Relevant bibliographies by topics / Reservoir fluids

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  1. Journal articles
  2. Dissertations / Theses
  3. Books
  4. Book chapters
  5. Conference papers
  6. Reports

Academic literature on the topic 'Reservoir fluids'

Author: Grafiati
Published: 4 June 2021
Last updated: 10 February 2022

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Journal articles on the topic "Reservoir fluids"

1

Hoffman, Monty, and James Crafton. "Multiphase flow in oil and gas reservoirs." Mountain Geologist 54, no. 1 (January 2017): 5–14. http://dx.doi.org/10.31582/rmag.mg.54.1.5.

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The porous rocks that make up oil and gas reservoirs are composed of complex combinations of pores, pore throats, and fractures. Pore networks are groups of these void spaces that are connected by pathways that have the same fluid entry pressures. Any fluid movement in pore networks will be along the pathways that require the minimum energy expenditure. After emplacement of hydrocarbons in a reservoir, fluid saturations, capillary pressure, and energy are in equilibrium, a significant amount of the reservoir energy is stored at the interface between the fluids. Any mechanism that changes the pressure, volume, chemistry, or temperature of the fluids in the reservoir results in a state of energy non-equilibrium. Existing reservoir engineering equations do not address this non-equilibrium condition, but rather assume that all reservoirs are in equilibrium. The assumption of equilibrium results in incorrect descriptions of fluid flow in energy non-equilibrium reservoirs. This, coupled with the fact that drilling-induced permeability damage is common in these reservoirs, often results in incorrect conclusions regarding the potential producibility of the well. Relative permeability damage, damage that can change which fluids are produced from a hydrocarbon reservoir, can occur even in very permeable reservoirs. Use of dependent variables in reservoir analysis does not correctly describe the physics of fluid flow in the reservoir and will lead to potentially incorrect answers regarding producibility of the reservoir.
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Li, Qing, Xue Lian You, Wen Xuan Hu, Jing Quan Zhu, and Zai Xing Jiang. "Major Controls on the Evolution of the Cambrian Dolomite Reservoirs in the Keping Area, Tarim Basin." Advanced Materials Research 734-737 (August 2013): 377–83. http://dx.doi.org/10.4028/www.scientific.net/amr.734-737.377.

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The Cambrian dolomite reservoir is an important target in oil and gas exploration. The Penglaiba section in the Keping area is typically examined in studies dealing with the Cambrian dolomite reservoirs of northwestern Tarim Basin. Based on sedimentological, petrographic, and geochemical data, lithofacies and fluids are identified as the major factors that control the dolomite reservoir in the study area. Lithoacies are fundamental to reservoir evolution because they provide suitable channels for dolomitization and dissolution of fluids that, in turn, facilitate the formation of high quality reservoirs. The lithofacies which could form high-quality reservoirs in the study area are: slope slip (collapse) facies, gypsum related facies, and algae dolomite facies. The sources of fluids include seawater, meteoric freshwater, diagenetic/hydrocarbon fluid, and hydrothermal fluid. These fluids lead to dolomitization, penecontemporaneous meteoric dissolution, hypergene dissolution, organic acid dissolution and hydrothermal dissolution that result in secondary porosity, and as such, they have a significant contribution to reservoir evolution.
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Miotti, Fabio, Andrea Zerilli, Paulo T. L. Menezes, João L. S. Crepaldi, and Adriano R. Viana. "A new petrophysical joint inversion workflow: Advancing on reservoir’s characterization challenges." Interpretation 6, no. 3 (August 1, 2018): SG33—SG39. http://dx.doi.org/10.1190/int-2017-0225.1.

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Reservoir characterization objectives are to understand the reservoir rocks and fluids through accurate measurements to help asset teams develop optimal production decisions. Within this framework, we develop a new workflow to perform petrophysical joint inversion (PJI) of seismic and controlled-source electromagnetic (CSEM) data to resolve for reservoirs properties. Our workflow uses the complementary information contained in seismic, CSEM, and well-log data to improve the reservoir’s description drastically. The advent of CSEM, measuring resistivity, brought the possibility of integrating multiphysics data within the characterization workflow, and it has the potential to significantly enhance the accuracy at which reservoir properties and saturation, in particular, can be determined. We determine the power of PJI in the retrieval of reservoir parameters through a case study, based on a deepwater oil field offshore Brazil in the Sergipe-Alagoas Basin, to augment the certainty with which reservoir lithology and fluid properties are constrained.
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Chen, Mei Tao, Ning Yang, and Shang Ming Yang. "Paleozoic Carbonate Hydrocarbon Accumulation Zones in Tahong Uplift Tarim Basin, Western China." Advanced Materials Research 403-408 (November 2011): 1511–16. http://dx.doi.org/10.4028/www.scientific.net/amr.403-408.1511.

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Analyzing the discovered carbonate reservoirs in the Tazhong area, Tarim Basin indicates that the development of a reservoir is controlled by subarial weathering and freshwater leaching processes, sedimentation, early diagenesis, and alteration by deep fluids. According to the origin and lateral distribution of reservoirs, the hydrocarbon accumulation zones in the Tazhong area are classified into four types: buried hill and palaeoweathering crust, organic buildup reef-bank, dolomite interior, and deep fluid alteration. Different types of carbonate hydrocarbon accumulation zones are distributed mainly in specific areas of the Tazhong uplift. Because of the different mechanisms of forming reservoirs in different carbonate hydrocarbon accumulation zones, the reservoir space, reservoir capability, type of reservoir and distribution of reservoirs are often different.
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Xu, Yongqiang, Linyu Liu, and Yushuang Zhu. "Characteristics of movable fluids in tight sandstone reservoir and its influencing factors: a case study of Chang 7 reservoir in the Southwestern of Ordos Basin." Journal of Petroleum Exploration and Production Technology 11, no. 9 (August 5, 2021): 3493–507. http://dx.doi.org/10.1007/s13202-021-01250-x.

