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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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Tahani, Hoda. "Determination of the velocity of sound in reservoir fluids using an equation of state." Thesis, Heriot-Watt University, 2012. http://hdl.handle.net/10399/2537.
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Production of oil and gas from hydrocarbon reservoirs results in reduction in reservoir pressure and changes in the fluid composition and saturations. Enhanced oil recovery methods such as Gas Injection, Water Flooding, CO2 Injection, in-situ Combustion, Water Alternative Gas injection (WAG) and so on have similar effects. Variation of these properties can lead to changes in the velocity of sound in subsurface layers. On the other hand, any change in temperature, pressure, composition and density of pore fluids has strong influence on the seismic elastic properties. Elastic properties of fluids are usually simplified in geophysics. All existing software employs empirical relations to calculate seismic wave velocities in reservoir fluids. In this study, thermodynamic properties have been considered as first and second order derivative properties of the thermodynamic potentials. For this purpose, a statistical thermodynamic approach, with the Statistical Associated Fluid Theory – Boublik - Alder – Chen – Kreglewski has been used and developed further for mixtures and real oils by proposing new mixing rules, tuning binary interaction parameters, and utilizing the properties of single carbon numbers. In addition, a large number of experimental data on pure, binary and multi-component systems have been generated in this work. The predictions of the model developed in this work have been validated against the experimental data generated in this work and those reported in the literature. The predictions were found to be in very good agreement with independent experimental data.
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Gozalpour, Fathollah. "Integrated phase behaviour modelling of petroleum fluids for compositional simulation of reservoir-surface processes." Thesis, Heriot-Watt University, 1998. http://hdl.handle.net/10399/1199.
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Al-Siyabi, Zaid Khamis Sarbookh. "The contact angle, interfacial tension and viscosity of reservoir fluids : experimental data and modelling." Thesis, Heriot-Watt University, 2000. http://hdl.handle.net/10399/1198.
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Haghighi, Hooman. "Phase equilibria modelling of petroleum reservoir fluids containing water, hydrate inhibitors and electrolyte solutions." Thesis, Heriot-Watt University, 2009. http://hdl.handle.net/10399/2307.
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Formation of gas hydrates can lead to serious operational, economic and safety problems in the petroleum industry due to potential blockage of oil and gas equipment. Thermodynamic inhibitors are widely used to reduce the risks associated with gas hydrate formation. Thus, accurate knowledge of hydrate phase equilibrium in the presence of inhibitors is crucial to avoid gas hydrate formation problems and to design/optimize production, transportation and processing facilities. The work presented in this thesis is the result of a study on the phase equilibria of petroleum reservoir fluids containing aqueous salt(s) and/or hydrate inhibitor(s) solutions. The incipient equilibrium methane and natural gas hydrate conditions in presence of salt(s) and/or thermodynamic inhibitor(s) have been experimentally obtained, in addition to experimental freezing point depression data for aqueous solution of methanol, ethanol, monoethylene glycol and single or mixed salt(s) aqueous solutions, are conducted. A statistical thermodynamic approach, with the Cubic-Plus-Association equation of state, has been employed to model the phase equilibria. The hydrate-forming conditions are modelled by the solid solution theory of van der Waals and Platteeuw. Predictions of the developed model have been validated against independent experimental data from the open literature and the data generated in this work. The predictions were found to agree well with the experimental data.
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Wise, Michael. "Phase equilibria measurement and modelling of petroleum reservoir fluids containing gas hydrate inhibitors and water." Thesis, Heriot-Watt University, 2016. http://hdl.handle.net/10399/3204.
