Academic literature on the topic 'Water-gas-rock interaction'
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Journal articles on the topic "Water-gas-rock interaction"
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Pang, Zhonghe, Jie Li, and 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, no. 2 (June 17, 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, and Serhii Skipochka. "Interaction of rock-bolt supports while weak rock reinforcing by means of injection rock bolts." Mining of Mineral Deposits 15, no. 4 (December 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, and Norikazu YAMADA. "Experimental research of plagioclase (rock)-gas-water interaction at hydrothermal conditions for CO2 mineralization." Japanese Magazine of Mineralogical and Petrological Sciences 38, no. 4 (2009): 111–21. http://dx.doi.org/10.2465/gkk.38.111.
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Popov, S. N., and 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, no. 30 (December 21, 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, and 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, and Chenglin Zhang. "Geochemistry of Formation Water and Implications for Ultradeep Tight Sandstone of DK Gas Field in Kuqa Depression." Geofluids 2022 (November 18, 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, and Moran Wang. "Numerical Simulation of Fluid Flow in Carbonate Rocks Based on Digital Rock Technology." Energies 15, no. 10 (May 19, 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, and Derek Elsworth. "Interpretation of Gas/Water Relative Permeability of Coal Using the Hybrid Bayesian-Assisted History Matching: New Insights." Energies 14, no. 3 (January 26, 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, and Katarzyna Chruszcz-Lipska. "Hydrogeochemical Aspects Associated with the Mixing of Formation Waters Injected Into the Hydrocarbon Reservoir." Gospodarka Surowcami Mineralnymi 33, no. 2 (June 27, 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.
Dissertations / Theses on the topic "Water-gas-rock interaction"
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Song, Ke-Han, and 宋科翰. "The alteration mineral assemblages by the gas-water-rock interaction- a case study in the Liuhunagku and Longfenku areas of Tatun Volcano Group." Thesis, 2017. http://ndltd.ncl.edu.tw/handle/9f9fc4.
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碩士中國文化大學
地學研究所地質組
105
This study firstly applies the petrography and alteration mineral assemblages of rocks to study mineralogical facies transition under the gas-water-rock interaction in Longfengku and Liuhaungku of the Tatun Volcano Group (TVG). The results showed that the andesite consists of augite, hypersthene, hornblende, plagioclase and these samples far away from fumarolest; a partial altered andesite composes of opal, cristobalite and less plagioclase; and he andesite includes opal and a little plagioclase in the closer fumaroles area. The sulfur element does not exist in samples far away from fumaroles. In addition, the results of SEM, EDS and ED-XRF displayed that samples are well texture and lower silica content, and higher of aluminum and calcium elements of samples in the far away fumaroles area. Finally, this study infers to the sulfur component plays important role during alteration process.
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CINTI, DANIELE. "CARATTERIZZAZIONE GEOCHIMICA DEI FLUIDI E GEOTERMOMETRIA NEL DISTRETTO VULCANICO VICANO-CIMINO. IMPLICAZIONI PER L’UTILIZZO DELLA RISORSA GEOTERMICA." Doctoral thesis, 2014. http://hdl.handle.net/2158/850905.
