineralization ». Japanese Magazine of Mineralogical and Petrological Sciences 38, n^o 4 (2009) : 111–21. http://dx.doi.org/10.2465/gkk.38.111.

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Popov, S. N., et S. E. Chernyshov. « Coupled mechanical and chemical and geodynamic problems arising during the operation of underground gas storage facilities with a mixture of hydrogen and methane ». Actual Problems of Oil and Gas, n^o 30 (21 décembre 2020) : 32–43. http://dx.doi.org/10.29222/ipng.2078-5712.2020-30.art4.

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The article discusses the features of the operation of underground gas storage facilities with the injection of a mixture of hydrogen and methane. It is shown that when such a mixture is injected, its chemical interaction with formation water and rock can occur, which leads to variations in the permeability, porosity and physical-mechanical properties of the reservoir. The consequence of such interaction may be unforeseen geomechanical and geodynamic processes that negatively affect the operation of underground gas storage facilities.

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Huang, Tianming, Yiman Li, Zhonghe Pang, Yingchun Wang et Shuo Yang. « Groundwater Baseline Water Quality in a Shale Gas Exploration Site and Fracturing Fluid - Shale Rock Interaction ». Procedia Earth and Planetary Science 17 (2017) : 638–41. http://dx.doi.org/10.1016/j.proeps.2016.12.171.

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Guo, Xiaobo, Libin Zhao, Wei Han, Longfei Zhou, Zhilong Huang, Xiongwei Sun, Xuejun Yang, Tonghui Zhang et Chenglin Zhang. « Geochemistry of Formation Water and Implications for Ultradeep Tight Sandstone of DK Gas Field in Kuqa Depression ». Geofluids 2022 (18 novembre 2022) : 1–14. http://dx.doi.org/10.1155/2022/6514733.

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Formation water is produced during gas well production, which can seriously affect gas well productivity, especially in deep and ultradeep tight sandstone gas reservoirs. In this paper, we have studied the formation water production and geochemical properties of the ultradeep tight sandstone gas reservoir in the Cretaceous Bashijiqike Formation of the DK gas field in the Kuqa Depression. The results indicate that the formation water can be classified as condensate water, gas-water transition zone water, mixed water, and isolated formation water, all of which are acidic and of CaCl2 type, with increasing salinity or chloride ion content. Sodium/chloride ratio (ρNa+/ρCl-), metamorphic coefficient (ρ(Cl--Na+)/ρ(Mg2+)), desulfurization coefficient ( 100 × ρ S O 4 2 − / ρ C l − ), and trace elements concentration parameters show that the formation water was formed in a closed and reductive environment and experienced strong water-rock interaction. The formation water may have been influenced by early seawater, but it is not significant and is more likely to have been influenced by water seepage from the overlying gypsum strata. The Sr, H, and O isotopes reveal that the different types of formation water have good homology and are not affected by atmospheric precipitation, which is propitious to the preservation of natural gas.

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Hu, Yong, Jiong Wei, Tao Li, Weiwei Zhu, Wenbo Gong, Dong Hui et Moran Wang. « Numerical Simulation of Fluid Flow in Carbonate Rocks Based on Digital Rock Technology ». Energies 15, n^o 10 (19 mai 2022) : 3748. http://dx.doi.org/10.3390/en15103748.

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Strong heterogeneity, low matrix permeability, and complex oil–water interaction make the fluid flow in carbonate rocks extremely complicated. In this study, we quantitatively characterize and simulate single-phase and multiphase flows with multiscale pore–vug–fracture structures involved in the carbonate reservoir developments. The main studies and conclusions include: (i) The CT technology is utilized to characterize the pores, fractures, and vugs of carbonate cores at multiple scales. It is found that even if the CT resolution reaches 0.5 μm, the pores of the core are still unconnected as a network, indicating that the carbonate matrix is particularly tight. The existence of fractures can increase the effective permeability, and even poorly connected fractures can significantly increase the permeability because it reduces the flow distance through the less permeable matrix. (ii) A numerical model of low-porosity strongly heterogeneous carbonate rocks was constructed based on digital image processing. Simulations of single-phase fluid flow under reservoir conditions were conducted, and the effects of surrounding pressure, pore pressure, and core size on the single-phase flow were investigated. Due to the strong heterogeneity of carbonate rocks, the pores, vugs, and fractures cause local preferential flow and disturbance within the core, which significantly affects the fluid flow path and the pressure distribution in the core. The overall permeability is a composite representation of the permeability of numerous microelements in the specimen. Permeability increases with an increasing pore pressure, and it decreases with increasing circumferential pressure. (iii) The gas–water two-phase flow model of a low-porosity strongly heterogeneous carbonate rock was established based on digital image processing. The variation law of the two-phase outlet flow velocity with the inlet gas pressure and the movement law of the two-phase interface of carbonate rock samples were obtained. Under certain surrounding pressure, the outlet gas velocity is larger than the outlet water velocity; with the increase of the inlet gas pressure, the pore space occupied by the gas phase in the rock becomes larger. With the increase of the surrounding pressure, the velocities of both outlet gas and water decrease. As the sample size decreases, the velocities of both outlet gas and water increase.

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Zhang, Jiyuan, Bin Zhang, Shiqian Xu, Qihong Feng, Xianmin Zhang et Derek Elsworth. « Interpretation of Gas/Water Relative Permeability of Coal Using the Hybrid Bayesian-Assisted History Matching : New Insights ». Energies 14, n^o 3 (26 janvier 2021) : 626. http://dx.doi.org/10.3390/en14030626.

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The relative permeability of coal to gas and water exerts a profound influence on fluid transport in coal seams in both primary and enhanced coalbed methane (ECBM) recovery processes where multiphase flow occurs. Unsteady-state core-flooding tests interpreted by the Johnson–Bossler–Naumann (JBN) method are commonly used to obtain the relative permeability of coal. However, the JBN method fails to capture multiple gas–water–coal interaction mechanisms, which inevitably results in inaccurate estimations of relative permeability. This paper proposes an improved assisted history matching framework using the Bayesian adaptive direct search (BADS) algorithm to interpret the relative permeability of coal from unsteady-state flooding test data. The validation results show that the BADS algorithm is significantly faster than previous algorithms in terms of convergence speed. The proposed method can accurately reproduce the true relative permeability curves without a presumption of the endpoint saturations given a small end-effect number of <0.56. As a comparison, the routine JBN method produces abnormal interpretation results (with the estimated connate water saturation ≈33% higher than and the endpoint water/gas relative permeability only ≈0.02 of the true value) under comparable conditions. The proposed framework is a promising computationally effective alternative to the JBN method to accurately derive relative permeability relations for gas–water–coal systems with multiple fluid–rock interaction mechanisms.

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Uliasz-Misiak, Barbara, et Katarzyna Chruszcz-Lipska. « Hydrogeochemical Aspects Associated with the Mixing of Formation Waters Injected Into the Hydrocarbon Reservoir ». Gospodarka Surowcami Mineralnymi 33, n^o 2 (27 juin 2017) : 69–80. http://dx.doi.org/10.1515/gospo-2017-0017.

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Abstract Formation waters extracted with crude oil and natural gas, due to their amount and chemical composition can be a problem for petroleum companies operating hydrocarbon deposits. On average, the world generates 2 to 3 times more water than oil. On average, the world generates 2 to 3 times more water than crude oil. T he amount of extracted water increases with the time of exploitation of the deposit, in the case of deposits at the final stage of depletion, the amount of extracted water is 5 to 8 times bigger than petroleum. Formation waters from hydrocarbons deposits are usually the highly mineralized brines. Large quantities of highly mineralized waters extracted with crude oil and gas are disposed of in various ways or neutralized. T he most common way of disposing of these waters is by injecting them into rock mass. As a result of injection of reservoir waters into hydrocarbon deposits, the waters interact with the storage formations. In these formations, there may be numerous reactions of mineral water with the rock environment. T he injection of reservoir waters will also cause mixing of waters that can disturb the state of thermodynamic equilibrium and will alter the chemistry of these waters. It was analyzed by the geochemical modeling of the interaction of the reservoir waters of Przemyśl natural gas field. Using the PHREEQC program, the chemical reactions related to the mixing of reservoir waters of different chemical types have been studied. It has been found that is possible to precipitation appropriated minerals as a result of mixing water with different chemical composition.

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Aguilera, Felipe, Susana Layana, Augusto Rodríguez-Díaz, Cristóbal González, Julio Cortés et Manuel Inostroza. « Hydrothermal alteration, fumarolic deposits and fluids from Lastarria Volcanic Complex : A multidisciplinary study ». Andean Geology 43, n^o 2 (20 mai 2016) : 166. http://dx.doi.org/10.5027/andgeov43n2-a02.