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AbstractAiming at the problem of complicated occurrence and flow state of the fluid in tight sandstone reservoir, this paper takes Chang 7 reservoirs in Southwestern of Ordos Basin as an example to analyze the occurrence characteristics of movable fluids by nuclear magnetic resonance experiment, while takes a series of microscopic experiments to analyze the influencing factors of difference of movable fluids. The results show that the T2 spectrum curves of fluid-saturated samples from Chang 7 reservoirs in the study area are dominated by the unimodal shape and the left-high-peak-right-low-peak bimodal shape. After centrifugation, the T2 spectrum curves are dominated by the left-high-peak-right-low-peak bimodal shape. The average movable fluid saturation is 33.27%, and the average T2 cutoff value is 13.61 ms. The movable fluids are mainly distributed in medium and large pores, and a small amount is distributed in small pores. The occurrence characteristics of movable fluids in tight reservoirs are complex and not controlled by a single factor. The size of throats and the connectivity of pore-throat have obvious effects on the saturation of movable fluids. The small size of throats and poor connectivity of pore-throat in tight reservoirs not only restrict the fluids in micropores, but also make the fluids in macropores difficult to flow under the control of small throats. The development of clay minerals will make the pore throats smaller, more complex and have poorer connectivity, and increase the fluid seepage resistance. On the other hand, it will make the specific surface area larger, which will cause a large number of fluids adsorbed on the clay surface and difficult to flow, resulting in the reduction of movable fluid saturation.
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Ting, P. David, Birol Dindoruk, and John Ratulowski. "Numerical Investigation of Gravitational Compositional Grading in Hydrocarbon Reservoirs Using Centrifuge Data." SPE Reservoir Evaluation & Engineering 12, no. 05 (September 2, 2009): 793–802. http://dx.doi.org/10.2118/116243-pa.

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Summary Fluid properties descriptions are required for the design and implementation of petroleum production processes. Increasing numbers of deep water and subsea production systems and high-temperature/high-pressure (HTHP) reservoir fluids have elevated the importance of fluid properties in which well-count and initial rate estimates are quite crucial for development decisions. Similar to rock properties, fluid properties can vary significantly both aerially and vertically even within well-connected reservoirs. In this paper, we have studied the effects of gravitational fluid segregation using experimental data available for five live-oil and condensate systems (at pressures between 6,000 and 9,000 psi and temperatures from 68 to 200°F) considering the impact of fluid composition and phase behavior. Under isothermal conditions and in the absence of recharge, gravitational segregation will dominate. However, gravitational effects are not always significant for practical purposes. Since the predictive modeling of gravitational grading is sensitive to characterization methodology (i.e., how component properties are assigned and adjusted to match the available data and component grouping) for some reservoir-fluid systems, experimental data from a specially designed centrifuge system and analysis of such data are essential for calibration and quantification of these forces. Generally, we expect a higher degree of gravitational grading for volatile and/or near-saturated reservoir-fluid systems. Numerical studies were performed using a calibrated equation-of-state (EOS) description on the basis of fluid samples taken at selected points from each reservoir. Comparisons of measured data and calibrated model show that the EOS model qualitatively and, in many cases, quantitatively described the observed equilibrium fluid grading behavior of the fluids tested. First, equipment was calibrated using synthetic fluid systems as shown in Ratulowski et al. (2003). Then real reservoir fluids were used ranging from black oils to condensates [properties ranging from 27°API and 1,000 scf/stb gas/oil ratio (GOR) to 57°API and 27,000 scf/stb GOR]. Diagnostic plots on the basis of bulk fluid properties for reservoir fluid equilibrium grading tendencies have been constructed on the basis of interpreted results, and sensitivities to model parameters estimated. The use of centrifuge data was investigated as an additional fluid characterization tool (in addition to composition and bulk phase behavior properties) to construct more realistic reservoir fluid models for graded reservoirs (or reservoirs with high grading potential) have also been investigated.
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Lee, Ji Ho, and Kun Sang Lee. "Multiphase, Multicomponent Simulation for Flow and Transport during Polymer Flood under Various Wettability Conditions." Journal of Applied Mathematics 2013 (2013): 1–8. http://dx.doi.org/10.1155/2013/101670.

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Accurate assessment of polymer flood requires the understanding of flow and transport of fluids involved in the process under different wettability of reservoirs. Because variations in relative permeability and capillary pressure induced from different wettability control the distribution and flow of fluids in the reservoirs, the performance of polymer flood depends on reservoir wettability. A multiphase, multicomponent reservoir simulator, which covers three-dimensional fluid flow and mass transport, is used to investigate the effects of wettability on the flow process during polymer flood. Results of polymer flood are compared with those of waterflood to evaluate how much polymer flood improves the oil recovery and water-oil ratio. When polymer flood is applied to water-wet and oil-wet reservoirs, the appearance of influence is delayed for oil-wet reservoirs compared with water-wet reservoirs due to unfavorable mobility ratio. In spite of the delay, significant improvement in oil recovery is obtained for oil-wet reservoirs. With respect to water production, polymer flood leads to substantial reduction for oil-wet reservoirs compared with water-wet reservoirs. Moreover, application of polymer flood for oil-wet reservoirs extends productive period which is longer than water-wet reservoir case.
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Warnecki, Marcin, Mirosław Wojnicki, Jerzy Kuśnierczyk, and Sławomir Szuflita. "Analizy PVT jako skuteczne narzędzie w rękach inżyniera naftowego. Pobór wgłębnych próbek płynów złożowych do badań PVT." Nafta-Gaz 76, no. 11 (November 2020): 784–93. http://dx.doi.org/10.18668/ng.2020.11.03.

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The most important aspect of laboratory analysis is undoubtedly to acquire data of the highest quality. The worldwide trend of drilling into deeper reservoirs characterised by the high temperature and high pressure (HTHP) conditions makes the newly discovered reservoirs challenging because of bearing fluids with an unprecedented diversity of phase behaviour and variability of phase parameters over time. Due to the high temperature of the deep horizons constituting the reservoir rock, many individual components of the reservoir fluids are located in a region close to their critical temperatures, i.e. gas condensate (retrograde condensation region) or volatile oil. In particular, gas condensate reservoirs are challenging to analyse. They are highly prone to the errors resulting from phase behaviour testing when using samples that are incompatible with the original reservoir in-situ fluid that saturates the reservoir rock pores. Taking the representative samples of reservoir fluid is an essential requirement to obtain reliable data that can characterise such phase-variable multicomponent reservoirs. The primary purpose of hydrocarbon fluid analysis in case of new discoveries is to determine the type of reservoir fluid system. It should also be borne in mind that without a sufficiently long production process from several intervals and/or several wells, it can be challenging to classify the fluid with confidence, especially at the initial analysis stage. The paper presents issues related to sampling of the reservoir fluid (such as crude oil and natural gas) for the physical property and phase behaviour analyses (PVT), usually accompanied by chemical analyses. The importance of representativeness of the samples in performing reliable tests that have a significant impact on the hydrocarbon production was discussed. The data obtained from the PVT laboratory are widely used in economic reports concerning local, regional or finally national hydrocarbon reserves. Other applications of the PVT data include coordination of reservoir exploitation methods related to a particular fluid composition, as well as input to design requirements for the surface facilities development, and selection of the suitable technology for hydrocarbon fluid treatment prior to introduction to the market. Various techniques of downhole sampling were mentioned and characterised with an explanation of their applicability. The criteria for selection of a proper method were also presented.
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Li, Fang Fang, Sheng Lai Yang, Dan Dan Yin, Hao Chen, Hui Lu, and Xing Zhang. "Estimation of CO2-Oil Phase Equilibrium and CO2 Storage Capacity in Jilin Oil Field." Advanced Materials Research 524-527 (May 2012): 1802–6. http://dx.doi.org/10.4028/www.scientific.net/amr.524-527.1802.