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RIASSUNTO
Il Distretto Vulcanico Vicano-Cimino (DVVC) è connesso all'attività magmatica post-orogenica che ha interessato il settore peri-tirrenico dell’Italia centrale. La composizione chimica ed isotopica di 333 acque e 25 emissioni gassose indica la presenza di due tipologie di fluidi: 1) acque fredde a chimismo bicarbonatico circolanti a deboli profondità entro formazioni vulcaniche e depositi sedimentari e 2) acque termali a composizione solfato‐bicarbonato‐calcica e ricche in gas (CO2) circolanti entro rocce carbonatiche‐evaporitiche, e separate dagli acquiferi superficiali da formazioni a bassa permeabilità. La fase gassosa, dominata dalla CO2, è comunemente associata alle acque termali emergenti nel DVVC. Essa può, tuttavia, entrare in contatto con gli acquiferi superficiali e, dissolvendo in essi, originare sorgenti a basso pH (acque acetose e bubbling pools) oppure manifestarsi in superficie direttamente dal suolo. L’emergenza di acque termali e gas in superficie si ha preferenzialmente in corrispondenza di elementi fragili (fratture e faglie), i quali forniscono le vie preferenziali per la risalita veloce dei fluidi di origine profonda verso la superficie. Viceversa le acque fredde risultano prive di apporti profondi e non mostrano alcuna relazione con l’assetto strutturale dell’area. Le acque ospitate negli acquiferi superficiali ed in quello profondo sono di origine meteorica e vanno a costituire due tipologie di circolazione: una più superficiale costituita da acque freatiche e di scorrimento, una più profonda dove le acque meteoriche si infiltrano nelle formazioni permeabili in affioramento per fratturazione e vanno ad alimentare il serbatoio idrotermale. Gli isotopi stabili dell’acqua sembrano suggerire una ricarica degli acquiferi di tipo locale, posta approssimativamente a 700‐800 m s.l.m. L'anidride carbonica è prodotta principalmente da reazioni termo-metamorfiche di decarbonatazione entro le porzioni più profonde e più calde dell’acquifero profondo (δ13C-CO2 tra -3.1 e -2.2‰ vs. VPDB) con un contributo minore da degassamento mantellico. I valori relativamente bassi del rapporto R/Ra (0.27-1.19) indicano che l’elio è principalmente derivante da una sorgente crostale con un contributo secondario di risalita dal mantello. Coerentemente, valori relativamente elevati dei rapporti N2/Ar e N2/3He e valori positivi di δ15N-N2 (da 0.91 a 5,7‰ vs AIR) caratterizzano i gas del DVVC, suggerendo la presenza di un significativo “eccesso” di azoto rispetto alla componente atmosferica. Reazioni di riduzione della CO2, in presenza di H2, che avvengono all’interno del serbatoio idrotermale a temperature >200°C, sembrano essere alla base della produzione di metano. I valori di δ34S-H2S (da 9.3 a 11.4‰ vs. VCDT) sono consistenti con l'ipotesi di una origine di H2S da riduzione termochimica delle anidriti Triassiche. Gli equilibri chimici relativi ai sistemi H2O‐H2‐H2S‐Ar e C3H6‐ C3H8 suggeriscono che le specie gassose raggiungono l’equilibrio chimico in un sistema acqua‐dominante a temperature inferiori rispetto a quella massima misurata in pozzo (218°C) ed a condizioni redox controllate dalle interazioni teoriche tra il fluido idrotermale ed un assemblaggio minerale locale. Le temperature relativamente elevate all’interno del serbatoio producono il rilascio di una fase gassosa che si separa dalla fase liquida e che, durante la risalita verso la superficie, è interessata da processi secondari (ri‐equilibrio a bassa temperatura, condensazione di vapore acqueo, dissoluzione entro acquiferi superficiali, attività microbica) che causano perdita di vapore acqueo (per condensazione) e notevoli cambiamenti nelle concentrazioni delle specie sensibili a variazioni della temperatura e delle condizioni redox (H2, CH4, CO2, CO e H2S). Il DVVC può essere considerato favorevolmente in termini di sfruttamento delle risorse geotermiche, sia per usi diretti che per la produzione di energia elettrica tramite sistemi a ciclo binario. In particolare, attraverso l’indagine geochimica si è tentato di fornire gli strumenti necessari per una stima delle potenzialità nei diversi settori dell’area di studio, degli utilizzi più idonei della risorsa e per una attenta valutazione del possibile impatto che i fluidi geotermali possono avere sulle infrastrutture (pozzi, impianti) e sull’ambiente.