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A multidisciplinary study that includes processing of Landsat ETM+ satellite images, chemistry of gas condensed, mineralogy and chemistry of fumarolic deposits, and fluid inclusion data from native sulphur deposits, has been carried out in the Lastarria Volcanic Complex (LVC) with the objective to determine the distribution and characteristics of hydrothermal alteration zones and to establish the relations between gas chemistry and fumarolic deposits. Satellite image processing shows the presence of four hydrothermal alteration zones, characterized by a mineral assemblage constituted mainly by clay minerals, alunite, iron oxides, and more subordinated ferrous minerals and goethite. Hydrothermal alteration zones present in the Lastarria sensu stricto volcano are directly related to the recent fumarolic activity. Geochemistry of fumarolic gas condensed, obtained from two fumaroles at temperatures between 328 and 320 °C, has allowed detecting 37 diverse elements corresponding to halogens, chalcophiles, siderophiles, alkali metals, alkali earth metals and Rare Earth Elements (REE), with concentrations that vary widely between 5,620 ppm (chlorine) and 0.01 ppm (Mo, Ag, Sn, Pb, Se, Mg and Cr). Logarithm of Enrichment Factor (log EFi) for each element present values between 6.35 (iodine) and<1 (K, Na, Ca, Fe and Al). Those elements are originated primarily from a magmatic source, whereas at shallow level a hydrothermal source contributes typical rock-related elements, which are leached from the wall rock by a strong interaction with hyperacid fluids. Mostly of elements detected are transported to the surface in the fumarolic emissions as gaseous species, while very few elements (Mg, Ca and Al) are transported in silicate aerosols. A wide spectrum of minerals are present in the fumarolic deposits, which are constituted by sublimates and incrustations, and the main minerals phases are distributed in six mineral families, corresponding to sulphates, hydrated sulphates, sulphides, halides, carbonates, silicates and native element minerals. The sublimate/incrustation minerals are dominated by the presence of sulphate, sulphur, chlorine and diverse rock-related elements, which are formed by processes that include a. oxidation of gaseous phase; b. strong rock-fluid interaction; c. dissolution of silicate minerals and volcanic glass; d. gas-water interaction; e. deposition/precipitation of saline bearing minerals; f. oxidation of sublimates/incrustations to form secondary minerals and g. remobilization of sulphur deposits by meteoric water. Despite that sublimate/ incrustation minerals are dominated by rock-related elements, its chemistry shows high contents of high-volatile elements as As, Sb, Cd, among others. Fluid inclusions studies carried out in thin pseudobanded native sulphur from fumarolic deposits, by use of Raman and infrared spectroscopy combined with microthermometry analyses, provided evidence of H2O, CO2, H2S, SO4, COS bearing fluids, homogenization temperatures around 110 °C and salinities varying from ~11 to ~7 wt% NaCl. Fluid inclusions data show also evidences of a mixing (dilution) between hot and saline fluid with a cooler fluid (cold groundwater or a steam-heated water) as the main process.

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Tantciura, Sergei, Yangyang Qiao et Pål Ø. Andersen. « Simulation of Counter-Current Spontaneous Imbibition Based on Momentum Equations with Viscous Coupling, Brinkman Terms and Compressible Fluids ». Transport in Porous Media 141, n^o 1 (3 novembre 2021) : 49–85. http://dx.doi.org/10.1007/s11242-021-01709-9.

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AbstractA numerical model is investigated representing counter-current spontaneous imbibition of water to displace oil or gas from a core plug. The model is based on mass and momentum conservation equations in the framework of the theory of mixtures. We extend a previous imbibition model that included fluid–rock friction and fluid–fluid drag interaction (viscous coupling) by including fluid compressibility and Brinkman viscous terms. Gas compressibility accelerated recovery due to gas expansion from high initial non-wetting pressure to ambient pressure at typical lab conditions. Gas compressibility gave a recovery profile with two characteristic linear sections against square root of time which could match tight rock literature experiments. Brinkman terms decelerated recovery and delayed onset of imbibition. Experiments where this was prominent were successfully matched. Both compressibility and Brinkman terms caused recovery deviation from classical linearity with the square root of time. Scaling yielded dimensionless numbers when Brinkman term effects were significant.Article Highlights Spontaneous imbibition with viscous coupling, compressibility and Brinkman terms. Viscous coupling reduces spontaneous imbibition rate by fluid–fluid friction. Brinkman terms delay early recovery and explain seen delayed onset of imbibition. Gas compressibility accelerates recovery and can be significant at lab conditions. Gas compressibility gives recovery with two root of time lines as seen for shale.

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Bonamico, Margherita, Paola Tuccimei, Lucia Mastrorillo et Roberto Mazza. « Freshwater–Saltwater Interactions in a Multilayer Coastal Aquifer (Ostia Antica Archaeological Park, Central ITALY) ». Water 13, n^o 13 (4 juillet 2021) : 1866. http://dx.doi.org/10.3390/w13131866.

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An integrated research approach consisting of hydrogeologic and geochemical methods was applied to a coastal aquifer in the Ostia Antica archaeological park, Roma, Italy, to describe freshwater–saltwater interactions. The archaeological park of Ostia Antica is located on the left bank of the Tevere River delta which developed on a morphologically depressed area. The water monitoring program included the installation of multiparametric probes in some wells inside the archaeological area, with continuous measurement of temperature, electrical conductivity, and water table level. Field surveys, water sampling, and major elements and bromide analyses were carried out on a seasonal basis in 2016. In order to understand the detailed stratigraphic setting of the area, three surface boreholes were accomplished. Two distinct circulations were identified during the dry season, with local interaction in the rainy period: an upper one within the archaeological cover, less saline and with recharge inland; and a deeper one in the alluvial materials of Tevere River, affected by salinization. Oxygen and carbon isotopic signature of calcite in the sediments extracted from the boreholes, along with major elements and Br concentration, allowed us to recognize the sources of salinity (mainly, local interaction with Roman salt pans and agricultural practices) and the processes of gas–water–rock interaction occurring in the area. All these inferences were confirmed and strengthened by PCA analysis of physicochemical data of groundwater.

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Heine, Florian, Kai Zosseder et Florian Einsiedl. « Hydrochemical Zoning and Chemical Evolution of the Deep Upper Jurassic Thermal Groundwater Reservoir Using Water Chemical and Environmental Isotope Data ». Water 13, n^o 9 (22 avril 2021) : 1162. http://dx.doi.org/10.3390/w13091162.

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A comprehensive hydrogeological understanding of the deep Upper Jurassic carbonate aquifer, which represents an important geothermal reservoir in the South German Molasse Basin (SGMB), is crucial for improved and sustainable groundwater resource management. Water chemical data and environmental isotope analyses of δD, δ18O and 87Sr/86Sr were obtained from groundwater of 24 deep Upper Jurassic geothermal wells and coupled with a few analyses of noble gases (3He/4He, 40Ar/36Ar) and noble gas infiltration temperatures. Hierarchical cluster analysis revealed three major water types and allowed a hydrochemical zoning of the SGMB, while exploratory factor analyses identified the hydrogeological processes affecting the water chemical composition of the thermal water. Water types 1 and 2 are of Na-[Ca]-HCO3-Cl type, lowly mineralised and have been recharged under meteoric cold climate conditions. Both water types show 87Sr/86Sr signatures, stable water isotopes values and calculated apparent mean residence times, which suggest minor water-rock interaction within a hydraulically active flow system of the Northeastern and Southeastern Central Molasse Basin. This thermal groundwater have been most likely subglacially recharged in the south of the SGMB in close proximity to the Bavarian Alps with a delineated northwards flow direction. Highly mineralised groundwater of water type 3 (Na-Cl-HCO3 and Na-Cl) occurs in the Eastern Central Molasse Basin. In contrast to water types 1 and 2, this water type shows substantial water-rock interaction with terrestrial sediments and increasing 40Ar/36Ar ratios, which may also imply a hydraulic exchange with fossil formation waters of overlying Tertiary sediments.

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Amadu, Mumuni, et Adango Miadonye. « Thermodynamic Computations for Ion Exchange and Surface Protonation Reactions and the Implications for Acid Induced Contact Angle Evolution in Silica Rich Saline Aquifer Systems ». International Journal of Chemistry 9, n^o 4 (26 octobre 2017) : 98. http://dx.doi.org/10.5539/ijc.v9n4p98.

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To reduce current high concentrations of anthropogenic greenhouse gases in the atmosphere to levels stipulated by the Intergovernmental Panel on Climate Change, geological sequestration has been universally proposed. On the basis of cost analysis and global availability, deep saline aquifers are the prime targets for most proposed commercial and pilot scale projects.While the geological storage of anthropogenic carbon dioxide is expected to mitigate global warming, the technical aspects of the injection deserve to be considered for efficient injection projects. The water rock interaction phenomenon occurs due to carbonic acid generation which causes surface protonation reactions and has the potential to decrease water wettability of the system leading to enhanced water mobility and efficient gas injection. Therefore, for a saline aquifer rock with minerals capable of ion exchange reactions that consume solution protons, the wettability of such a system is likely to be preserved leading to reduced water mobility and poor gas injection. Generally, the extents to which surface protonation and ion exchange reactions occur depend on the free energy change of the reaction.In this paper, we have carried out thermodynamic computations for the free energies of surface protonation and ion exchange reactions. Based on the values of computed free energies, which show that ion exchange reactions have lower free energies, we have discussed the wettability implications for geological storage in silica rich saline aquifer systems.

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Pinilla, Andres, Milan Stanko, Miguel Asuaje et Nicolás Ratkovich. « In-Depth Understanding of ICD Completion Technology Working Principle ». Processes 10, n^o 8 (28 juillet 2022) : 1493. http://dx.doi.org/10.3390/pr10081493.