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The CO2EOR and Storage Project in Jilin oilfield is the first large CCS demonstration project in China for CO2geological storage into depleting oil reservoirs. It aims at enhancing the understanding of CO2EOR mechanisms, movement of CO2in the reservoir and relevant physical-chemical reactions involved in the storage process, meanwhile gaining practical experience of monitoring and verification of CO2storage technology in tight oil reservoirs. To have a better understanding of the naturally occurring and phase transformation between CO2and reservoir fluid and provide accurate data for designing an oil development plan, we must know the interactions between CO2and reservoir fluids. Hence, in the first part of this paper the CO2and reservoir fluid phase equilibrium is measured with laboratory experiment, then the collected data is used to calculate the theory and practical CO2Sequestration capacities.
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Zhu, X., and G. A. McMechan. "Numerical simulation of seismic responses of poroelastic reservoirs using Biot theory." GEOPHYSICS 56, no. 3 (March 1991): 328–39. http://dx.doi.org/10.1190/1.1443047.

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Biot theory proSvides a framework for computing the seismic response of fluid‐saturated reservoirs. Numerical implementation by 2-D finite‐differences allows investigation of the effects of spatial variations in porosity, permeability, and fluid viscosity, on seismic displacements of the solid frame and of the fluids (oil, gas, and/or water) in the reservoir. The porosity primarily influences wave velocities; the viscosity‐to‐permeability ratio primarily influences amplitudes and attenuation. Synthetic crosswell, VSP, and surface survey seismograms for representative reservoir models contain primary and converted reflections from fluid as well as lithologic contacts, and they illustrate the distribution of information available for describing a reservoir.
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Dissertations / Theses on the topic "Reservoir fluids"

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Dandekar, Abhijit Yeshwant. "Interfacial tension and viscosity of reservoir fluids." Thesis, Heriot-Watt University, 1994. http://hdl.handle.net/10399/1397.

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Li, Xuesong. "Interfacial properties of reservoir fluids and rocks." Thesis, Imperial College London, 2013. http://hdl.handle.net/10044/1/14380.

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Interfacial phenomena between CO2, brines or hydrocarbon, and carbonate rocks were investigated with the aim of understanding key aspects on CO2 storage and enhanced oil recovery (EOR) in carbonate reservoirs. The interfacial tensions between brines and CO2 were studied systematically with variation of the salt type and concentration under conditions applicable to the field. The results of the study indicate that, for strong electrolytes, the interfacial tension increases linearly with the positive charge concentration. Empirical models have been developed that represent the results as a function of temperature, pressure and molality with the small absolute average relative deviation of about 2 %. The interfacial tension measured between brine and crude oils indicated that interfacial tension has a strong dependence on both the viscosity of crude oil and the salinity of the brine. Molecular dynamics (MD) simulations of interfacial tension between water or brine and CO2 were carried out to investigate microscopic interfacial phenomena and to further understand the dependence of interfacial tension on temperature, pressure, and brine salinity. The simulation results were consistent with the experimental data obtained in this study. In particular, the simulations showed that the interfacial tension is linearly dependent on the positive charge concentration for strong electrolytes, most likely due to desorption of ions on the interface between brine and CO2. The contact angle of brine and crude oil on carbonate rocks was measured at both ambient and reservoir conditions. The results indicate that brine salinity has a strong effect on the wettability of the carbonate rock surface. This thesis provided the first attempt to explain the low salinity effect from the interactions between brine and rocks. Contact angle results and wettability index gathered from the NMR and Amott approaches measured on porous rocks were compared and found to be correlated in (crude oil + brine + calcite) systems at ambient condition. Molecular dynamics simulations of contact angle were carried out to give a deeper understanding of the underlying mechanism of the effect of brine salinity on wettabilty. Together with the experimental evidence, it can be concluded that increasing the salinity of brine results in an increase of the interfacial tension between calcite and brine. This is the first attempt to simulate contact angles by IFT simulations. Over all, interfacial phenomena between reservoir rocks and fluids were investigated by interfacial tension and contact angle measurement and by molecular simulation. Based on the wide range of experimental and simulation data obtained, this thesis provides a near complete understanding of the brine and CO2 interfacial behaviour under reservoir conditions. The empirical models obtained can predict reliably essentially any interfacial tension between brine and CO2 at reservoir conditions with given brine composition, temperature and pressure. MD simulations together with the experimental evidence, indicate that reducing the salinity of brine generally reduces the adhesion tension of crude oil in brine and calcite system. Thus proving that low salinity water flooding could potentially increase oil recovery from carbonate reservoir. More generally, low salinity aquifers are found to be more favourable for CO2 trapping.
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Ivakhnenko, Oleksandr Petrovych. "Magnetic analysis of petroleum reservoir fluids, matrix mineral assemblages and fluid-rock interactions." Thesis, Heriot-Watt University, 2006. http://hdl.handle.net/10399/140.

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Calabrese, Claudio. "Viscosity and density of reservoir fluids with dissolved CO2." Thesis, Imperial College London, 2017. http://hdl.handle.net/10044/1/61899.