ABSTRACT
The Vicano–Cimino Volcanic District (VCVD) is related to the post-orogenic magmatic activity of the peri-
Tyrrhenian sector of Central Italy. The chemical and isotopic compositions of 333 water discharges and 25 gas
emissions indicate the occurrence of two main sources: 1) cold Ca-HCO3 to Ca(Na, K)-HCO3 type waters from
relatively shallow aquifers hosted in volcanic and sedimentary formations; and 2) thermal Ca-SO4(HCO3) type
waters located in a deep CO2-pressurized reservoir, hosted in carbonate–evaporite rocks and separated from
the shallow aquifers by thick sequences of low-permeability formations. Carbon dioxide is mainly produced by
thermal metamorphic decarbonation within the deepest and hottest parts of the carbonate–evaporite reservoir
(δ13C–CO2 from−3.1 to+2.2‰vs. VPDB), likely affected by a mantle-rooted CO2. ReleaseofCO2-rich gases from
the deep aquifer into the overlying shallow aquifers produces high-CO2 springs and bubbling pools. The spatial
distribution of thermal waters and CO2-rich cold discharges is strongly controlled by fractures and faults located
in correspondencewith buried structural highs. Stable isotopes (δD and δ18O) suggest thatmeteoric water feeds
both the shallowand deep reservoirs. The relatively lowR/Ra values (0.27–1.19) indicate that He ismainly deriving
from a crustal source, with minor component from the mantle affected by crustal contamination related to
the subduction of the Adriatic plate. Consistently, relatively high N2/Ar and N2/3He ratios and positive δ15N–N2
values (from0.91 to 5.7‰vs. air) characterize the VCVD gas discharges, suggesting the occurrence of a significant
“excess” nitrogen. Isotopic compositions of CH4 (δ13C–CH4 and δD–CH4 values from−28.9 to−22.1‰vs. VPDB
and from −176 to −138‰ vs. VSMOW, respectively), and composition of light alkanes are indicative of prevalent
thermogenic CH4, although the occurrence of abiogenic CH4 production cannot be excluded. The δ34S–H2S
values (from+9.3 to+11.4‰vs. VCDT) are consistentwith the hypothesis of H2S production fromthermogenic
reduction of Triassic anhydrites. Gas geothermometry in the H2O–H2–Ar–H2S system suggests that the VCVD
gases equilibrated in a liquid phase at redox conditions controlled by interactions of fluids with the local mineral
assemblage at temperatures lower (b200 °C) than that andmeasured in deep (N2000 m) geothermalwells. This
confirms that secondary processes, i.e. steam condensation, gas dissolution in shallow aquifers, re-equilibration
at lower temperature, and microbial activity, significantly affect the chemistry of the uprising fluids. Thermal
water chemistry supports the occurrence in this area of an anomalous heat flowthat, coupledwith the recent demographic
growth, makes this site suitable for direct and indirect exploitation of the geothermal resource, in
agreement with the preliminary surveys carried out in the 1970's–1990's for geothermal exploration purposes.
Book chapters on the topic "Water-gas-rock interaction"
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Aiuppa, A., L. Brusca, W. D’Alessandro, S. Giammanco, and F. Parello. "A Case Study of Gas-Water-Rock Interaction in a Volcanic Aquifer: The South-Western Flank of Mt. Etna (Sicily)." In Water-Rock Interaction, 125–45. Dordrecht: Springer Netherlands, 2002. http://dx.doi.org/10.1007/978-94-010-0438-1_5.
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Huaiyan, Lei, Fu Wanjun, and Shi Yuxin. "Enhanced gas generation by clay mineral catalysis of source rocks." In Water-Rock Interaction, 259–62. London: Routledge, 2021. http://dx.doi.org/10.1201/9780203734049-64.
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Pal’yanova, G. A., G. P. Shironosova, and G. R. Kolonin. "Modeling of gold behavior in hydrothermal complex fluid with gas component." In Water-Rock Interaction, 819–23. London: Routledge, 2021. http://dx.doi.org/10.1201/9780203734049-204.
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Evans, William C., George W. Kling, and Michele L. Tuttle. "Lake Nyos, Cameroon: Examining the 1986 gas release from the system standpoint." In Water-Rock Interaction, 303–6. London: Routledge, 2021. http://dx.doi.org/10.1201/9780203734049-75.