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The rate-controlled production (RCP) inflow control devices (ICDs) are valves placed in the lower completion of oil and gas wells, capable of autonomously controlling the reservoir inflow. This completion technology self-regulates the inflow of undesired phases, such as water, by choking the flow after the breakthrough event, thus improving the recovery factor and reducing water production. In this context, this article presents a numerical study that describes the working principle of RCP valves based on a computational fluid dynamics (CFD) analysis. The numerical models are based on the conservation equations of fluid flow, the volume of fluid (VOF) multiphase flow model, and the dynamic fluid body interaction (DFBI) model to simulate the valve’s movement caused by its interaction with the flow. This study demonstrates the possibility of studying RCP valves alone or coupled with the whole completion assembly and reservoir rock. The difference in the valve efficiency after considering the entire completion assembly and reservoir rock is 19% less compared with the stand-alone analysis of the valve. Finally, this study provides a deep understanding of the fluid dynamics near the wellbore, the completion assembly, and the RCP valves, along with its chocking, which could be helpful to future researchers interested in improving multiphase flow efficiency in subsurface processes.

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Shyrin, Leonid, Rostislav Yehorchenko et Мykola Sergienko. « SPECIFICS OF DIAGNOSTICS OF TECHNICAL CONDITION OF TRANSPORT AND TECHNOLOGICAL SYSTEM “MINING GAS PIPELINE – MINE WORKING” ». Geoengineering, n^o 6 (30 novembre 2021) : 28–37. http://dx.doi.org/10.20535/2707-2096.6.2021.241823.

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The purpose of the paper is to analyze a deformation mechanism of the mine degassing pipelines to forecast their spatial changes in terms of intensification of underground mining of coal-gas seams. Methodology. The paper deals with expert assessment of the available approaches to diagnostics of technical condition of mine degassing pipelines, which are constructed within the in-seam underground mine workings with the floor rocks prone to heaving. The results of scheduled surveying measurements of technical condition of in-seam development workings have helped identify the potentially hazardous zones of rock mass deformation and indices of changes in spatial location of section degassing pipelines mounted in those mine workings. To determine the operating modes of a degassing pipeline under such operating conditions, a computer model of interaction of the elements of transport-technological system “mine gas pipeline – mine working” has been developed Findings. Diagnostics of technical conditions of the mine gas transmission lines and examination of their dismantled components have helped understand that deflections, mainly resulting in water accumulation zones, intensive corrosion of internal pipe walls, and mechanical depositions of coal and rock dust take place right within the flange connection areas. Formation of such zones is argued by health of the degassing pipeline as well as mine air inflow. Availability of internal corrosion, water accumulations, and mine air inflow decreases substantially capacity of the underground gas transmission line inclusive of qualitative characteristics of the captured methane-air mixture and efficiency of MDS on the whole. Originality. New approaches to diagnostics of technical condition of mine degassing gas pipeline in difficult mining and geological conditions of development of gas-bearing coal seams are substantiated and it is offered to consider indicators of their functioning as interacting in space and time transport-technological system "mine gas pipeline - mining". Practical implications. The operational parameters of mine degassing systems notes that the equipment performance with the least underpressure losses created by vacuum pipes requires that the degassing pipeline should have minimum hydraulic resistance of the gas transmission network. Pipeline aeration from the mine workings and water accumulations should be prevented by means of qualitative hermetic sealing of its flange connections as well as the pipeline straightness with the corresponding pitches. Consequently, the basic requirements for operating mine degassing pipelines involve their design profile, tightness of flange connections of pipes as well as operative control of the facility health.

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Zhang, Qiang, Xiaochun Li, Bing Bai, Shaobin Hu et Lu Shi. « Effect of Pore Fluid Pressure on the Normal Deformation of a Matched Granite Joint ». Processes 6, n^o 8 (1 août 2018) : 107. http://dx.doi.org/10.3390/pr6080107.

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The influence of pore fluid pressure on the normal deformation behaviors of joints is vital for understanding the interaction between hydraulic and mechanical processes of joints. The effect of pore fluid pressure on the normal deformation of a granite matched joint was investigated by laboratory experiments. Experimental results indicate pore fluid pressure significantly affects the normal deformation of jointed sample, and the relative normal deformation of jointed sample during fluid injection consists of the opening of the joint and the dilation of host rock. The action of pore fluid pressure on the joint follows the Terzaghi’s effective stress law. The normal deformation of the joint can be well quantitated by the generalized exponential model. The relative normal deformation of host rock during fluid injection would have a linear relationship with pore fluid pressure, and if affected by gas is more pronounced than water.

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Zhang, Liankai, Xiaoqun Qin, Pengyu Liu, Qibo Huang, Funing Lan et Hongbing Ji. « Estimation of carbon sink fluxes in the Pearl River basin (China) based on a water–rock–gas–organism interaction model ». Environmental Earth Sciences 74, n^o 2 (22 octobre 2014) : 945–52. http://dx.doi.org/10.1007/s12665-014-3788-2.

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Stotler, Randy L., Matthew F. Kirk, K. David Newell, Robert H. Goldstein, Shaun K. Frape et Rhys Gwynne. « Stable Bromine Isotopic Composition of Coal Bed Methane (CBM) Produced Water, the Occurrence of Enriched 81Br, and Implications for Fluid Flow in the Midcontinent, USA ». Minerals 11, n^o 4 (30 mars 2021) : 358. http://dx.doi.org/10.3390/min11040358.

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This study characterizes the δ37Cl, δ81Br, and 87Sr/86Sr of coal bed methane produced fluids from Pennsylvanian Cherokee Group coals of the Cherokee Basin in southeast Kansas, USA. The δ37Cl, δ81Br, and 87Sr/86Sr values range between −0.81 and +0.68‰ (SMOC), −0.63 and +3.17‰ (SMOB), and 0.70880 and 0.71109, respectively. A large percentage of samples have δ81Br above +2.00‰. Two fluid groups were identified on the basis of K/Br, Br/Cl, and Ca/Mg ratios, temperature, He content, δ2H, δ18O, δ81Br, and 87Sr/86Sr. Both fluid groups have geochemical similarities to fluids in Cambrian, Ordovician, and Mississippian units. Lower salinity and higher temperature fluids from deeper units are leaking up into the Cherokee Group and mixing with a higher salinity fluid with higher δ81Br and more radiogenic 87Sr/86Sr. Variation in δ37Cl indicates an unknown process other than mixing is affecting the salinity. This process does not appear to be related to evaporation, evaporite dissolution, or diffusion. Insufficient data are available to evaluate halide–gas or water–rock interaction, but halide–gas interactions are not likely a significant contributor to high δ81Br. Rather, interactions with organically bound bromine and soluble chloride within the coal could have the strongest effect on δ37Cl and δ81Br values.

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Marín-Camacho, Pedro, Fernando Velasco-Tapia, Rubén Bernard-Romero, Bodo Weber et Reneé González-Guzmán. « New geochemical evidence constraining the water-rock-gas interaction on geothermal fluids of the Querétaro Graben, northern Trans-Mexican Volcanic Belt ». Journal of South American Earth Sciences 114 (mars 2022) : 103702. http://dx.doi.org/10.1016/j.jsames.2021.103702.

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Li, Guangquan, Pengfei Zhang et Jingshu Sun. « A new model describing the interaction between fluid pressure wave in pores and P-wave in rock matrix ». GEOPHYSICS 82, n^o 4 (1 juillet 2017) : MR105—MR109. http://dx.doi.org/10.1190/geo2016-0285.1.

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The interaction between seismic waves in rocks and fluid pressure in pores remains one of the most challenging topics in seismic exploration. A perturbation technique is used to develop a new model to describe the propagation of fluid pressure in pores associated with P-waves in the rock matrix. The basic idea is to approximate classification of waves in saturated rocks into two orders. The first order is a dominant P-wave in the matrix, and the second order is a companion fluid wave induced by the first-order wave. This approach is innovative and advantageous in that the complex interactions of stress between the matrix and fluid are decoupled and the mathematical solutions become easy to seek for. The fluid pressure wave is analyzed by a 1D plane wave ignoring the Poisson’s effect. Parameterization of the model using sandstone saturated with water results in the conclusion that the fluid wave has an amplitude one order of magnitude smaller than the matrix wave and the two waves have a very slight phase difference. We have also evaluated the potential application of our model to shale gas and shale oil.

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Zhang, Nan, Wei Liu, Yun Zhang, Pengfei Shan et Xilin Shi. « Microscopic Pore Structure of Surrounding Rock for Underground Strategic Petroleum Reserve (SPR) Caverns in Bedded Rock Salt ». Energies 13, n^o 7 (27 mars 2020) : 1565. http://dx.doi.org/10.3390/en13071565.

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Using salt caverns for an underground strategic petroleum reserve (SPR) is considered as an ideal approach due to the excellent characteristics of low porosity, low permeability, self-healing of damage, and strong plastic deformation ability of rock salt. Salt deposits in China are mostly layered rock salt structures, with the characteristics of many interlayers, bringing great challenges for the construction of SPR facilities. Studying the microscopic pore characteristics of the rock surrounding SPR salt caverns in different environments (with brine and crude oil erosion) is necessary because the essence of mechanical and permeability characteristics is the macroscopic embodiment of the microscopic pore structure. In this paper, XRD tests and SEM tests are carried out to determine the physical properties of storage media and surrounding rock. Gas adsorption tests and mercury intrusion tests are carried out to analyze the microscopic pore structure, specific surface area variation and total aperture distribution characteristics of SPR salt cavern host rock. Results show that: (1) Large numbers of cores in interlayer and caprock may provide favorable channels for the leakage of high-pressure crude oil and brine. (2) The blockage of pores by macromolecular organic matter (colloid and asphaltene) in crude oil will not significantly change the structural characteristics of the rock skeleton, which is beneficial to the long-term operation of the SPR salt cavern. (3) The water–rock interaction will bring obvious changes in the micro-pore structure of rock and increase the leakage risk of the storage medium. The results can provide theoretical bases and methods for the tightness analysis of China’s first underground SPR salt cavern.