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The viscosity and density of a range of aqueous and hydrocarbon reservoir fluids, with and without dissolved CO2, have been studied at high temperature and high pressure conditions. The findings of this research can be applied to the oil and gas industry, for instance to design and operate enhanced oil recovery (EOR) processes using CO2 and large-scale carbon storage in depleted hydrocarbon reservoirs or deep saline aquifers. In this work, the viscosity was measured by means of a vibrating-wire (VW) viscometer while the density was measured with a vibrating U-tube (VT) densimeter. The simultaneous measurements of viscosity and density were carried out in the single-phase compressed liquid region at temperatures between (273 and 466) K and pressures up to 100 MPa. In addition, density measurements were made for four hydraulic fluids up to a maximum pressure of 135 MPa. The viscosity and density measurements of NaCl(aq) and CaCl2(aq) brines under CO2 addition were made at salt molalities of 0.77 mol·kg-1 and 1.00 mol·kg-1, respectively. Additional density measurements were also made for the [CO2 + NaCl(aq) or CaCl2(aq)] systems at salt molalities of 2.50 mol·kg-1. To enable the viscosity measurements, a key contribution of this work was the development of a new modification of the working equation of the VW viscometer which takes into account the electrical conductivity of these brines, and hence expanded the use of this precise technique to an entire new class of conductive fluids. The results for the viscosity and density were correlated as functions of temperature, pressure and the mole fraction of dissolved CO2. For viscosity, a simple modification of the Vogel-Fulcher-Tamman equation was employed while, for density, an equation based on the partial molar volume of CO2(aq) and the molar volume of the CO2-free aqueous solution was used. The viscosity and density of two synthetic crude oil mixtures with dissolved CO2 were also measured. The synthetic dead oil contained a total of 17 components including linear and branched alkanes, cyclo-alkanes and aromatics. A live oil with a gas-to-oil ratio of 58 was obtained from this dead oil by adding solution gas (CH4 + C2H6 + C3H8). For the synthetic dead oil, the mole fractions of dissolved CO2 were x = (0.0, 0.1, 0.2, 0.4, 0.6 and 1.0). The investigated CO2 mole fractions for the synthetic live oil mixture were x = (0.0, 0.1, 0.2 and 0.4). The experimental viscosity and density data were correlated at each CO2 mole fraction as a function of temperature and pressure. A modified Tait equation was used to correlate the densities, while an empirical equation was used for modelling the viscosity of the (CO2 + synthetic crude oil) mixtures. Accurate viscosity and density data were then gathered for two synthetic paraffinic mixtures in order to validate the Vesovic-Wakeham (VW) predictive method for these complex mixtures over a wide range of temperature and pressure, at viscosities up to 2.5 mPa∙s. The two mixtures were referred to as oil #1 and oil #2 and contained a total of 10 and 5 liquid normal alkane components, respectively. The selection criteria for these components were based on the distribution of single carbon number (SCN) of a real light stock tank oil with a molecular weight of 184 g∙mol-1 and density of about 867 kg∙m-3. The mole fraction of C7+ in both mixtures was constrained to 0.9. n-alkane mixtures were chosen because they represent the simplest system to investigate for developing a generic predictive model applicable to more complex and heavy synthetic crude oils. The VW model was able to represent the viscosities of both mixtures with an absolute average deviation of 5 %. The positive results of this work on n-alkane mixtures is an essential precursor for the application of the VW model to more complex fluids encountered in the petrochemical industry. The density of four hydraulic fluids were also studied to test the correlative capability of the modified Tait equation over wide ranges of temperature and pressure. In this case, a correlative approach was preferred to a predictive model because the chemical composition of the above-mentioned fluids was unknown. The modified Tait equation fitted well the experimental density data and was successfully employed to extrapolate densities at 473.15 K, at pressures from (0.1 to 135) MPa. The accurate correlative power of the modified Tait equation over wide ranges of temperature and pressure can be exploited for improving the performance and design of motors and pumps which make use of hydraulic fluids. The results presented in this thesis were carried out as part of the Qatar Carbonates and Carbon Storage Research Centre (QCCSRC) program. The work extends the knowledge of the viscosity and density of reservoir fluids under CO2 addition at higher pressures and temperatures compared to the existing available data in the literature. In addition, it also provides purely empirical or semi-theoretical models which are able to determine the viscosity and density of reservoir fluids with dissolved CO2 with satisfactory accuracies for industrial applications. However, additional research is needed in this field, and for this reason, further experimental investigations have been identified and suggested.
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Chow, Yu Tsing Florence. "Interfacial properties of reservoir fluids and carbon dioxide with impurities." Thesis, Imperial College London, 2016. http://hdl.handle.net/10044/1/44376.

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Interfacial tension measurements of the binary systems (N2 + H2O), (Ar + H2O), and (H2 + H2O), and ternary systems (CO2 + N2 + H2O), (CO2 + Ar + H2O) and (CO2 + H2 + H2O), are reported at pressures of (0.5 to 50.0) MPa, and temperatures of (298.15 to 473.15) K. The design of a custom-built Interfacial Properties Rig was detailed. The pendant drop method was used. The expanded uncertainties at 95% confidence are 0.05 K for temperature; 0.07 MPa for pressure; 0.019·γ for interfacial tension in the (N2 + H2O) system; 0.016·γ for interfacial tension in the (Ar + H2O) system; 0.017·γ for interfacial tension in the (H2 + H2O) system; 0.032·γ for interfacial tension in the (CO2 + N2 + H2O) system; 0.018·γ for interfacial tension in the (CO2 + Ar + H2O) system; and 0.017·γ for interfacial tension in the (CO2 + H2 + H2O) system. The interfacial tensions of all systems were found to decrease with increasing pressure. The use of SGT + SAFT-VR Mie to model interfacial tensions of the binary and ternary systems was reported, for systems involving CO2, N2 and Ar. The binary systems (N2 + H2O) and (Ar + H2O), and ternary systems (CO2 + N2 + H2O) and (CO2 + Ar + H2O), were modelled with average absolute relative deviations of 1.5 %, 1.8 %, 3.6 % and 7.9 % respectively. For the (CO2 + Ar + H2O) system, the agreement is satisfactory at the higher temperatures, but differs significantly at the lower temperatures. Contact angles of (CO2 + brine) and (CO2 + N2 + brine) systems on calcite surfaces have also been measured, at 333 K and 7 pressures, from (2 to 50) MPa, for a 1 mol·kg-1 NaHCO3 brine solution, using the static method on captive bubbles.
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Kashefi, Khalil. "Measurement and modelling of interfacial tension and viscosity of reservoir fluids." Thesis, Heriot-Watt University, 2012. http://hdl.handle.net/10399/2567.