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Osipenko, A. B., G. M. Gavrilenko, and Yu O. Egorov. "Types of recent seafloor gas-hydrothermal activity in the Western Pacific island arcs." In Water-Rock Interaction, 579–81. London: Routledge, 2021. http://dx.doi.org/10.1201/9780203734049-142.
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Shigeno, Hiroshi, Masaaki Takahashi, Tetsuro Noda, and Isao Matsunaga. "Gas chemistry for Hijiori Hot Dry Rock circulation tests conducted in 1989 and 1991." In Water-Rock Interaction, 549–52. London: Routledge, 2021. http://dx.doi.org/10.1201/9780203734049-134.
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Mayer, Bernhard, H. Roy Krouse, and Allan H. Legge. "The fate of sulfur of industrial origin in the pedosphere and hydrosphere near a sour gas plant in Alberta, Canada." In Water-Rock Interaction, 207–10. London: Routledge, 2021. http://dx.doi.org/10.1201/9780203734049-51.
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"Role of water-rock-gas interaction in sequestration of CO2." In Water-Rock Interaction XIII. CRC Press, 2010. http://dx.doi.org/10.1201/b10556-16.
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Novikov, D. A., A. V. Chernykh, F. F. Dultsev, E. V. Borisov, and P. A. Yan. "TRACE ELEMENTS FRACTIONATION IN THE WATER-ROCK-OIL SYSTEM ON THE EXAMPLE OF OIL-AND-GAS-BEARING DEPOSITS OF WESTERN SIBERIA, THE ARCTIC REGIONS." In WATER-ROCK INTERACTION: GEOLOGICAL EVOLUTION, 254–57. Buryat Scientific Center of SB RAS Press, 2020. http://dx.doi.org/10.31554/978-5-7925-0584-1-2020-254-257.
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Edelev, A. V., N. V. Yurkevich, S. B. Bortnikova, T. A. Fedorova, Yu G. Karin, V. V. Olenchenko, and P. S. Osipova. "ASSESSMENT OF THE DYNAMICS OF WATER : ROCK INTERACTION BY SUBSURFACE (BY ELECTROTOMOGRAPHY) AND SURFACE (BY GAS EMANATIONS) MANIFESTATIONS AS AN EXAMPLE OF SULFIDE-CONTAINING WASTES FROM THE SALAIR GOK." In WATER-ROCK INTERACTION: GEOLOGICAL EVOLUTION, 339–42. Buryat Scientific Center of SB RAS Press, 2020. http://dx.doi.org/10.31554/978-5-7925-0584-1-2020-339-342.
Full textConference papers on the topic "Water-gas-rock interaction"
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Ryzhenko, B. N., and O. A. Limantseva. "THERMODYNAMIC SIMULATION OF WATER-ROCK-GAS SYSTEM FOR PREDICTION OF CHEMICAL COMPOSITION DRAINAGE SOLUTION OF UDOKAM COPPER ORE DEPOSIT." In The Geological Evolution of the Water-Rock Interaction. Buryat Scientific Center of SB RAS Press, 2018. http://dx.doi.org/10.31554/978-5-7925-0536-0-2018-72-78.
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Stone, Amanda J., John A. Diemer, David S. Vinson, and Valerie S. Reynolds. "WATER-ROCK INTERACTION IN THE DEEP RIVER BASIN, NC, A CANDIDATE BASIN FOR SHALE GAS DEVELOPMENT." In 66th Annual GSA Southeastern Section Meeting - 2017. Geological Society of America, 2017. http://dx.doi.org/10.1130/abs/2017se-290455.
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Edgin, Matthew, John Kaszuba, Janet Dewey, and Mark Longman. "WATER-ROCK INTERACTION IN A GAS SHALE: EFFECTS OF STIMULATION FLUID ON MINERALOGY AND POROSITY IN THE PRESENCE OF FORMATION WATER." In GSA Annual Meeting in Indianapolis, Indiana, USA - 2018. Geological Society of America, 2018. http://dx.doi.org/10.1130/abs/2018am-320840.