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Kusakabe, Minoru, Keisuke Nagao, Takeshi Ohba, Jung Hun Seo, Sung-Hyun Park, Jong Ik Lee et Byong-Kwon Park. « Noble gas and stable isotope geochemistry of thermal fluids from Deception Island, Antarctica ». Antarctic Science 21, n^o 3 (11 février 2009) : 255–67. http://dx.doi.org/10.1017/s0954102009001783.

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AbstractNew stable isotope and noble gas data obtained from fumarolic and bubbling gases and hot spring waters sampled from Deception Island, Antarctica, were analysed to constrain the geochemical features of the island's active hydrothermal system and magmatism in the Bransfield back-arc basin. The 3He/4He ratios of the gases (< 9.8 × 10-6), which are slightly lower than typical MORB values, suggest that the Deception Island magma was generated in the mantle wedge of a MORB-type source but the signature was influenced by the addition of radiogenic 4He derived from subducted components in the former Phoenix Plate. The N2/He ratios of fumarolic gas are higher than those of typical mantle-derived gases suggesting that N2 was added during decomposition of sediments in the subducting slab. The δ13C values of -5 to -6‰ for CO2 also indicate degassing from a MORB-type mantle source. The H2/Ar- and SiO2 geothermometers indicate that the temperatures in the hydrothermal system below Deception Island range from ~150°C to ~300°C. The δD and δ18O values measured from fumarolic gas and hot spring waters do not indicate any contribution of magmatic water to the samples. The major ionic components and δD-δ18O-δ34S values indicate that hot spring waters are a mixture of local meteoric water and seawater. Mn and SiO2 in spring waters were enriched relative to seawater reflecting water-rock interaction at depth.

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Li, Lei, Xue Zhang, Jiahui Liu, Qiuheng Xie, Xiaomei Zhou, Jianyang Zheng et Yuliang Su. « Research Progress and Prospect of Carbon Dioxide Utilization and Storage Based on Unconventional Oil and Gas Development ». Energies 15, n^o 24 (11 décembre 2022) : 9383. http://dx.doi.org/10.3390/en15249383.

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Energy security and the reduction of greenhouse gases such as carbon dioxide are two major crises facing the world today. Using carbon dioxide to develop unconventional oil and gas resources is a positive way to reduce greenhouse gas emissions, which can significantly alleviate global energy security issues. This study systematically introduces the prerequisites for CO2 to extract crude oil and CO2 to be safely and effectively stored. Under high temperature and high pressure, the rock properties of deep reservoirs are completely different from those of atmospheric conditions in the two-phase porous media environment of crude oil and high salinity formation water. The research progress on the phase behavior, mutual solubility, CO2 storage potential and mechanism between supercritical CO2 and crude oil, formation water and reservoir are reviewed in detail. In addition, CO2 leakage will inevitably occur during long-term geological storage, the proper estimation and evaluation of the risk and establishment of corresponding sealing methods are the way forward for CO2 geological storage. By systematically elaborating the nature, advantages and disadvantages of fluid–fluid, fluid–solid interaction and geological integrity destruction mechanism, the directions in which several key problems should be solved were pointed out.

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Herbort, O., P. Woitke, Ch Helling et A. Zerkle. « The atmospheres of rocky exoplanets ». Astronomy & ; Astrophysics 636 (avril 2020) : A71. http://dx.doi.org/10.1051/0004-6361/201936614.

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Context. Little is known about the interaction between atmospheres and crusts of exoplanets so far, but future space missions and ground-based instruments are expected to detect molecular features in the spectra of hot rocky exoplanets. Aims. We aim to understand the composition of the gas in an exoplanet atmosphere which is in equilibrium with a planetary crust. Methods. The molecular composition of the gas above a surface made of a mixture of solid and liquid materials was determined by assuming phase equilibrium for given pressure, temperature, and element abundances. We study total element abundances that represent different parts of the Earth’s crust (continental crust, bulk silicate Earth, mid oceanic ridge basalt), CI chondrites and abundances measured in polluted white dwarfs. Results. For temperatures between ~600 and ~3500 K, the near-crust atmospheres of all considered total element abundances are mainly composed of H2O, CO2, and SO2 and in some cases of O2 and H2. For temperatures ≲500 K, only N2-rich or CH4-rich atmospheres remain. For ≳3500 K, the atmospheric gas is mainly composed of atoms (O, Na, Mg, and Fe), metal oxides (SiO, NaO, MgO, CaO, AlO, and FeO), and some metal hydroxides (KOH and NaOH). The inclusion of phyllosilicates as potential condensed species is crucial for lower temperatures, as they can remove water from the gas phase below about 700 K and inhibit the presence of liquid water. Conclusions. Measurements of the atmospheric composition could, in principle, characterise the rock composition of exoplanet crusts. H2O, O2 and CH4 are natural products from the outgassing of different kinds of rocks that had time to equilibrate. These are discussed as biomarkers, but they do emerge naturally as a result of the thermodynamic interaction between the crust and atmosphere. Only the simultaneous detection of all three molecules might be a sufficient biosignature, as it is inconsistent with chemical equilibrium.

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Carcione, José M., Hans B. Helle et Nam H. Pham. « White's model for wave propagation in partially saturated rocks : Comparison with poroelastic numerical experiments ». GEOPHYSICS 68, n^o 4 (juillet 2003) : 1389–98. http://dx.doi.org/10.1190/1.1598132.

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We use a poroelastic modeling algorithm to compute numerical experiments of wave propagation in White's partial saturation model. The results are then compared to the theoretical predictions. The model consists of a homogeneous sandstone saturated with brine and spherical gas pockets. White's theory predicts a relaxation mechanism, due to pressure equilibration, causing attenuation and velocity dispersion of the wavefield. We vary gas saturation either by increasing the radius of the gas pocket or by increasing the density of gas bubbles. Despite that the modeling is two dimensional and interaction between the gas pockets is neglected in White's model, the numerical results show the trends predicted by the theory. In particular, we observe a similar increase in velocity at high frequencies (and low permeabilities). Furthermore, the behavior of the attenuation peaks versus water saturation and frequency is similar to that of White's model. The modeling results show more dissipation and higher velocities than White's model due to multiple scattering and local fluid‐flow effects. The conversion of fast P‐wave energy into dissipating slow waves at the patches is the main mechanism of attenuation. Differential motion between the rock skeleton and the fluids is highly enhanced by the presence of fluid/fluid interfaces and pressure gradients generated through them.

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Inostroza, Manuel, Séverine Moune, Roberto Moretti, Magali Bonifacie, Vincent Robert, Arnaud Burtin et Elodie Chilin-Eusebe. « Decoding water-rock interaction and volatile input at La Soufriere volcano (Guadeloupe) using time-series major and trace element analyses in gas condensates ». Journal of Volcanology and Geothermal Research 425 (mai 2022) : 107517. http://dx.doi.org/10.1016/j.jvolgeores.2022.107517.

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Astafiev, V. I., M. G. Kakhidze, V. I. Popkov et A. V. Popkova. « MULTI-SCALE STRESS-DEFORMATION STATUS OF POROUS GEOLOGICAL STRUCTURE AS RELATED TO WELL FILTRATION FLOWS ». Vestnik of Samara University. Natural Science Series 19, n^o 9.2 (6 juin 2017) : 153–69. http://dx.doi.org/10.18287/2541-7525-2013-19-9.2-153-169.

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Mono-harmonic junction in the interaction of porous space rock stress in oil/gas saturated reservoirs and averaged hydro-dynamic flows of viscous oil towards wells obtained as a result of innovative decisions in oil industry in general is presented. Within the frames of block homogeneous models of a well through the application of 3D linear theory of wave diffusion along the surface of geophysical emission layer, mathematical statement of asymmetrical filtration challenge with finite velocity of effect is presented. Dispersive ratios for constrained and resonant dissipative structures in a shear layer of viscous-elastic filtration at the edge of a slug of water-oil displacement are given. The redistribution results for the averaged inflow profile of viscous Newtonian filtration into asymmetrical energy-stable stress-deformation status inside the saturated porous media at various constraints: in conditions of enclosed or capillary-clamped boundary and in non-constrained conditions - at the frontier of displacement or with stimulation of water-flood displacement in zones of stagnation is presented.

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Li, Qingyu, Laijun Lu, Quansheng Zhao et Shuya Hu. « Impact of Inorganic Solutes’ Release in Groundwater during Oil Shale In Situ Exploitation ». Water 15, n^o 1 (31 décembre 2022) : 172. http://dx.doi.org/10.3390/w15010172.