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The knowledge of reservoir fluids physical properties is crucial in upstream and downstream processes of petroleum industry. Viscosity and interfacial tension are among the most influential parameters on fluid behaviour. These properties have considerable effects on fluid flow characteristics and consequently in many oil and gas production and processing aspects from porous media to surface facilities. Hence, accurate estimation of the mentioned fluid properties plays a significant role in reservoir development. However, experimental data are scarce at high pressure and high temperature (HPHT) conditions. The work presented in this thesis is an integrated experimental and modelling investigation of viscosity and interfacial tension of petroleum reservoir fluids over a wide range of pressure and temperature conditions. Several series of experimental data on the viscosity of reservoir fluids were generated at high pressure and high temperature conditions (up to 20,000 psia and 200 °C). Experiments were conducted on three binary hydrocarbon systems and three synthetic and real multi-component mixtures, in addition to investigating the effect of dissolved water on the viscosity of the above fluids. Besides, the influence of oil-based mud filtrate on the viscosity of various dead oil samples also was studied as part of this thesis. The effect of different salt concentrations on the interfacial tension of gas-brine systems over a wide range of pressure and temperature conditions also was studied experimentally. The experimental data generated were employed to evaluate, improve and propose predictive models to estimate the mentioned physical properties. A new approach to retrieve the viscosity of original fluid (clean dead oil) from contaminated sample was introduced. Also a novel technique for predicting the gas-water (brine) interfacial tension was outlined. The proposed techniques and models were evaluated against independent experimental data generated in this work and the data gathered from open sources. Predictions of the developed methods were in good agreement with the experimental data.
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Pereira, Luís M. C. "Interfacial tension of reservoir fluids : an integrated experimental and modelling investigation." Thesis, Heriot-Watt University, 2016. http://hdl.handle.net/10399/3207.

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Interfacial tension (IFT) is a property of paramount importance in many technical areas as it deals with the forces acting at the interface whenever two immiscible or partially miscible phases are in contact. With respect to petroleum engineering operations, it influences most, if not all, multiphase processes associated with the extraction and refining of Oil and Gas, from the optimisation of reservoir engineering strategies to the design of petrochemical facilities. This property is also of key importance for the development of successful and economical CO2 geological storage projects as it controls, to a large extent, the amount of CO2 that can be safely stored in a target reservoir. Therefore, an accurate knowledge of the IFT of reservoir fluids is needed. Aiming at filling the experimental gap found in literature and extending the measurement of this property to reservoir conditions, the present work contributes with fundamental IFT data of binary and multicomponent synthetic reservoir fluids. Two new setups have been developed, validated and used to study the impact of high pressures (up to 69 MPa) and high temperatures (up to 469 K) on the IFT of hydrocarbon systems including n-alkanes and main gas components such as CH4, CO2, and N2, as well as of the effect sparingly soluble gaseous impurities and NaCl on the IFT of water and CO2 systems. Saturated density data of the phases, required to determine pertinent IFT values, have also been measured with a vibrating U-tube densitometer. Results indicated a strong dependence of the IFT values with temperature, pressure, phase density and salt concentration, whereas changes on the IFT due to the presence of up to 10 mole% gaseous impurities (sparingly soluble in water) laid very close to experimental uncertainties. Additionally, the predictive capabilities of classical methods for computing IFT values have been compared to a more robust theoretical approach, the Density Gradient Theory (DGT), as well as to experimental data measured in this work and collected from literature. Results demonstrated the superior capabilities of the DGT for accurately predicting the IFT of synthetic hydrocarbon mixtures and of a real petroleum fluid with no further adjustable parameters for mixtures. In the case of aqueous systems, one binary interaction coefficient, estimated with the help of a single experimental data point, allowed the correct description of the IFT of binary and multicomponent systems in both two- and three-phase equilibria conditions, as well as the impact of salts with the DGT.
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Bayreuther, Moritz, Jamin Cristall, and Felix J. Herrmann. "Curvelet denoising of 4d seismic." European Association of Geoscientists and Engineers, 2004. http://hdl.handle.net/2429/453.

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With burgeoning world demand and a limited rate of discovery of new reserves, there is increasing impetus upon the industry to optimize recovery from already existing fields. 4D, or time-lapse, seismic imaging is an emerging technology that holds great promise to better monitor and optimise reservoir production. The basic idea behind 4D seismic is that when multiple 3D surveys are acquired at separate calendar times over a producing field, the reservoir geology will not change from survey to survey but the state of the reservoir fluids will change. Thus, taking the difference between two 3D surveys should remove the static geologic contribution to the data and isolate the timevarying fluid flow component. However, a major challenge in 4D seismic is that acquisition and processing differences between 3D surveys often overshadow the changes caused by fluid flow. This problem is compounded when 4D effects are sought to be derived from vintage 3D data sets that were not originally acquired with 4D in mind. The goal of this study is to remove the acquisition and imaging artefacts from a 4D seismic difference cube using Curvelet processing techniques.
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Eriksen, Daniel. "Molecular-based approaches to modelling carbonate-reservoir fluids : electrolyte phase equilibria, and the description of the fluid-fluid interface." Thesis, Imperial College London, 2017. http://hdl.handle.net/10044/1/49242.

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In this thesis, a new approach to parameterization of the intermolecular potential models of ionic species in electrolyte solutions for the SAFT-VRE Mie theory is presented. Additionally, a predictive approach to the description of the fluid-fluid interface of non-electrolytic, non-associating mixtures is presented. These approaches are intended to support an integrated workflow for the study of the fluid systems relevant for carbon capture and sequestration. The parameterization methodology developed for the intermolecular potential models of ionic species in the SAFT-VRE Mie theory reduces the parameters to be estimated from solution data to a single interaction-energy per solvent-ion pair. This is achieved through the use of literature values for the ion-size parameter, and theoretical estimates for the ion-ion interaction energy. Additionally, the Born diameters of the ion models are taken to be those of Rashin and Honig, and not estimated from data. This approach is applied to the monovalent halides as well as select divalent ions. The resulting models reproduce the solvation energy in H2O to within 5 % error at standard conditions for the monovalent halides. Furthermore, the electrolyte models are demonstrated to provide a fair description of aqueous electrolytes when considering the limited parameterization. The predictive description of the fluid-fluid interface, is achieved by an approach in which the Square Gradient Theory (SGT) and the SAFT-VR Mie EOS are combined. The SGT influence parameter is mapped to the SAFT-VR Mie intermolecular model parameters through the relationship with the direct correlation function. The resulting model is parametrized by matching simulation data for the interfacial tension of λr-6 Mie monomeric fluids. A final evaluation of the model is carried out against non-associating systems of up to 4 species, for which predictive capabilities are demonstrated.
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Al, Ghafri Saif. "Phase behaviour and physical properties of reservoir fluids under addition of carbon dioxide." Thesis, Imperial College London, 2014. http://hdl.handle.net/10044/1/19007.