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Schreiber, Pierre-Edouard, Andrea Osorio Ochoa, Jean-Claude Hild, Catherine Prinet, Marcel Bourgeois, and Amit Kumar. "A Comprehensive Analysis of Water Alternating Gas Recovery Mechanisms in a Giant Middle East Field." In SPE Conference at Oman Petroleum & Energy Show. SPE, 2022. http://dx.doi.org/10.2118/200067-ms.
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Abstract This paper is based on a study performed on an offshore Middle East field. The field is a giant complex mostly carbonate oil field, which is characterized by a thin oil column, a low permeability associated with fractures, a large transition zone and a lateral variation in fluid properties. Even after an extensive and efficient water-flood development, there are substantial amounts of oil remaining in the reservoir due to the highly oil-wet nature of the rock. Various Enhanced Oil Recovery (EOR) techniques have been envisaged to enhance oil production. The most mature one is the immiscible hydrocarbon Water Alternating Gas (WAG) injection. This High Pressure (HP)-WAG project started in September 2012 after the encouraging results of the continuous Low Pressure (LP) gas injection trial performed in 2008. This paper presents the latest analysis of the performances of this HP-WAG project. The HP-WAG project performances is evaluated through (i) the oil gain (versus a water-flood baseline), (ii) the water injectivity evolution over the WAG cycles, (iii) the gas management and (iv) the well and surface integrity. The paper also aims to share the methodology for analyzing the contribution of the main mechanisms occurring over the WAG cycles: the oil-gas interaction mechanisms and the desaturation mechanisms. The oil-gas interactions that occur in immiscible gas injection cases lead to significant long-lasting WAG effects thanks to both the swelling effects that continue even once the oil is saturated and a permanent mobility ratio improvement. The contribution of both macroscopic and microscopic oil desaturation is also described and quantified in this paper. The work presented in this paper has evidenced the HP-WAG technique benefits and has improved the understanding of the impacts of the main mechanism occurring in the reservoir. This knowledge paved the way towards more extensive WAG deployment on the field. It also emphasized the need of laboratory experiments to calibrate the three-phase models and the absolute need of compositional models to capture the entire WAG benefits even in immiscible gas injection cases.
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Yamamoto, Marcio, Motohiko Murai, Katsuya Maeda, and Shotaro Uto. "An Experimental Study of the Interaction Between Pipe Structure and Internal Flow." In ASME 2009 28th International Conference on Ocean, Offshore and Arctic Engineering. ASMEDC, 2009. http://dx.doi.org/10.1115/omae2009-79312.
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Nowadays pipes are widely deployed in the offshore environment especially in the petroleum industry where rigid and flexible pipes are used for well drilling and hydrocarbon production. Whereas during drilling, a mixture of drilling mud, rock cuttings and sometimes gas flows through the drilling riser, during production mono or multiphase (comprising oil, water and gas) flow takes place within the system. However up till now, most of the studies on offshore pipelines and risers have been focused on the pipe structure and its interaction with hydrodynamic forces and offshore platforms. In particular for numerical computation studies and reduced scale model experiments, the pipe is usually modeled as a tensioned beam and sometimes only the internal pressure is taken into account with other effects due to its internal flow being neglected. This paper deals with the interaction between the pipe structure and its internal flow. In order to verify the internal flow effects, an experimental analysis was carried out not using a reduced scale model. In particular, mono-phase fluid flows into the pipe and a parametric analysis using the flow rate was carried out. Discussion about the experimental results and numerical applications is also included.
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Sayed, Mohammed A., Ghaithan A. Al-Muntasheri, and Feng Liang. "Required Understanding for the Development of Shale Reservoirs in the Middle East in Light of Developments in North America." In SPE Middle East Unconventional Resources Conference and Exhibition. SPE, 2015. http://dx.doi.org/10.2118/spe-172939-ms.