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Oil shale can produce oil and shale gas by heating the oil shale at 300–500 °C. The high temperature and the release of organic matter can change the physical and mechanical properties of rocks and make the originally tight impervious layer become a permeable layer under in situ exploitation conditions. To realize the potential impact of the in situ exploitation of oil shale on groundwater environments, a series of water–rock interaction experiments under different temperatures was conducted. The results show that, with the increase of the reaction temperature, the anions and cations in the aqueous solution of oil shale, oil shale–ash, and the surrounding rock show different trends, and the release of anions and cations in the oil shale–ash solution is most affected by the ambient temperature. The hydrochemical type of oil shale–ash solution is HCO3-SO4-Na-K at 80 °C and 100 °C, which changes the water quality. The main reasons are that (1) the high temperature (≥80 °C) can promote the dissolution of FeS in oil shale and (2) the porosity of oil shale increases after pyrolysis, making it easier to react with water. This paper is an important supplement to the research on the impact of the in situ exploitation of oil shale on the groundwater environment. Therefore, the impacts of in situ mining on groundwater inorganic minerals should be taken into consideration when evaluating in situ exploitation projects of oil shale.

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Do, Hyun-Kwon, Seong-Taek Yun, Soonyoung Yu, Yon-Gyung Ryuh et Hyeon-Su Choi. « Evaluation of Long-Term Impacts of CO2 Leakage on Groundwater Quality Using Hydrochemical Data from a Natural Analogue Site in South Korea ». Water 12, n^o 5 (20 mai 2020) : 1457. http://dx.doi.org/10.3390/w12051457.

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Three hydrochemical types of CO2-rich water (i.e., Na-HCO3, Ca-Na-HCO3 and Ca-HCO3) occur together in the silicate bedrock (granite and gneiss) of Gangwon Province in South Korea. As a natural analogue of geological carbon storage (GCS), this can provide implications for the environmental impacts of the leakage of CO2 from deep GCS sites. By using hydrochemical and isotopic datasets that were collected for previous and current studies, this study aimed to carefully scrutinize the hydrochemical differences in the three water types with an emphasis on providing a better understanding of the impacts of long-term CO2 leakage on groundwater quality (especially the enrichments of minor and trace metals). As a result, the Na-HCO3 type CO2-rich water contained higher Li, Rb and Cs than the Ca-HCO3 type, whereas Fe, Mn and Sr were higher in the Ca-HCO3 type than in the Na-HCO3 type despite the similar geological setting, which indicate that the hydrochemical differences were caused during different geochemical evolutionary processes. The δ18O and δD values and tritium concentrations indicated that the Na-HCO3 type was circulated through a deep and long pathway for a relatively long residence time in the subsurface, while the Ca-HCO3 type was strongly influenced by mixing with recently recharged water. These results were supported by the results of principal component analysis (PCA), whose second component showed that the Na-HCO3 type had a significant relation with alkali metals such as Li, Rb and Cs as well as Na and K and also had a strong relationship with Al, F and U, indicating an extensive water-rock interaction, while the Ca-HCO3 type was highly correlated with Ca, Mg, Sr, Fe and Mn, indicating mixing and reverse cation exchange during its ascent with hydrogeochemical evolution. In particular, the concentrations of Fe, Mn, U and Al in the CO2-rich water, the result of long-term water-rock interaction and cation exchange that was enhanced by CO2 leakage into silicate bedrock, exceeded drinking water standards. The study results show that the leakage of CO2 gas and CO2-rich fluid into aquifers and the subsequent hydrogeochemical processes can degrade groundwater quality by mobilizing trace elements in rocks and consequently may pose a health risk.

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Musfika Rahman et Iskandar Dzulkarnain. « Response Surface Method for Modelling the Effect of CO2 in Brine/Waxy Oil Interfacial Tension during LSW-WAG Enhanced Oil Recovery ». Journal of Advanced Research in Applied Sciences and Engineering Technology 22, n^o 1 (16 janvier 2021) : 54–68. http://dx.doi.org/10.37934/araset.22.1.5468.

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Recent research on the combination of low salinity waterflood (LSW) with CO2 water-alternating gas (WAG) has received significant attention due to its effectiveness in recovering residual oil in a mature field. The solubility of CO2 increases with decreasing brine salinity; and the presence of CO2 in the injected water is expected to reduce the water/oil interfacial tension (IFT) leading to the release of trapped oil previously held in the rock by capillary forces. However, to date, little study has been done on the fluid/fluid interaction during the LSW-WAG process involving waxy crude oil and injected brine. In this study, two models have been developed from experimental IFT measurements that can facilitate the prediction of the CO2 effect in the interfacial tension between oil/water interface in the presence and absence of CO2. This objective is achieved by modelling the effect of pressure, brine salinity, and CO2 on oil/water IFT with the response surface methodology (RSM) using the modified central composite design method (CCD) for the experimental design. Based on the developed model, the optimum values of input variables were calculated by analysis of variance (ANOVA) to obtain an acceptable model. The R-squared values demonstrate that the developed models could appropriately predict the experimental results of oil/water IFT from Dulang crude oil and 7 different brine salinity. The results of this study are expected to give insights into the fluid/fluid interaction behaviour during the LSW-WAG recovery process from a mature field with waxy crude oil.

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Cartwright, I., T. Weaver, S. Tweed, D. Ahearne, M. Cooper, C. Czapnik et J. Tranter. « O, H, C isotope geochemistry of carbonated mineral springs in central Victoria, Australia : sources of gas and water–rock interaction during dying basaltic volcanism ». Journal of Geochemical Exploration 69-70 (juin 2000) : 257–61. http://dx.doi.org/10.1016/s0375-6742(00)00059-5.

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Lu, Lingling, Chen Guo, Zhenlong Chen et Hang Yuan. « Quantitative Identification of Water Sources of Coalbed Methane Wells, Based on the Hydrogen and Oxygen Isotopes of Produced Water—A Case of the Zhijin Block, South China ». Energies 15, n^o 24 (16 décembre 2022) : 9550. http://dx.doi.org/10.3390/en15249550.

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The quantitative identification of water sources is an important prerequisite for objectively evaluating the degree of aquifer interference and predicting the production potential of coalbed methane (CBM) wells. However, this issue has not been solved yet, and water sources are far from being completely understood. Stable water isotopes are important carriers of water source information, which can be used to identify the water sources for CBM wells. Taking the Zhijin block in the Western Guizhou Province as an example, the produced water samples were collected from CBM wells. The relationships between the stable isotopic compositions of the produced water samples and the production data were quantitatively analyzed. The following main conclusions were obtained. (1) The δD and δ18O values of the produced water samples were between −73.37‰ and −27.56‰ (average −56.30‰) and between −11.04‰ and −5.93‰ (average −9.23‰), respectively. The water samples have D-drift characteristics, showing the dual properties of atmospheric precipitation genesis and water–rock interaction modification of the produced water. An index d was constructed to enable the quantitative characterization of the degree of D-drift of the produced water. (2) The stable isotopic compositions of produced water showed the control of the water sources on the CBM productivity. The probability of being susceptible to aquifer interference increased with the increasing span of the producing seam combination, reflected in the lowering δD and δ18O values and the decreasing gas productivity. (3) Three types of water, namely, static water, dynamic water, and mixed water, were identified. The characteristic values of the isotopic compositions of the static and dynamic water were determined. Accordingly, a quantitative identification method for the produced water sources was constructed, based on their stable isotopic compositions. The identification results have a clear correlation with the gas production, and the output of the static water contributes to the efficient CBM production. The method for the quantitative identification of the water sources proposed in this study, can help to improve the CBM development efficiency and optimize the drainage technology.

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Radwan, Ahmed E. « Integrated reservoir, geology, and production data for reservoir damage analysis : A case study of the Miocene sandstone reservoir, Gulf of Suez, Egypt ». Interpretation 9, n^o 4 (4 août 2021) : SH27—SH37. http://dx.doi.org/10.1190/int-2021-0039.1.

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Reservoir damage is considered one of the major challenges in the oil and gas industry. Many studies have been conducted to understand formation damage mechanisms in borehole wells, but few studies have been conducted to analyze the data to detect the source, causes, and mitigations for each well where damage has occurred. I have investigated and quantified the reasons and mitigation of reservoir damage problems in the middle Miocene reservoir within the El Morgan oil field at the southern central Gulf of Suez, Egypt. I used integrated production, reservoir, and geologic data sets and their history during different operations to assess the reservoir damage in El Morgan-XX well. The collected data include the reservoir rock type, fluid, production, core analysis, rock mineralogy, geology, water chemistry, drilling fluids, perforations depth intervals, workover operations, and stimulation history. The integration of different sets of data gave a robust analysis of reservoir damage causes and helps to suggest suitable remediation. Based on these results, I conclude the following: (1) Workover fluid has been confirmed as the primary damage source, (2) the reservoir damage mechanisms could be generated by multisources including solids and filtrate invasions, fluid/rock interaction (deflocculating of kaolinite clay), water blockage, salinity chock, and the high sulfate content of the invaded fluid, and (3) multidata integration leads to appropriate reservoir damage analysis and effective design of the stimulation treatment. Furthermore, minimizing fluid invasion into the reservoir section by managing the overbalance during drilling and workover operations could be very helpful. Fluid types and solids should be considered when designing the stimulation treatment and compatibility tests should be performed. Long periods of completion fluid in boreholes are not recommended, particularly if the completion fluid pressure and reservoir pressure are out of balance, as well as the presence of sensitive formation minerals.

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Musfika Rahman et Iskandar Dzulkarnain. « RSM for Modelling the CO2 Effect in the Interfacial Tension Between Brine and Waxy Dulang Crude Oil During LSW-WAG EOR ». Journal of Advanced Research in Fluid Mechanics and Thermal Sciences 85, n^o 2 (9 août 2021) : 159–74. http://dx.doi.org/10.37934/arfmts.85.2.159174.