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The phase behaviour of reservoir fluids under the addition of carbon dioxide (CO2) were studied at elevated pressures and temperatures similar to those encountered in enhanced oil recovery (EOR) and carbon storage processes. The principal focus of the work presented in this thesis is the experimental investigation of the phase behaviour of these CO2 mixtures with hydrocarbon reservoir fluids. For this purpose, a new high-pressure high-temperature apparatus was designed and constructed. The apparatus consisted of a thermostated variable-volume view cell driven by a computer-controlled servo motor system. The maximum operating pressure and temperature were 40 MPa and 473.15 K, respectively. Measurements were then made over a wide range of pressure and temperature conditions for two representative CO2-hydrocarbon systems: (CO2 + n-heptane + methylbenzene) and (CO2 + synthetic crude oil). The vapour-liquid phase behaviour of the former system was studied, under CO2 addition and various molar ratios of n-heptane to methylbenzene, along different isotherms at temperatures between (298 and 473) K and at pressures up to approximately 16 MPa. In the latter, the synthetic oil contained a total of 17 components while solution gas (methane, ethane and propane) was added to obtain live synthetic crudes with gas-oil ratios of either 58 or 160. Phase equilibrium and density measurements were then made for the ‘dead’ oil and the two ‘live’ oils under the addition of CO2. The measurements were carried out at temperatures between (298.15 and 423.15) K and at pressures up to 36 MPa, and included vapour-liquid, liquid-liquid and vapour-liquid-liquid equilibrium conditions. The phase equilibria of (carbon dioxide + n-heptane + water) and (carbon dioxide + methane + water) mixtures were also studied using a high pressure quasi-static analytical apparatus with on-line compositional analysis by gas chromatography. The former system was studied under conditions of three-phase equilibria along five isotherms at temperatures from (323.15 to 413.15) K and at pressures up to the upper critical end point (UCEP). In the latter system, compositions of three coexisting fluid phases have been obtained along eight isotherms at temperatures from (285.15 to 303.5) K and at pressures up to either the UCEP or up to the hydrate formation locus. Compositions of coexisting vapour and liquid phases have been obtained along three isotherms at temperatures from (323.15 to 423.15) K and pressures up to 20 MPa for mixtures containing nearly equal overall mole fractions of CH4 and CO2. The quadruple curve along which hydrate coexists with the three fluid phases was also measured. A detailed study of these ternary mixtures was carried out based on comparison with available ternary data of the type (CO2 + n-alkane + water) and available data for the constituent binary subsystems. In this way, we analyze the observed effects on the solubility when the n-alkane component was changed or a third component was added. The experimental data for the (CO2 + hydrocarbon) systems have been compared with results calculated with two predictive models, PPR78 and PR2SRK, based on Peng-Robinson 78 (PR78) and Soave-Redlich-Kwong (SRK) cubic equations of state (EoS) with group-contribution formula for the binary interaction parameters and with the use of different alpha functions. Careful attention was paid to the critical constants and acentric factor of high molar-mass components. The use of the Boston-Mathias modification of the PR78 and SRK equations was also investigated. The experimental data obtained for the (CO2 + n-heptane + methylbenzene) mixture were also compared with the predictions made using SAFT-Gamma-Mie, a group-contribution version of the Statistical Associating Fluid Theory (SAFT), which was implemented with the generalized Mie potential to represent segment-segment interactions. Detailed assessment of the predictive capability of these models concluded that the agreement between the experimental data and prediction from these methods, while not perfect, is very good, especially on the bubble curve. The results suggest that there is merit in the approach of combining these methods with a group-contribution scheme. Comparison between these approaches concluded that they all have comparable accuracies regarding VLE calculations. The experimental data obtained for the ternary mixtures (CO2 + n-alkane + water) have been compared with the predictions of SAFT for potentials of variable range (SAFT-VR), implemented with the square-well (SW) potential using parameters fitted to experimental pure-component and binary-mixture data. A good performance of the SAFT-VR equation in predicting the phase behaviour at different temperatures was observed even with the use of temperature-independent binary interaction parameters. It was also observed that an accurate prediction of phase behaviour at conditions close to criticality cannot be accomplished by mean-field based theories, such as the models used in this work, that do not incorporate long-range density fluctuations. Density measurements on a variety of brines (both single-salt and mixed) were studied in the present work within the context of CO2 storage processes in saline aquifers. Densities of MgCl2(aq), CaCl2(aq), KI(aq), NaCl(aq), KCl(aq), AlCl3(aq), SrCl2(aq), Na2SO4(aq), NaHCO3(aq) , the mixed salt system [(1 – x) NaCl + xKCl](aq) and the synthetic reservoir brine system [x1NaCl + x2KCl + x3MgCl2 + x4CaCl2 + x5SrCl2 + x6Na2SO4 + x7NaHCO3](aq), where x denotes mole fraction, were studied at temperatures between (283 and 473) K and pressures up to 68.5 MPa. The measurements were performed with a vibrating-tube densimeter calibrated under vacuum and with pure water over the full ranges of pressure and temperature investigated. It was observed that careful attention needs to be paid to the type of calibration method selected. An empirical correlation is reported that represents the density for each brine system as a function of temperature, pressure and molality with absolute average relative deviations (%AAD) of approximately 0.02 %. Comparing the model with a large database of results from the literature suggested that the model is in good agreement with most of the available data. The model can be used to calculate density, apparent molar volume and isothermal compressibility of single component salt solutions over the full ranges of temperature, pressure and molality studied. An ideal mixing rule for the density of a mixed electrolyte solution was tested against our mixed salts data and was found to offer good predictions at all conditions studied with an absolute average relative deviation of 0.05 %. The present work was carried out as part of the Qatar Carbonates and Carbon Storage Research Centre (QCCSRC) program. It covered a wide range of phase behaviour and density measurements at conditions relevant to oil and gas fields’ applications, and explored the predictive capabilities of some available models, in particular predictive cubic EoS, SAFT-VR and SAFT-Gamma-Mie. The research and data collected represents a good step in enabling the direct design and optimisation of CO2-EOR and carbon storage processes. An example is the validation of the predictive models and the determination of the miscibility pressure which is essential for effective recovery of the heavy hydrocarbons. Areas in which the research might be extended, both through further experimental studies and improved modelling, have been identified.
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Books on the topic "Reservoir fluids"

1

L, Christensen Peter, ed. Phase behavior of petroleum reservoir fluids. Boca Raton: CRC/Taylor & Francis, 2007.