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Abstract The ever-increasing international energy demands require exploration of new fossil energy resources. Unconventional oil and gas have received a great deal of attention in recent years as the technological advancements have made their production possible and more economical. Most of the shale developments took place in North America where the learning curve is being developed. Although shales still require lots of understanding and more advanced technologies, a substantial experience has been developed in North America. This paper presents an effort to summarize the current experience in shales of North America from different angles: rock mechanics, rock/fluids interaction, gas flow mechanisms through shale rocks, proppant embedment and water recovery after shale fracturing. Three prospective areas for unconventional gas were found in the Kingdom of Saudi Arabia: in the Northwest, South Ghawar and condensate-rich shale gas in the Rub' Al-Khali area. The main targeted formations for unconventional natural gas are: the Ordovician Sarah, Silurian Qulibah, Qusaiba hot shale, Devonian Jauf and Permian Unayzah formations. The Qusaiba shale is located at depths of 7,500 to 20,000 ft throughout Saudi Arabia's basins. The Qusaiba Hot Shale in the Northwest area is relatively thick and it is considered to be the richest in all possible source rocks with a maximum total organic content of 6.15%. Shales are composed of: kerogen, rock matrix and natural fractures. The mineralogy of shale varies from one field to another. Literature has confirmed that for Haynesville shale, the rock becomes more ductile with the increase in its clay content. Similar trends were seen for Lower Bakken shale. While other shale reservoirs, like Eagle Ford, Barnett and Middle Bakken are harder since they contain more quartz and calcite. The exposure of these clay-sensitive rocks to fracturing fluids does change their rock mechanical properties. This has been confirmed in literature where Middle Bakken shale lost 52% of its Young's modulus after exposure to 2 wt% KCl slickwater at 300°F for 48 hours. The use of slickwater in fracturing represents a major challenge as it consumes huge volumes of this valuable resource. Recycling of produced water has been attempted in North America in Marcellus. An average amount of 3 to 8 million gallons of water are used in fracturing one well in Marcellus shale formation. In one application, re-use of the flowback water resulted in 25% reduction in the fresh water volumes and it reduced the cost of disposing produced water by 45 to 55%. The paper presents a summary of all of these findings from North America. A comprehensive understanding and analysis on unconventional reservoirs is required for the Middle Eastern reservoirs.
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Yamamoto, Marcio, Motohiko Murai, Shotaro Uto, Tomo Fujiwara, Shigeo Kanada, Luis A. R. Quadrante, and Ken Haneda. "An Experimental Analysis of the Interaction Between Hanged Pipe and Internal Flow." In ASME 2010 29th International Conference on Ocean, Offshore and Arctic Engineering. ASMEDC, 2010. http://dx.doi.org/10.1115/omae2010-20312.
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The pipes are playing an important role in the offshore environment. Risers and pipelines are widely deployed by the petroleum industry for the well drilling and hydrocarbons production. Whereas during drilling, a mixture of drilling mud and solids in suspension (rock cuttings) flows through the drilling riser; during the production, mono or multiphase flow (comprising oil, water and gas) takes place within the production system. However up till now, most of investigations on offshore pipelines and risers have neglected the effects of the internal flow and have focused mainly on the interaction among pipe’s structure, hydro-dynamic forces and offshore platform’s motion. This paper deals with the interaction between the pipe structure and its internal flow. An experimental analysis was carried out, in the Deep Sea Basin of the National Maritime Research Institute (Japan), using a model of 10 m length. In this experiment, a mono-phase fluid of liquid and another bi-phase fluid of liquid and solids in suspension are used as the internal flow fluid and a parametric analysis using the internal flow rate and pipe’s oscillating frequency was carried out. Discussion about the experimental results is also included.
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Bordeaux Rego, Fabio, Shayan Tavassoli, Esmail Eltahan, and Kamy Sepehrnoori. "Geochemical Modeling of Petrophysical Alteration Effect on CO2 Injectivity in Carbonate Rocks." In SPE International Conference on Oilfield Chemistry. SPE, 2021. http://dx.doi.org/10.2118/204284-ms.