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Understanding gas hydrate inhibitor distribution in hydrocarbon phases is essential for the economic design of process equipment. In order to build a clear image of the inhibitor’s distribution in various phases, three experimental investigations were devised; solubility in liquid and vapour phase as well as saturation pressure measurements. These data will contribute significantly to the understanding of the partitioning of these components as the data in the open literature are fairly limited. Aiming at filling the experimental gap found in the literature, the solubility of methane in pure methanol and ethanol as well as 70 and 50 wt% aqueous solutions at 238.15 – 298.15 K and 0.3 – 47 MPa were measured. The data from the ethanol/solution solubility measurements were used to optimise the methane-ethanol Binary Interaction Parameters (BIPs) of the CPA-SRK72 Equation of State (EoS). The model calculations showed an absolute average deviation of 5.3% over the full pure data range. To improve the CPA-SRK72 EoS predictions for aqueous solutions, new methane-ethanol BIPs were regressed showing significant improvement for both solubility and quaternary bubble point predictions. In order to determine the inhibitor loss to the vapour phase, the inhibitor content of methane was measured using Gas Chromatography (GC) between 0.7 – 62 MPa and 273.15 – 298.15 K. Additionally, a number of bubble point measurements were conducted for binary, ternary and quaternary systems containing methane, a liquid hydrocarbon phase (C7 – C12), methanol/ethanol and water. This was to investigate the effect of the inhibitor phase in the ternary, and the dominant excess water phase in the quaternary system, on the bubble point pressure as well as evaluating the CPA-SRK72 predictions. The saturation pressures were measured at 253.15 – 313.15 K. The solubility of CO2 in Mono-ethylene glycol (MEG), Di-ethylene glycol (DEG) and Tri-ethylene glycol (TEG) and their aqueous solutions (90, 60 and 40 wt%), at pressures and temperatures ranging from 0.2 – 43.4 MPa and 263 – 343 K, were measured. The solubility of CO2 in pure MEG, DEG and TEG were predicted using the CPA-SRK72 EoS, using a single binary interaction parameter, showing an absolute average deviation of 5.13%, 9.51% and 2.55% respectively. Correlations for the solubility of CO2 in MEG, DEG and TEG aqueous solutions, using aqueous solution regressed BIPs, showed an overall absolute average deviation of 17.5%, 18.2% and 25.16% respectively, a significant improvement from the non-aqueous solution BIP optimised predictions.
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Parslow, Gary Iain. "Erosion risk modelling of subsea components." Thesis, Cranfield University, 1998. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.267498.
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WALDMANN, ALEX TADEU ALMEIDA. "THE DRIVING MECHANISMS FOR BRIDGING AGENTS EFFECTIVENESS ON DRILLING FLUIDS INVASION CONTROL INTO OIL RESERVOIR ROCKS." PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIRO, 2005. http://www.maxwell.vrac.puc-rio.br/Busca_etds.php?strSecao=resultado&nrSeq=7651@1.
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PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIROEste estudo procurou observar e quantificar os parâmetros operacionais que governam as propriedades permoporosas da torta de filtração, formada após o escoamento de uma solução de glicerina com uma determinada concentração de sólidos. A formação de um reboco externo de baixa permeabilidade é um dos fatores mais importantes para minimizar da invasão do filtrado de fluido na rocha reservatório. A contaminação do reservatório pelo filtrado do fluido pode trazer vários problemas operacionais, que serão discutidos nesta dissertação. A eficiência do sistema de fluidos em minimizar a invasão é normalmente avaliada através de ensaios padrão de filtração estática. Neste trabalho dois objetivos centrais são definidos: Identificar os parâmetros operacionais que governam as propriedades permoporosas do reboco externo através de ensaios de filtração estática e disponibilizar uma metodologia para a avaliação da invasão do filtrado do fluido de perfuração na geometria poço-reservatório (escoamento radial), a partir de ensaios de laboratório de filtração estática (escoamento linear). Os resultados indicam que a solução da lei Darcy para o problema de filtração com formação de torta incompressível mostrou - se adequada para grande maioria dos ensaios experimentais com solução de glicerina contendo agentes obturantes. O mesmo não se verificou para ensaios com solução de goma xantana como meio contínuo. Os resultados experimentais obtidos mostraram também que, para uma mesma solução de glicerina contendo agente obturante, os valores de permeabilidade da torta de filtração obtidos na geometria linear e na geometria radial são semelhantes. Desta forma, pode - se validar a metodologia de previsão do grau da invasão de fluidos de perfuração na rocha reservatório (configuração radial) a partir de ensaios convencionais de laboratório (configuração linear).
This work deals with the understanding of the major operational parameters governing filter cake building drilling fluids invasion through reservoir rocks. The ability of the fluid system to prevent invasion is normally evaluated by standardized static filtration experiments. In these tests, the fluid is pressurized through a filter paper or into a consolidated inert porous medium. The volume which crosses the porous core is monitored along the time. Darcy flow modeling of non-compressible cakes proved to reproduce adequately the filtration of a Newtonian fluid + particulate system through ceramic and sinterized steel disks. Pressure differential, particle size and shape proved to be relevant parameters affecting filter cake permeability and porosity. The present study proposes, through the coupling of a linear filtration formulation (lab configuration) and a radial single phase formulation (wellbore vicinity), to predict fluid invasion depth of fluid filtrate in the reservoir rock. Modeling is validated with linear and radial lab tests. The proposed methodology is a requirement for optimum drilling fluid design to be used in the drilling of reservoir sections in both exploratory and development wells.