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Recent studies on low-salinity waterflooding (LSW) and CO2 water-alternating gas (WAG) use are noteworthy because of their effectiveness in recovered oil content retention in mature fields. s the brine salinity decreases, the solubility of CO2also increases. The CO2in the injected water is expected to reduce the water/oil interfacial tension (IFT), and thus previouslytrapped oil in the rock by capillary forces will flow. However, as of yet, a fewresearches havefocusedon the fluid/fluidinteraction involving waxy crude oil/brinein the LSW-WAGprocess. Twomodels, both of which have been developed from experimental interfacial tension measurements, assist in estimating the CO2's effect on oil/water interfacial tension in the presence and absence of CO2. This objective is accomplished by designing experiments using the modified central composite design (CCD)method in response surface methodology (RSM). Theeffectof pressure, brine salinity, and CO2on oil/water IFT are taken into consideration while modelling.Analysis of variance (ANOVA) was used to determine the optimal values of input variables based on the developed model to obtain an acceptable model. The R-squared values indicate that the developed models arecapable of accurately forecasting the experimental results of oil/water IFT using Dulang crude oil and seven different brine salinities. The findings of this study are expected to shed light on the fluid/fluid interaction behaviour during the LSW-WAG recovery process in a mature field producing waxy crude oil.

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Griffioen, Jasper, Hanneke Verweij et Roelof Stuurman. « The composition of groundwater in Palaeogene and older formations in the Netherlands. A synthesis ». Netherlands Journal of Geosciences 95, n^o 3 (27 juin 2016) : 349–72. http://dx.doi.org/10.1017/njg.2016.19.

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AbstractThere is increasing interest in the exploitation of the deep subsurface of the Netherlands for purposes other than conventional oil and gas production, such as geothermal energy, shale gas exploitation and the disposal of radioactive waste, so for technical and environmental reasons it is important to understand the composition of the deep groundwater. A synthesis has been made of almost 200 existing groundwater analyses for the Oligocene and older formations in the Netherlands. Three groundwater categories are considered: (1) deep oil and gas reservoirs, (2) deep, buried and confined aquifers and (3) shallower, semi-confined aquifers with or without outcrop areas nearby. No distinct water types are found but a continuous series, with Cl ranging from around 10,000 to 200,000 mg l−1: the highest concentrations are found in the reservoirs and the lowest in the semi-confined aquifers. The most saline brines are found in the northern onshore area and adjacent offshore area, where Permian and Triassic rock salt also occurs regionally in the subsurface. The groundwater is usually pH-neutral, saturated in carbonates and anaerobic. Anhydrite saturation occurs when the Cl concentration exceeds 100,000 mg l−1, and halite saturation occurs at Cl concentrations close to 200,000 mg l−1. Few tracer analyses have been done for δ2H–H2O, δ18O–H2O, δ37Cl, Br, Li and B, which makes a rigorous palaeohydrological interpretation impossible. Lithium and B may be controlled by water–rock interaction which makes them less suitable as tracers. Some of the analyses suggest that dissolution of rock salt plays a role in determining the salinity of groundwater for some deep wells in the southern part of the Netherlands, whereas other analyses suggest that evaporated seawater influences the salinity in the associated wells. Cation-exchange patterns and alkalinity to Ca ratios indicate that groundwater in the deep, buried and shallow, semi-confined aquifers is usually freshening. Six14C analyses of samples from the buried aquifers indicate an apparent age of at least 20,000 years. Six δ37Cl analyses of formation waters from reservoirs in South-Holland suggest diffusion of Cl from a brine towards fresher water, and the associated K and also Li concentrations further suggest that these brines are related to rock salt dissolution and are not the residue of evaporated seawater. The high Ca concentrations are enigmatic for the hypersaline formation waters in the reservoirs. A limited series of samples had been analysed for various trace elements. The median concentrations are similar to the seawater and Dutch background concentration limits for shallow groundwater, but maximum concentrations can be up to three orders of magnitude higher. In conclusion, the data synthesis shows that the composition of groundwater in reservoirs and aquifers of Palaeogene and older age varies strongly in salinity at the national scale. Presence of evaporite deposits and diffusive transport seem to play important roles in controlling the salinity. Many existing analyses have no or only a few tracer analyses, that even vary among the samples. A complete suite of analyses is needed to elucidate the hydrogeological and geochemical processes that control the groundwater composition.

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Miadonye, Adango, et Mumuni Amadu. « Modeling of Contact Angle versus pH and Derivation of Contact Angle versus Pressure in Deep Saline Aquifers under Geological Carbon Storage ». International Journal of Chemistry 12, n^o 2 (22 octobre 2020) : 19. http://dx.doi.org/10.5539/ijc.v12n2p19.

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Geological storage of anthropogenic carbon dioxide is regarded as a technically and economically viable strategy for mitigating carbon dioxide induced climate warming. Central to geological storage of anthropogenic carbon dioxide is the water rock interaction, which has a direct bearing on pH induced wettability evolution in saline aquifers. Consequently, understanding contact angle trend versus injected gas pressure is useful, considering its relationship to pH evolution in formation brine due to dissolved gas at prevailing temperatures and salinities. Several research works have published experimental data on contact angle versus pressure pertaining to geological conditions of anthropogenic carbon storage. In the present study, we have used thermodynamic theories relating to a surface charge model, contact angle and the classical Nernst equation to derive a logarithmic pH dependent contact angle equation. Considering the relationship between carbon dioxide solubility and pressure for a given temperature and salinity as well as the link between pH and the extent of solubility, we have plotted calculated contact angles versus corresponding pressures. Results of the plots obtained compare well with literature values. Therefore, given the lack of theoretical approach regarding contact angle versus pressure, our research work fills the knowledge gap considering the novelty in the derivation of the pH dependent contact angle equation.

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Zhitova, Elena S., Dmitry A. Khanin, Anton A. Nuzhdaev, Maria A. Nazarova, Rezeda M. Ismagilova, Vladimir V. Shilovskikh, Anastasia N. Kupchinenko, Ruslan A. Kuznetsov et Pavel S. Zhegunov. « Efflorescent Sulphates with M+ and M2+ Cations from Fumarole and Active Geothermal Fields of Mutnovsky Volcano (Kamchatka, Russia) ». Minerals 12, n^o 5 (10 mai 2022) : 600. http://dx.doi.org/10.3390/min12050600.

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In this study, sulphate efflorescent minerals covering the surface of the Donnoe and Dachnoe fields of the Mutnovsky volcano are described. The minerals were precipitated on the argillic facies as the result of water–rock interaction and fumarole emission. A chemical composition of Ca, Ba, (NH4)+, Na-Fe3+, (NH4)+-Al, (NH4)+-Fe3+, Na-Al, K-Al, and K-Fe3+ sulphates was reported. Elements such as Sr, Mg, Co, Ni, Ti and P were found as isomorphic impurities. Ammonia species were concentrated around fumaroles. The mineral assemblage described herein is unique in relation to other geological settings and reflects the process of low-temperature mineral formation associated with volcanism. The thermal water contains cations such as H, Na, K, NH4, Ca, Mg, Fe2+, Fe3+, and Al in different proportions with pH ranging from 2.4 to 6.5 and the dominance of acidic waters. The gas condensate bears such cations as (NH4)+, Ca, and Mg and has a pH of ~5. Thus, the rest of the main cations are derived from the leaching of the host rocks. Among the identified phases, the alunite-supergroup minerals are more prone to isomorphism. The Ti, Co, and Ni impurities mark the unique geochemistry of thermal water at the Mutnovsky volcano. We postulate that the chemical composition of alunite-supergroup minerals reflects the types of hydrothermal occurrences and contains important information on the geochemistry of the hydrothermal process.

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Roulleau, Emilie, Daniele Tardani, Yuji Sano, Naoto Takahata, Nicolas Vinet, Francisco Bravo, Carlos Muñoz et Juan Sanchez. « New insight from noble gas and stable isotopes of geothermal/hydrothermal fluids at Caviahue-Copahue Volcanic Complex : Boiling steam separation and water-rock interaction at shallow depth ». Journal of Volcanology and Geothermal Research 328 (décembre 2016) : 70–83. http://dx.doi.org/10.1016/j.jvolgeores.2016.10.007.

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Zhang, Yuzhu, Chun Chang Huang, Zhihai Tan, Haijun Qiu, Yinglu Chen, Yuda Cuan, Hui Zhao et al. « Palaeoclimatic and palaeoenvironmental implications of late-Pleistocene aeolian sand in the Jin-Shaan Gorges of the Yellow River valley revealed by luminescence chronology ». Holocene 29, n^o 6 (5 mars 2019) : 964–74. http://dx.doi.org/10.1177/0959683619831421.

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River valleys are critical water-gas-rock interactions zone, where close interaction between fluvial and aeolian deposition are a pronounced feature in arid, semi-arid, and semi-humid environments. Pedo-sedimentological investigations were carried out in the Jin-Shaan Gorges of the Yellow River valley. Two late-Pleistocene and Holocene aeolian sand-loess profiles were identified within the cliff riverbank. The aim of this study is to reveal the palaeoclimatic conditions and driving factors for the formation of palaeo-aeolian sand in the Jin-Shaan Gorges of the Yellow River valley. Five samples were taken from the aeolian sand-loess profiles for optically stimulated luminescence (OSL) dating. The OSL ages are in stratigraphic order and range from 12.8 ± 0.7 ka to 11.8 ± 1.0 ka. By combining OSL ages with additional stratigraphic correlations, the deposition period of the palaeo-aeolian sand is dated to 12.5–11.8 ka, which would place it at the Younger Dryas (YD) time interval that punctuated the last glacial-Holocene transition period. The formation of palaeo-aeolian sand in the region was due to sufficient sediment supply from the riverbed sand of the Yellow River, strong East Asian winter monsoon, and strong wind erosion. These results give insights into the palaeoclimatic and palaeoenvironmental conditions for the formation of aeolian sand associated with the river valleys in semi-arid and sub-humid regions.