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Abstract Carbon dioxide injection into sedimentary formations has been widely used in enhanced oil recovery (EOR) and geological-storage projects. Several field cases have shown an increase in water injectivity during CO2 Water-Alternating-Gas (WAG) projects. Although there is consensus that the rock-fluid interaction is the main mechanism, modeling this process is still challenging. Our main goal is to validate a physically based model on experimental observations and use the validated model to predict CO2 injectivity alteration based on geochemical reactions in carbonate rocks. In this paper, we present a new method for CO2 reactive transport in porous media and its impact on injectivity. We hypothesize that if CO2 solubilizes in the connate water, then it induces a shift in chemical equilibrium that stimulates mineral dissolution. Consequently, porosity and permeability will increase, and cause alterations to well injectivity. We develop a predictive model to capture this phenomenon and validate the model against available data in the literature. We use UTCOMP-IPhreeqc, which is a fully coupled fluid-flow and geochemical simulator to account for rock/hydrocarbon/water interactions. In addition, we perform several experiments to test CO2/water slug sizes, mineralogy assembly, injected brine composition, and gravity segregation combined with the effect of heterogeneity. Coreflood simulations using chemical equilibrium and kinetics indicate mineral dissolution at reservoir conditions. The results suggest that the intensity of rock dissolution depends on formation mineralogy and brine composition as carbonate systems work as buffers. Additionally, we show that prolonged CO2 and brine injection induces petrophysical alteration close to the injection region. Our field-scale heterogeneous reservoir simulations show that permeability alteration calculated based on Carman-Kozeny correlation and wormhole formulation had the same results. Furthermore, we observed that water injectivity increased by almost 20% during subsequent cycles of CO2-WAG. This finding is also supported by the Pre-Salt carbonate field data available in the literature. In the case of continuous CO2 injection, the carbonate dissolution was considerably less severe in comparison with WAG cases, but injectivity increased due to unfavorable CO2 mobility. With the inclusion of gravity segregation, we report that the injectivity doubles in magnitude. The simulations show more extensive dissolution at the upper layers of the reservoir, suggesting that preferential paths are the main cause of this phenomenon. The ideas presented in this paper can be utilized to improve history-matching of production data and consequently reduce the uncertainty inherent to CO2-EOR and carbon sequestration projects.
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Wang, J. W., Z. Q. Qu, T. K. Guo, M. Chen, and B. Zhang. "Numerical Simulation of Hydraulic Fracturing Damage Evolution in Geothermal Reservoirs with Natural Fractures Based on THMD Coupling Model." In 56th U.S. Rock Mechanics/Geomechanics Symposium. ARMA, 2022. http://dx.doi.org/10.56952/arma-2022-0951.
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ABSTRACT: The key to develop the geothermal energy economically and effectively is forming a high quality enhanced geothermal system (EGS) with complex fracture network. Clarifying the interaction between hydraulic fracture (HF) and natural fracture (NF) is of positive significance to study how to establish an efficient EGS. In this paper, based on meso damage mechanics, elastic thermodynamics and Biot’s classical seepage mechanics, a thermo-hydro-mechanical-damage (THMD) coupling model of hydraulic fracturing in geothermal reservoir with randomly distributed NFs is established. Then the evolution of thermal field (T), seepage field (H), solid field (M) and damage (D) during hydraulic fracturing is simulated, and the effects of injection flow rates, rock thermal expansion coefficients and the NFs parameters (including length, dip angle and distribution density) on HF propagation are analyzed. The results indicate that under the action of water pressure and thermal stress, the normal stress on the NF surface will increase, resulting in the fracture damage. High injection flow rate would create longer fracture and significantly increase the fracture width, which is conducive to the development of deep thermal reservoirs. And high thermal expansion coefficient of rock is more conducive to form complex fractures. NFs will guide the HF to turn along the dip angle of NFs ,and the longer the NFs are, the stronger their guiding effect on HF. When the angle between the dip angle of NFs and the expansion direction of HF is large, the longitudinal expansion of HF is hindered, but the HF could communicate and activate more NFs. The NFs density directly determines the degree of hydraulic fracturing damage, and the damage area of HF increases with the increase of NFs density. 