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Al-Kharusi, Badr Soud. "Relative permeability of gas-condensate near wellbore, and gas-condensate-water in bulk of reservoir." Thesis, Heriot-Watt University, 2000. http://hdl.handle.net/10399/1098.
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Dufal, Simon. "Development and application of advanced thermodynamic molecular description for complex reservoir fluids containing carbon dioxide and brines." Thesis, Imperial College London, 2013. http://hdl.handle.net/10044/1/12799.
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This thesis contains a study of the thermodynamic properties of complex reservoir fluids. The focus of this work is the development of an equation of state and molecular models to describe the phase behaviour of the different components of the reservoir fluids that may be encountered in the context of CO2 injection into geological formations suitable for storage, e.g., saline aquifers or depleted hydrocarbon reservoirs, together with that of mixtures of these components that may be encountered. The major constituents of these reservoir fluids are the injected gas (CO2, which may contain some impurities), alkanes and various other hydrocarbons from natural gas or crude oil, water and salts. The first task is to ensure that the method selected (the SAFT-VR Mie equation of state) to model those fluids can provide an accurate description of the simplest of the fluids encountered, CO2 and hydrocarbons. A crucial aspect of this concerns a detailed examination of the procedure for searching the highly degenerate model-parameter space to obtain the best models for each fluid. The suitability of the method is also assessed by studying other simple fluids, as a means to test the range of validity of the models developed. Once the method has been validated for a wide range of relatively simple fluids, the next step is to study more-complex fluids including, in particular, water. Water is ubiquitous in the systems of interest but is a notoriously difficult fluid to model accurately using simple models of the sort that are tractable for use in the context of equation-of-state modelling. The provision of a good model of water underpins a large part of the work and is accomplished only as a result of further development of the theory upon which the equation of state is based, involving not only its statistical-mechanical foundation but also lengthy numerical procedures to isolate the most physically reasonable application of the theory. Bearing in mind its simplicity, the resulting model for water, within the context of the refined theory, provides for a remarkably good representation of the thermodynamic properties of water and forms a highlight of the thesis. The remaining part of the work is the development of a framework in which to treat the ionic components of reservoir fluids. Following the implementation of a standard method to treat electrolyte solutions, the main goal of the thesis is achieved with the modelling of the phase equilibria of CO2-brine systems, demonstrating that the proposed method is a suitable tool for the study of complex reservoir fluids containing carbon dioxide and brines.
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Petrie, Elizabeth Sandra. "Rock Strength of Caprock Seal Lithologies: Evidence for Past Seal Failure, Migration of Fluids and the Analysis of the Reservoir Seal Interface in Outcrop and the Subsurface." DigitalCommons@USU, 2014. https://digitalcommons.usu.edu/etd/2072.
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This research characterizes the nature of fractures in Paleozoic and Mesozoic caprock seal analogs exposed in central and south-eastern Utah. The results of this research show evidence for fluid flow and mineralization in the subsurface as well as reactivation of fractures suggesting that the fractures act as a loci for fluid flow through time. The heterolithic nature of the caprock seals and meso-scale (cm to m) variability in fracture distributions and morphology highlight the strong link between the variation in material properties and the response to changing stress conditions. The variable connectivity of fractures and the changes in fracture density at the meso-scale plays a critical role in subsurface fluid flow. The presence or formation of new fractures can result in seal bypass systems, which can cause failure of hydrocarbon traps, CO2 geosequestration sites, waste and subsurface fluid repositories. An integrated approach of field, borehole geophysical, burial and stress history modeling, rock strength testing, and numerical modeling are used to understand the effects changing material properties, rock strength, and stress history have on sealing capacity. Simplified stress history models derived from burial history curves are combined with laboratory derived rock properties to understand the importance variations in rock properties and differential and effective mean stress have on the mechanical failure of fine-grained clastic sedimentary rocks. Burial history and rock strength data show that in units that experience similar burial depths and changing mechanical property exert a control on deformation type. Geomechanical models reveal changes in local strain magnitudes at locked mechanical interfaces, suggesting that elastic mismatch between layers results in differential strain distribution. Characterization of fracture patterns, rock strength variability and the modeled changes in subsurface strain distribution is especially important for understanding the response of low-‐permeability rocks to changing stress in the subsurface, and is applicable to multiple geo-engineering scenarios such as exploitation of natural resources, waste disposal, and management of fluids in the subsurface. The analyses presented in this dissertation provide analog fracture data for fine-grained clastic rocks and a dataset for better understanding the importance of heterogeneity in low permeability rocks.