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1955-, Spivey John Paul, and Lenn Christopher P, eds. Petroleum reservoir fluid property correlations. Tulsa, Okla: PennWell Corp., 2010.

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The physics of reservoir fluids: Discovery through downhole fluid analysis. Sugar Land, Tex: Schlumberger, 2008.

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PVT and phase behaviour of petroleum reservoir fluids. Amsterdam: Elsevier, 1998.

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The properties of petroleum fluids. 2nd ed. Tulsa, Okla: PennWell Books, 1990.

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Ahmed, Tarek H. Working guide to reservoir rock properties and fluid flow. Amsterdam: Elsevier, 2010.

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D, McKinney Paul, ed. Advanced reservoir engineering. Boston: Gulf Professional Pub., 2005.

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Petroleum reservoir rock and fluid properties. Boca Raton: Taylor & Francis, 2006.

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Kerimov, V. I︠U︡. (Vagif I︠U︡nus ogly) and Gorfunkel Michael V, eds. Fluid dynamics of oil and gas reservoirs. Hoboken, New Jersey: Scrivener Publishing/Wiley, 2015.

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Rachinsky, M. Z., and V. Y. Kerimov. Fluid Dynamics of Oil and Gas Reservoirs. Hoboken, NJ, USA: John Wiley & Sons, Inc., 2015. http://dx.doi.org/10.1002/9781118999004.

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Book chapters on the topic "Reservoir fluids"

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Chierici, Gian Luigi. "Reservoir Fluids." In Principles of Petroleum Reservoir Engineering, 17–46. Berlin, Heidelberg: Springer Berlin Heidelberg, 1994. http://dx.doi.org/10.1007/978-3-662-02964-0_2.

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Archer, J. S., and C. G. Wall. "Properties of Reservoir Fluids." In Petroleum Engineering, 40–61. Dordrecht: Springer Netherlands, 1986. http://dx.doi.org/10.1007/978-94-010-9601-0_4.

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Yang, Shenglai. "Physical Properties of Reservoir Fluids Under Reservoir Conditions." In Fundamentals of Petrophysics, 135–77. Berlin, Heidelberg: Springer Berlin Heidelberg, 2017. http://dx.doi.org/10.1007/978-3-662-55029-8_4.

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Yang, Shenglai. "Physical Properties of Reservoir Fluids Under Reservoir Conditions." In Fundamentals of Petrophysics, 135–77. Berlin, Heidelberg: Springer Berlin Heidelberg, 2016. http://dx.doi.org/10.1007/978-3-662-53529-5_4.

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Sinha, Mihir K., and Larry R. Padgett. "Physical Properties of Reservoir Hydrocarbon Fluids." In Reservoir Engineering Techniques Using Fortran, 3–11. Dordrecht: Springer Netherlands, 1985. http://dx.doi.org/10.1007/978-94-009-5293-5_1.

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Hu, Xuetao. "The Physical Properties of Reservoir Fluids." In Physics of Petroleum Reservoirs, 165–324. Berlin, Heidelberg: Springer Berlin Heidelberg, 2017. http://dx.doi.org/10.1007/978-3-662-55026-7_3.

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Hu, Xuetao. "The Physical Properties of Reservoir Fluids." In Physics of Petroleum Reservoirs, 165–324. Berlin, Heidelberg: Springer Berlin Heidelberg, 2016. http://dx.doi.org/10.1007/978-3-662-53284-3_3.

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Chierici, Gian Luigi. "Radial Flow Through Porous Media: Slightly Compressible Fluids." In Principles of Petroleum Reservoir Engineering, 139–66. Berlin, Heidelberg: Springer Berlin Heidelberg, 1994. http://dx.doi.org/10.1007/978-3-662-02964-0_5.

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Yang, Shenglai. "Chemical Composition and Properties of Reservoir Fluids." In Fundamentals of Petrophysics, 3–26. Berlin, Heidelberg: Springer Berlin Heidelberg, 2017. http://dx.doi.org/10.1007/978-3-662-55029-8_1.

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Yang, Shenglai. "Chemical Composition and Properties of Reservoir Fluids." In Fundamentals of Petrophysics, 3–26. Berlin, Heidelberg: Springer Berlin Heidelberg, 2016. http://dx.doi.org/10.1007/978-3-662-53529-5_1.

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Conference papers on the topic "Reservoir fluids"

1

Couples, G. D., H. Lewis, M. A. Reynolds, G. E. Pickup, J. Ma, M. Rouainia, N. Bicanic, and C. J. Pearce. "Upscaling Fluid-Flow and Geomechanical Properties in Coupled Matrix+Fractures+Fluids Systems." In SPE Reservoir Simulation Symposium. Society of Petroleum Engineers, 2003. http://dx.doi.org/10.2118/79696-ms.

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Khan, Sikandar, Yehia Khulief, and Abdullatif Al-Shuhail. "Reservoir Geomechanical Modeling and Ground Uplift During CO2 Injection Into Khuff Reservoir." In ASME-JSME-KSME 2019 8th Joint Fluids Engineering Conference. American Society of Mechanical Engineers, 2019. http://dx.doi.org/10.1115/ajkfluids2019-4809.

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Abstract In this investigation, coupled-geomechanical modeling is performed using the COMSOL Multiphysics software, during carbon dioxide injection into the deep Khuff carbonate reservoir. Khuff reservoir is a carbonate reservoir that is capped by the low permeability Sudair shale geological layer. The main objective of the study was to evaluate safe values of the carbon dioxide injection parameters for the Khuff reservoir that will act as a benchmark for the similar reservoirs and injection scenarios around the globe. Carbon dioxide was injected for a period of 10 years into the reservoir and the corresponding variations in the reservoir pore-pressure and ground uplift was evaluated. The Mohr-Coulomb failure criterion was utilized to perform the stability analysis for the Khuff reservoir during carbon dioxide injection.
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Stone, Terry Wayne, and James S. Nolen. "Practical and Robust Isenthalpic/Isothermal Flashes for Thermal Fluids." In SPE Reservoir Simulation Symposium. Society of Petroleum Engineers, 2009. http://dx.doi.org/10.2118/118893-ms.