1. INTRODUCTION Geothermal energy is a widely distributed, low-carbon, environment-friendly and sustainable clean energy (Potten and Thuro 2017; Zhao et al. 2020). Hot Dry Rock (HDR) refers to the high-temperature rock mass with general temperature greater than 180 °C, buried depth of several kilometers, no fluid or only a small amount of underground fluid (Hofmann et al. 2014; Xu et al. 2012). As a new geothermal resource, it has advantages in geothermal energy development and application, which has attracted more and more attention. However, the HDR found at present is mainly composed of granite, showing low porosity and permeability (Lu and Wang 2015). Hydraulic fracturing technology is a mature and effective method to reconstruct low quality reservoir in oil and gas field development projects (Qu et al. 2021). This technology can be applied to HDR geothermal reservoir to realize efficient development of geothermal energy, too. Through the circulation of cold water in high-temperature rock formations with fractures, the geothermal energy is efficiently exploited. And then the high-temperature fluid will be used for step applications such as power generation or heating, which is the so-called enhanced geothermal system (EGS) (Bujakowski et al. 2015; Guo et al. 2019; Olasolo et al. 2016). Studies have shown that in the production process of EGS, the number of fractures or the complexity of fracture network will significantly affect the exploitation efficiency of geothermal energy (Guo et al. 2020b; Zhang et al. 2021; Jin et al. 2020). In order to form EGS with complex fracture networks for efficient development of geothermal energy, it is necessary to clarify the interaction between artificial fractures and natural fractures, and find out the evolution law of fracture during hydraulic fracturing.
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Lu, Feng Hu. "Using Isotope Technology to Identify Oil and Gas Reservoir Sweet Spots." In SPE Reservoir Characterisation and Simulation Conference and Exhibition. SPE, 2023. http://dx.doi.org/10.2118/212642-ms.
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Abstract Porosity and permeability of rocks are crucial parameters utilized to assess the quality of oil and gas reservoirs. Diagenesis in carbonate reservoirs commonly results in dissolution, and creates secondary porosity and permeability. At the same time, geochemical records (e.g., isotopes and elements) in the carbonate rocks are diagenetically altered. This study is to utilize the isotope technology to evaluate diagenesis and its impact on oil and gas reservoirs. Micro-samples were collected from marine carbonate rocks in a studied reservoir for carbon and oxygen isotope analyses, plus analyses of Sr isotopes and element concentrations. The analytical results show outstanding negative shifts of oxygen isotopes in some intervals, whereas carbon and strontium isotopes have a minor or little change. These intervals also contain lower element contents including strontium. It is believed that these intervals experienced diagenetic dissolution with abundant secondary porosity, and are the best potential for oil and gas reservoirs. Petrographic study indicates minor cements but higher porosity developed within these intervals. This is confirmed by high porosity measured within these intervals by using other methods including gas injection and well logging. Furthermore, the degrees of water-rock interaction were quantitively assessed by modeling covariations of isotope pairs, which can help evaluate the quality of reservoirs relating to the intensity of diagenesis. Intensive diagenesis with a high water-rock ratio particularly in a closed system may result in additional cementation, alteration of most geochemical parameters, and also reduce porosity and permeability. Thus, the isotope technology can be utilized as an effective method to assess reservoir potential and determine reservoir sweet spots. Note that carbonate cementation and recrystallization commonly occur during diagenesis, and commonly show negative oxygen isotope values. If sampling happens to contain a certain amount of cements and recrystallized carbonate minerals, the analytical results will show lower oxygen isotopes and trace elements than their primary values in the studied marine carbonates. Petrographic study was conducted to help micro-sampling, and verify that cements were not collected in the studied carbonate rocks for isotope analysis. The implementation of this study is that the isotope results obtained from one studied well can be applied in the whole field or/and the region, as diagenesis rarely occurs only around one well. This will save cost for repeatedly measurements from different wells and fields by using other methods.