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Teca, Dário Bokiló Machado. "Correction of the anisotropy in resistivity: application to pore pressure prediction." Master's thesis, Faculdade de Ciências e Tecnologia, 2014. http://hdl.handle.net/10362/13132.
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Dissertação para obtenção do Grau de Mestre em
Engenharia Geológica (Georrecursos)This dissertation is based on a curricular training period done at company Total EP Angola between July and December 2013. The data presented relate to a real case study of an exploration block, which for reasons of confidentiality is designated by Block Michocho. The fluids pressure measurement in the geological formations can be inferred from the formation resistivity log. In not perpendicular wells to the layers, resistivity curves show higher values than the expected due to the anisotropic effect of the formation thus the inference of the pressure of fluids from resistivity logs can lead to unrealistic values. Most of the developments wells drilled on Block Michocho in Angola are highly deviated, if not sub-horizontal, in the reservoir section. The objective of this work is to correct the anisotropic effect of the resistivity of Block Michocho due to non-perpendicularity of the wells when intersect the geological formations. In this study, the correction of the resistivity is based on the formula proposed by Moran and Gianzero in 1979 and involves the dipping angle of the induction logging tool and the coefficient of anisotropy of the rock formation. Prior to application of this formula for the corrections of resistivity of the Block Michocho wells logs, a set of validation tests were made. Due to lack of data on development wells (highly inclined wells) the validation test was carried out in five exploration wells where resistivity is available in the two principal directions. It was assumed that the formula would be approved for resistivity corrections if the horizontal resistivity obtained by the formula had a good correspondence with the horizontal resistivity obtained by the induction logging tool. After this validation step, the coefficient of anisotropy to be used in the formula was calibrated as well as the correction of the curves of resistivity of the remaining development wells, those much more diverted regarding the rock layers. The corrected resistivity can be applied for pore pressure prediction in low permeability rock formations, in which the main objective is to identify regions where fluid pressure is higher than normal pressure, i.e. overpressure regions. For illustration purposes, a resistivity curve from an exploration well was chosen and the pressure of the fluids in low permeability rocks was computed by using the formula proposed by Eaton in 1975. With this well data, a potential overpressure region was identified and should be avoided in drilling activities.
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Bello, Kelani. "Modeling multiphase solid transport velocity in long subsea tiebacks : numerical and experimental methods." Thesis, Robert Gordon University, 2013. http://hdl.handle.net/10059/3138.
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Transportation of unprocessed multiphase reservoir fluids from deep/ultra deep offshore through a long subsea tieback/pipeline is inevitable. This form of transportation is complex and requires accurate knowledge of critical transport velocity, flow pattern changes, phase velocity, pressure drop, particle drag & lift forces, sand/liquid/gas holdup, flow rate requirement and tieback sizing etc at the early design phase and during operation for process optimisation. This research investigated sand transport characteristics in multiphase, water‐oil‐gas‐sand flows in horizontal, inclined and vertical pipes. Two critical factors that influence the solid particle transport in the case of multiphase flow in pipes were identified; these are the transient phenomena of flow patterns and the characteristic drag & lift coefficients ( D C , L C ). Therefore, the equations for velocity profile were developed for key flow patterns such as dispersed bubble flow, stratified flow, slug flow and annular flow using a combination of analytical equations and numerical simulation tool (CFD). The existing correlations for D C & L C were modified with data acquired from multiphase experiment in order to account for different flow patterns. Minimum Transport Velocity (MTV) models for suspension and rolling were developed by combining the numerically developed particle velocity profile models with semi‐empirical models for solid particle transport. The models took into account the critical parameters that influence particle transport in pipe flow such as flow patterns and particle drag & lift coefficients, thus eliminate inaccuracies currently experienced with similar models in public domain. The predictions of the proposed MTV models for suspension and rolling in dispersed bubble, slug flow and annular flow show maximum average error margin of 12% when compared with experimental data. The improved models were validated using previously reported experimental data and were shown to have better predictions when compared with existing models in public domain. These models have the potential to solve the problems of pipe and equipment sizing, the risk of sand deposition and bed formation, elimination of costs of sand unloading, downtime and generally improve sand management strategies.