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Li, Mingqian, Xiujuan Liang, Changlai Xiao, Yuqing Cao et Shuya Hu. « Hadrochemical Evolution of Groundwater in a Typical Semi-Arid Groundwater Storage Basin Using a Zoning Model ». Water 11, n^o 7 (28 juin 2019) : 1334. http://dx.doi.org/10.3390/w11071334.

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Groundwater guarantees water resources and ecological environment security in semi-arid areas. Studying the chemical evolution of groundwater in semi-arid areas is of great significance to regional ecological environment protection and water resources management. The water storage basin is not only a space for groundwater storage and movement but also a place for water–rock–gas interaction and elemental migration, dispersion, and enrichment. Due to its unique climate and geological environment, the semi-arid water storage basins have different hydrochemical environments, forming a zonal hydrogeochemical character. In this study, a typical semi-arid water storage basin (west of Jilin Province) is taken as an example, through the cross section of the recharge–runoff–excretion zone. A three-level hydrogeochemical zoning model is constructed to reveal the hydrogeochemical evolution of the area. The model is divided into three layers from bottom to top. The first layer shows the geological and hydrogeological conditions, including the topography, lithology, geological time, and hydrodynamic characteristics of the study area. The second layer represents the hydrogeochemical processes, divided into the recharge zone, runoff zone, and discharge zone in the horizontal direction according to the hydrodynamic environment and hydrochemistry type. The hydrogeochemical action gradually changes from lixiviation to cation exchange, evaporation, and concentration, as the landform plays a key role in hydrochemistry formation in the discharge area. The third layer gives the characteristics of the groundwater chemical components, including chemistry type, total dissolved solids, main anion and cation, and characteristic element F. Qualitative and quantitative characterizations of hydrochemistry evolution by reverse simulation and hydrodynamic, hydrochemical and thermodynamic indicators are given.

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Khurshid, Ilyas, et Imran Afgan. « Geochemical Investigation of CO2 Injection in Oil and Gas Reservoirs of Middle East to Estimate the Formation Damage and Related Oil Recovery ». Energies 14, n^o 22 (16 novembre 2021) : 7676. http://dx.doi.org/10.3390/en14227676.

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The injection performance of carbon dioxide (CO2) for oil recovery depends upon its injection capability and the actual injection rate. The CO2–rock–water interaction could cause severe formation damage by plugging the reservoir pores and reducing the permeability of the reservoir. In this study, a simulator was developed to model the reactivity of injected CO2 at various reservoir depths, under different temperature and pressure conditions. Through the estimation of location and magnitude of the chemical reactions, the simulator is able to predict the effects of change in the reservoir porosity, permeability (due to the formation/dissolution) and transport/deposition of dissoluted particles. The paper also presents the effect of asphaltene on the shift of relative permeability curve and the related oil recovery. Finally, the effect of CO2 injection rate is analyzed to demonstrate the effect of CO2 miscibility on oil recovery from a reservoir. The developed model is validated against the experimental data. The predicted results show that the reservoir temperature, its depth, concentration of asphaltene and rock properties have a significant effect on formation/dissolution and precipitation during CO2 injection. Results showed that deep oil and gas reservoirs are good candidates for CO2 sequestration compared to shallow reservoirs, due to increased temperatures that reduce the dissolution rate and lower the solid precipitation. However, asphaltene deposition reduced the oil recovery by 10%. Moreover, the sensitivity analysis of CO2 injection rates was performed to identify the effect of CO2 injection rate on reduced permeability in deep and high-temperature formations. It was found that increased CO2 injection rates and pressures enable us to reach miscibility pressure. Once this pressure is reached, there are less benefits of injecting CO2 at a higher rate for better pressure maintenance and no further diminution of residual oil.

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Taran, Yu A., G. V. Ryabinin, B. G. Pokrovski, I. N. Nazhalova et N. A. Malik. « MINERAL WATERS OF THE AVACHINSKY DEPRESSION, KAMCHATKA ». Bulletin of Kamchatka Regional Association «Educational-Scientific Center». Earth Sciences, n^o 2(50) (30 juin 2021) : 22–39. http://dx.doi.org/10.31431/1816-5524-2021-2-50-22-39.

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Saline waters (up to 22 g/l) were tapped by deep (to 3000 m) wells at the foot of active volcanoes Avachinsky and Koryaksky, within Avachinsky depression. Temperature of waters was ~ 60°C in the western part and cold in the eastern part, closer to the Pacific coast. In this paper we present the literature and our own data on chemical and isotopic composition of these waters. The waters are of the Na-Cl type with extremely low abundances of sulfate and magnesium, high concentration of calcium and surprisingly high concentration of strontium. The waters contain about 50 ml/l of gas where methane and nitrogen are main components (~ 70 vol% and 30 vol%, respectively) and also presents H2S (~ 30 ml/l) and very low concentrations of CO2 (< 0.5 vol%). The N2/Ar ratio, as a rule, is higher than the air ratio, i.e., the non-atmospheric nitrogen presents. We discuss the possible options of the water-rock interaction, responsible for the chemical composition of waters, and offer a conceptual model of the proposed basin of mineral waters that includes the distribution of deep temperatures, the location of the possible sources of heat mineralized solutions.

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Qiao, C., L. Li, R. T. Johns et J. Xu. « Compositional Modeling of Dissolution-Induced Injectivity Alteration During CO2 Flooding in Carbonate Reservoirs ». SPE Journal 21, n^o 03 (15 juin 2016) : 0809–26. http://dx.doi.org/10.2118/170930-pa.

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Summary Geochemical reactions between fluids and carbonate rocks can change porosity and permeability during carbon dioxide (CO2) flooding, which may significantly affect well injectivity, well integrity, and oil recovery. Reactions can cause significant scaling in and around injection and production wells, leading to high operating costs. Dissolution-induced well-integrity issues and seabed subsidence are also reported as a substantial problem at the Ekofisk field. Furthermore, mineral reactions can create fractures and vugs that can cause injection-conformance issues, as observed in experiments and pressure transients in field tests. Although these issues are well-known, there are differing opinions in the literature regarding the overall impacts of geochemical reactions on permeability and injectivity for CO2 flooding. In this research, we develop a new model that fully couples reactive transport and compositional modeling to understand the interplay between multiphase flow, phase behavior, and geochemical reactions under reservoir and injection conditions relevant in the field. Simulations were carried out with a new in-house compositional simulator on the basis of an implicit-pressure/explicit-composition and finite-volume formulation that is coupled with a reactive transport solver. The compositional and geochemical models were validated separately with CMG-GEM (CMG 2012) and CrunchFlow (Steefel 2009). Phase-and-chemical equilibrium constraints are solved simultaneously to account for the interaction between phase splits and chemical speciation. The Søreide and Whitson (1992) modified Peng-Robinson equation of state is used to model component concentrations present in the aqueous and hydrocarbon phases. The mineral-dissolution reactions are modeled with kinetic-rate laws that depend on the rock/brine contact area and the brine geochemistry, including pH and water composition. Injectivity changes caused by rock dissolution and formation scaling are investigated for a five-spot pattern by use of several common field-injection conditions. The results show that the type of injection scheme and water used (fresh water, formation water, and seawater) has a significant impact on porosity and permeability changes for the same total volume of CO2 and water injected. For continuous CO2 injection, very small porosity changes are observed as a result of evaporation of water near the injection well. For water-alternating-gas (WAG) injection, however, the injectivity increases from near zero to 50%, depending on the CO2 slug size, number of cycles, and the total amount of injected water. Simultaneous water-alternating-gas injection (SWAG) shows significantly greater injectivity increases than WAG, primarily because of greater exposure time of the carbonate surface to CO2-saturated brine coupled with continued displacement of calcite-saturated brine. For SWAG, carbonate dissolution occurs primarily near the injection well, extending to larger distances only when the specific surface area is small. Formation water and seawater lead to similar injectivity increases. Carbonated waterflooding (a special case of SWAG) shows even greater porosity increases than SWAG because more water is injected in this case, which continuously sweeps out calcite-saturated brine. The minerals have a larger solubility in brine than in fresh water because of the formation of aqueous complexes, leading to more dissolution instead of precipitation. Overall, this research points to the importance of considering the complex process coupling among multiphase flow, transport, phase behavior, and geochemical reactions in understanding and designing schemes for CO2 flooding as well as enhanced oil recovery at large.

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You, Jiahui, et Kyung Jae Lee. « Pore-Scale Numerical Investigations of the Impact of Mineral Dissolution and Transport on the Heterogeneity of Fracture Systems During CO2-Enriched Brine Injection ». SPE Journal 27, n^o 02 (21 janvier 2022) : 1379–95. http://dx.doi.org/10.2118/204313-pa.