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Qiao, Changhe, Saeid Khorsandi, and Russell T. Johns. "A General Purpose Reservoir Simulation Framework for Multiphase Multicomponent Reactive Fluids." In SPE Reservoir Simulation Conference. Society of Petroleum Engineers, 2017. http://dx.doi.org/10.2118/182715-ms.

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Perez, G., A. K. Chopra, and C. D. Severson. "Enhanced Geostatistical Mapping of Reservoir Fluids." In International Meeting on Petroleum Engineering. Society of Petroleum Engineers, 1995. http://dx.doi.org/10.2118/29964-ms.

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Dehghan, Ali A. "An Experimental Investigation of Thermal Stratification in an Underground Water Reservoir." In ASME 2004 Heat Transfer/Fluids Engineering Summer Conference. ASMEDC, 2004. http://dx.doi.org/10.1115/ht-fed2004-56784.

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Temperature stratification in a long-term underground water reservoir was studied experimentally. The cold water storage tank, which was selected for this study, is an underground water reservoir with a domed shape roof and equipped with wind towers (Baad-Gir) which are responsible for capturing wind from any direction and inducing airflow over the water surface. These historic reservoirs were used as a source of drinking cold water in hot arid central regions of Iran during hot and dry summer season. The cylindrical shape underground reservoir, with 12m in height and 12m in diameter, was filled with 15°C water from a nearby well in winter. Temperature data were taken every ten days from late April until mid-October. To obtain accurate experimental temperature data, water layers temperature was measured in vertical direction whilst cold water was extracted from bottom of the tank on a daily basis at a rate corresponding to the regional inhabitants water consumption. It was observed that stable thermal stratification was developed after charging the reservoir. The temperature of extracted water was in the range of 11.9–13.1 °C during the entire summer period whilst the outside ambient temperature was reached upto 42 °C. It is believed that the radiation heat exchange between the water surface and the storage ceiling, as well as the convective heat and mass transfer from the surface of water induced by airflow were primarily responsible for temperature profile change. However, the discharged water flow rate had a secondary effect on thermal stratification.
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Chen, Ganglin, Chris Finn, Ramesh Neelamani, Dominique Gillard, Gianni Matteucci, and Bill Fahmy. "Spectral decomposition response to reservoir fluids from a deepwater reservoir." In SEG Technical Program Expanded Abstracts 2006. Society of Exploration Geophysicists, 2006. http://dx.doi.org/10.1190/1.2369841.

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Pennington, Wayne D. "Beyond structure: Geophysics for reservoir management (lithology, fluids, and fluid movement)." In SEG Technical Program Expanded Abstracts 1996. Society of Exploration Geophysicists, 1996. http://dx.doi.org/10.1190/1.1826514.

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Ravitz, Ray, LaTosha Moore, and Charles F. Svoboda. "VES an Alternative to Biopolymers in Reservoir Reservoir Drill-In Fluids." In 8th European Formation Damage Conference. Society of Petroleum Engineers, 2009. http://dx.doi.org/10.2118/121933-ms.

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Bukovac, Tomislav, Aulia Akbari, Nihat M. Gurmen, Nagendra Mehrotra, Ibrahim Alabi, Roland Orellana, and Nelson Suarez Arcano. "Unconventional Fracturing Fluids for Unconventional Reservoir Challenges." In Abu Dhabi International Petroleum Exhibition & Conference. Society of Petroleum Engineers, 2016. http://dx.doi.org/10.2118/183426-ms.

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Reports on the topic "Reservoir fluids"

1

Nur, Amos. Porous reservoir rocks with fluids: Reservoir transport properties and reservoir conditions. Office of Scientific and Technical Information (OSTI), January 2004. http://dx.doi.org/10.2172/820852.

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Ziagos, J. P., R. J. Gelinas, S. K. Doss, and R. G. Nelson. Adaptive forward-inverse modeling of reservoir fluids away from wellbores. Office of Scientific and Technical Information (OSTI), July 1999. http://dx.doi.org/10.2172/14795.

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Hoekstra, P., M. W. Blohm, C. H. Stoyer, and B. A. James. Characterization of reservoir rocks and fluids by surface electromagnetic transient methods. Office of Scientific and Technical Information (OSTI), July 1992. http://dx.doi.org/10.2172/10192984.

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Hoekstra, P., M. W. Blohm, C. H. Stoyer, and B. A. James. Characterization of reservoir rocks and fluids by surface electromagnetic transient methods. Office of Scientific and Technical Information (OSTI), January 1992. http://dx.doi.org/10.2172/7296641.

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Hoekstra, P. Characterization of reservoir rocks and fluids by surface electromagnetic transient methods. Office of Scientific and Technical Information (OSTI), January 1991. http://dx.doi.org/10.2172/6025147.

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Lansangan, R. M., and J. S. Lievois. Mercury-free PVT apparatus for thermophysical property analyses of hydrocarbon reservoir fluids. Office of Scientific and Technical Information (OSTI), August 1992. http://dx.doi.org/10.2172/7052545.

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Tomutsa, L., A. Brinkmeyer, and D. Doughty. Imaging techniques applied to the study of fluids in porous media. Scaling up in Class 1 reservoir type rock. Office of Scientific and Technical Information (OSTI), April 1993. http://dx.doi.org/10.2172/10149969.

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Dutton, S. P., M. A. Malik, and G. B. Asquith. Geologic and engineering characterization of Geraldine Ford Field, Reeves, and Culberson Counties, Texas - analysis of reservoir fluids. Topical report, 1997. Office of Scientific and Technical Information (OSTI), April 1998. http://dx.doi.org/10.2172/598384.

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Lansangan, R. M., and J. S. Lievois. Mercury-free PVT apparatus for thermophysical property analyses of hydrocarbon reservoir fluids. Final report, August 16, 1990--July 31, 1992. Office of Scientific and Technical Information (OSTI), August 1992. http://dx.doi.org/10.2172/10126822.

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Weare, Nancy Moller. Technology for Increasing Geothermal Energy Productivity. Computer Models to Characterize the Chemical Interactions of Goethermal Fluids and Injectates with Reservoir Rocks, Wells, Surface Equiptment. Office of Scientific and Technical Information (OSTI), July 2006. http://dx.doi.org/10.2172/887335.

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