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Moss, Adam Keith. "Pore-level fluid migration in reservoir sandstones." Thesis, University of Plymouth, 1994. http://hdl.handle.net/10026.1/1722.
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The void space properties of a set of gas reservoir sandstone samples have been measured. The properties include porosity, absolute gas permeability, electrical resistivity formation factor and tortuosity. The mineralogy of each sandstone was determined by scanning electron microscopy and energy dispersive x-ray analysis. Mercury intrusion and extrusion data have been measured for most of the sandstone samples. A new procedure for measuring the degree and range of void size correlations within resin-filled sandstones has been developed. Image analysis of backscattered electron micrographs of these samples supplies void size and positional information. A "semi-variogram" study of void size and coordinate data ascertains the degree and range of void size correlation. Measurable correlation has been found in two sandstone samples, but was absent from four others. Diffusion coefficients of methane, iso-butane and n-butane through dry sandstones have been measured using an adaptation of a non-steady state method, using a redesigned apparatus. A repeatability and error analysis of diffusion coefficient measurement has also been performed. A correlation between diffusion coefficients, absolute permeability, porosity and formation factor was detected for sandstones containing little clay. The diffusion coefficients measured for clay affected sandstones did not correlate with any petrophysical properties of these samples. A computer model capable of simulating porous media has been previously developed. It consists of a 10x10x10 network of cubic pores and cylindrical throats, and simulates die mercury intrusion curve. The void size distribution is modified until both simulated and experimental curves closely match. New void size distribution input and curve fit algorithms have been developed to increase the speed and accuracy of die simulations and a new modelling procedure allows the modelling of samples with void size correlation. The model is capable of simulating porosity, permeability, tortuosity and mercury extrusion. Each of the reservoir sandstones has been modelled and their characteristic properties simulated. Successful simulations were obtained for all relatively clay-free reservoir sandstones. Clay affected sandstone simulations were less successful due to the high complexity of these samples. A study into formation damage witiiin reservoir sandstones was also undertaken. The effect of colloidal particulate void space penetration is measured and simulated.
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Diyashev, Ildar. "Problems of fluid flow in a deformable reservoir." Texas A&M University, 2005. http://hdl.handle.net/1969.1/3330.
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This research is focused on development and enhancement of the model of fluid flow
in a formation with stress-dependent permeability. Several typical axi-symmetrical problems
of fluid flow in a multi-layered reservoir with account for wellbore storage and skin have
been solved numerically. The permeability was assumed to be a function of the vertical
deformation of the reservoir. This deformation is the result of changing stress-strain state in
the elastic system, comprised of the reservoir itself and the surrounding rock mass. The
change in the stress-strain state of the system is induced by pressure change in the layers of
the reservoir.
Numerical results qualitatively agree with observed field behavior. Such behavior
includes (1) deviation of an inflow performance curve from the straight-line relationship at
pressures above bubble-point pressure, (2) time- and rate-dependence of well-testing
derivative, (3) asymmetry of processes of production and of injection, and (4) inconsistent
results between drawdown and buildup, or injection and falloff tests.
Based on the results, a procedure to estimate the parameters of the suggested
permeability model is proposed.
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Oloso, Munirudeen Ajadi. "Prediction of reservoir fluid properties using machine learning." Thesis, University of Portsmouth, 2018. https://researchportal.port.ac.uk/portal/en/theses/prediction-of-reservoir-fluid-properties-using-machine-learning(a0f121e7-9e87-468d-a001-42ddb9d5a421).html.