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Summary Carbon dioxide (CO2) storage and sequestration is regarded as an effective approach to mitigate greenhouse gas emissions. While injecting an enormous amount of CO2 into carbonate-rich aquifers, CO2 dissolves in the formation brine under the large pressure and the subsequently formed CO2-enriched brine reacts with the calcite. Reaction-induced changes in pore structure and fracture geometry alter the porosity and permeability, giving rise to the concerns of CO2 storage capacity and security. Especially in the reservoir or aquifer with natural fractures, the fractures provide highly permeable pathways for fluid flow. This study aims to analyze the acid-rock interaction and subsequent permeability evolution in the systems with complex fracture configurations during CO2 injection by implementing a pore-scale Darcy-Brinkman-Stokes (DBS) reactive transport model. The model has been developed by expanding the functionality of OpenFOAM, which is an open-source code for computational fluid dynamics. A series of partial differential equations are discretized by applying the finite volume method and then solved sequentially. Different fracture configurations, such as fracture length, density, connection, and mineral components, have been considered to investigate their impacts on the dynamic porosity-permeability relationship, dissolution rate, and reactant transport characteristics during CO2 storage. Various mineralogical compositions were investigated to compare their effects on the reactive transport and subsequent system behavior induced by water-rock interactions. The investigation revealed several interesting findings. We found that calcium (Ca) ions concentration was low in the poorly connected area at the initial time. Because CO2-enriched brine saturated the system and reacted with calcite, Ca ions started accumulating in the system. However, Ca ions barely flowed out of the poorly connected area, and the concentration became high. Lengths of branches mainly influenced the dissolution rates, while they had slight impacts on the porosity-permeability relationship. While fracture connectivity had an apparent influence on the porosity-permeability relationship, it showed a weak relevance on the dissolution rate. The calcite-clay fracture-matrix system showed a slow increase of permeability because CO2-enriched brine was injected. These microscopic insights can help enhance the CO2 sealing capacity to guarantee environmental safety.

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Zappone, Alba, Antonio Pio Rinaldi, Melchior Grab, Quinn C. Wenning, Clément Roques, Claudio Madonna, Anne C. Obermann et al. « Fault sealing and caprock integrity for CO<sub>2</sub> ; storage : an in situ injection experiment ». Solid Earth 12, n^o 2 (5 février 2021) : 319–43. http://dx.doi.org/10.5194/se-12-319-2021.

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Abstract. The success of geological carbon storage depends on the assurance of permanent containment for injected carbon dioxide (CO2) in the storage formation at depth. One of the critical elements of the safekeeping of CO2 is the sealing capacity of the caprock overlying the storage formation despite faults and/or fractures, which may occur in it. In this work, we present an ongoing injection experiment performed in a fault hosted in clay at the Mont Terri underground rock laboratory (NW Switzerland). The experiment aims to improve our understanding of the main physical and chemical mechanisms controlling (i) the migration of CO2 through a fault damage zone, (ii) the interaction of the CO2 with the neighboring intact rock, and (iii) the impact of the injection on the transmissivity in the fault. To this end, we inject CO2-saturated saline water in the top of a 3 m thick fault in the Opalinus Clay, a clay formation that is a good analog of common caprock for CO2 storage at depth. The mobility of the CO2 within the fault is studied at the decameter scale by using a comprehensive monitoring system. Our experiment aims to close the knowledge gap between laboratory and reservoir scales. Therefore, an important aspect of the experiment is the decameter scale and the prolonged duration of observations over many months. We collect observations and data from a wide range of monitoring systems, such as a seismic network, pressure temperature and electrical conductivity sensors, fiber optics, extensometers, and an in situ mass spectrometer for dissolved gas monitoring. The observations are complemented by laboratory data on collected fluids and rock samples. Here we show the details of the experimental concept and installed instrumentation, as well as the first results of the preliminary characterization. An analysis of borehole logging allows for identifying potential hydraulic transmissive structures within the fault zone. A preliminary analysis of the injection tests helped estimate the transmissivity of such structures within the fault zone and the pressure required to mechanically open such features. The preliminary tests did not record any induced microseismic events. Active seismic tomography enabled sharp imaging the fault zone.

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Gamal, Hany, Saad Al-Afnan, Salaheldin Elkatatny et Mohamed Bahgat. « Barium Sulfate Scale Removal at Low-Temperature ». Geofluids 2021 (22 mars 2021) : 1–12. http://dx.doi.org/10.1155/2021/5527818.

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Precipitation of the scale in the oil and gas reservoirs, surface and subsurface equipment, and processing and production facilities is a big problem as it affects petroleum production. The scale precipitations decrease the oil and gas production and cause economical loss. Solving this issue requires an engineering investigation to provide a safe, efficient, and economic solution. Consequently, this study proposed a developed dissolver for barium sulfate scales, where two field-scale samples were collected from different locations. The compositional analysis for scale samples showed that sample 1 is 100% barium sulfate where sample 2 has 97.75% barium sulfate and 2.25% of quartz. The composition of the developed dissolver has diethylenetriamine pentaacetic acid (DTPA) as a chelating agent, oxalic acid, and tannic acids as an activator, nonionic surfactant, and water as the base fluid. The new dissolver was investigated with extensive lab tests to determine the dissolution efficiency, precipitation tendency for the dissolved scale solids, corrosion rate, and fluid-rock interaction. The obtained successful results indicated that the developed dissolver had a dissolution efficiency for two real barium scale samples as the results showed 76.9 and 71.2% at 35°C and 91.3 and 78.4% at 90°C for samples 1 and 2, respectively. The new solution has a great performance compared with common scale dissolvers in the oil field as hydrochloric acid, ethylenediaminetetraacetic acid, and diethylenetriamine pentaacetic acid. The developed dissolver showed a very low precipitation tendency for the scale dissolved solids (1.9 and 3.2% for samples 1 and 2, respectively) under 35°C for 24 hours. Without any additives of corrosion inhibitors, the corrosion rate was 0.001835 g/cm2 at 6.9 MPa and 100°C for 6 hours. Injecting the developed dissolver for damaged sandstone core sample with barite mud by flooding test showed a return permeability of 115%.

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Huang, Yi, Zhongwei Wu, Xiaoming Sun, Yan Wang, Guiyong Shi, Wei Zhai et Yao Guan. « He-Ar Isotopes and Trace Gas Compositions of Fluid Inclusions in Massive Sulphides from the Yushui Copper-Polymetallic Deposit, South China : Metallogenic Implications ». Minerals 9, n^o 5 (29 avril 2019) : 258. http://dx.doi.org/10.3390/min9050258.

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The Yushui ore deposit, located in the middle section of the Yong’an-Meixian Hercynian depression, is a medium-sized Cu-polymetallic massive sulphide deposit in Eastern Guangdong Province, South China. This deposit is characterized by unusually high copper grade (up to 50–60 wt. % Cu). Other metallic elements, such as lead, zinc and silver, are also economically important in the Yushui ore bodies. The aim of this study was to apply N2–Ar–He systematics, together with organic gases (light-hydrocarbon tracers), to constrain the origin and evolution of ore-forming fluids. The helium-argon isotopes and trace gas compositions of fluid inclusions trapped within metal sulphide minerals were measured for a number of bonanza ores from the Yushui deposit. The noble gas concentrations in the studied samples vary over one to two orders of magnitude (4He: 2.27–160.00 × 10−5 cm3 STP g−1; 3He: 0.53–34.88 × 10−12 cm3 STP g−1; 40Ar: 6.28–37.82 × 10−7 cm3 STP g−1; 36Ar: 1.25–10.40 × 10−9 cm3 STP g−1). Our data show a narrow range of 3He/4He ratios from 0.006 to 0.056 Ra (~0.026 Ra on average, n = 8), which are considerably lower than the modern atmospheric end-member value; whereas the 40Ar/36Ar ratios (ranging from 333.76 to 501.68, with an average of 397.53) are significantly greater than that of air-saturated water. Most of the bornite samples have somewhat higher 3He/4He ratios of trapped fluids when compared to chalcopyrite. Overall, these He-Ar results are well within the range of crustal reservoir, thus implying a predominantly crustal source (originated from Caledonian basement) for ore-forming solutions, with little contribution from mantle-derived fluids. Analysis of the N2–Ar–He composition in Cu-rich sulphides indicates that the Yushui ore-forming fluids were probably derived from formation water (or basinal hot brines). Moreover, organic gas species identified in sulphide-hosted fluid inclusions are mainly composed of C1–C4 alkanes, while the concentrations of unsaturated olefins and aromatic hydrocarbons are very low. In particular, most chalcopyrite samples with relatively low 3He/4He ratios (0.006–0.016 Ra) and 40Ar*/4He values (0.0002–0.0012) are generally characterized by very high CO2/CH4 ratios (~60–102). All these suggest that main-stage Cu-Ag metallogenic processes might have not been affected by high-temperature magmatic activities or superimposed by strong metamorphic overprinting, although some chalcopyrite-rich ores appear to be influenced by later stage hydrothermal processes. In summary, neither magmatic input nor convecting seawater has played an important role in the formation of Yushui copper-polymetallic deposit. The massive sulphide ore bodies were products of water–rock interaction between metal-bearing basinal brines and the host sedimentary strata.

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Li, Liangping, Meijing Zhang et Ming Zhang. « Gas-Water-Rock Interactions and Implications for Geoenvironmental Issues ». Geofluids 2018 (8 octobre 2018) : 1–4. http://dx.doi.org/10.1155/2018/6847392.

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