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The phase and volumetric behaviour of reservoir fluid properties, referred to as pressure-volumetemperature (PVT) properties, involve the thermodynamic studies of the fluid with respect to pressure, temperature and its volumetric compositions. PVT properties are usually determined by laboratory experiments performed on the actual samples of the reservoir fluid. Failing that, these fluid properties have been evaluated by some other methods such as equations of state, empirical correlations and recently, machine learning models. Machine learning is basically the prediction of the future with, (supervised learning), or without, (unsupervised learning), prior knowledge of the past. A common problem for the standalone machine learning technique is local minimum. In view of this, ensemble systems and hybrid techniques have been developed successfully for improvement in different fields. This work introduces two different ensemble methods based on support vector regression and regression trees where both ensemble approaches utilise a novel concept tagged "Tying Ranking" in selection of the base models. Also, a hybrid system for reservoir fluid characterisation with a novel way of grouping petroleum fluid properties using intelligent method was developed. The hybrid system uses K-Means clustering for the intuitive grouping along with functional networks for the prediction. The performance and generalisation of the developed models are compared against their standalone and selected empirical models using some statistical measures which are commonly used for performance evaluation in the petroleum industry. In the first category of experimentation, the impact and effect of training the machine learning models with more diverse and bigger data set is shown. Effects of using different functional forms to predict dead oil, saturated and undersaturated viscosity are also explored. In addition, impacts of different statistical measures on the predicted outputs and wrong interpretations of results in the literature are examined. The main statistical measures that are used for comparison are root mean squared errors, average absolute percentage relative error and maximum absolute percentage relative error. For each of the reservoir fluid properties considered in this work, at least one or more of the developed machine learning models have better overall and average performance than all the compared correlations in each category. The superiority of the three developed machine learning models is visible in the trend analysis as they show less deviations in results compared to the empirical correlations and their standalone methods in most cases for all the considered reservoir fluid properties.
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Daniell, W. E. "Seismic behaviour of reservoir intake towers." Thesis, University of Bristol, 1992. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.262826.
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Ballentine, Christopher John. "He, Ne, and Ar isotopes as tracers in crustal fluids." Thesis, University of Cambridge, 1991. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.387053.
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Al, Harrasi Mahmood Abdul Wahid Sulaiman. "Fluid flow properties of tight gas-condensate reservoirs." Thesis, University of Leeds, 2011. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.582106.
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Tight gas-condensate reservoirs contain large reserves, but can be extremely costly to develop. Understanding the fundamental controls on the fluid flow behaviour of tight gas and gas-condensate reservoirs has the potential to result in more cost-effective reservoir development and help increase the world's producible reserves. Therefore, the principal objective of the thesis is to improve understanding of multiphase flow within tight gas-condensate reservoirs. In order to achieve this objective a series of pore-to-core scale experiments under controlled conditions were performed, followed by numerical simulation. Three methodologies were used in this study: First, pore-scale experiments in glass micromodels with liquid-liquid systems were performed to improve understanding of the phase separation and flow mechanisms at pore level. Second, coreflood experiments were performed while in-situ saturation was monitored using an X-ray C'I' -scanner. A newly developed liquid-liquid system was used in these experiments. Flow through tight gas sandstones allowed the determination of relative penneabilities as well as determining their dependence on absolute permeability and capillary number. Third, production simulation modelling has been conducted to investigate the implications of the results. The micromodel experiments have proved extremely useful for characterizing the flow behaviour . of condensate systems. The results showed that the flow mechanisms and phases' distributions were affected largely by interfacial tension, pore structure and wettability.
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Vlastos, Serafeim. "Seismic characterisation of fluid flow in fractured reservoirs." Thesis, University of Edinburgh, 2005. http://hdl.handle.net/1842/11507.
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In the first part of this thesis we introduce a new numerical method that combines a numerical method with an analytical method. We model the seismic wave propagation in fractured rock using the pseudospectral method. The fractures are treated as planes of weakness using the concept of the linear slip deformation or displacement discontinuity model. The implementation of fractures with a vanishing width in the finite difference grid is done using an equivalent medium theory. The objective is to investigate the effects of lengthscale (size) and spatial distributions of fractures on the characteristics of propagating waves. We demonstrate that the waveforms can be significantly affected by the presence of fractures with different lengthscales reltive to the wavelength, and we also show that different spatial distributions of fractures can give characteristic features on the wavefields, implying that information about fracture distributions in natural rock may be obtained directly from seismic data. In the second part of the thesis, we deal exclusively with scattering attenuation. Synthetic modelling studies with and without intrinsic attenuation show that the contribution of scattering attenuation is significant. Scattering involves no energy loss, but produces a more extended, lower amplitude wavetrain by the resulting interference. It is dependent on the nature of small-scale fluctuations in the earth parameters and is found to be frequency dependent. For the numerical simulation, we use the method introduced in the thesis that can accurately model the effects of scattering. The various fracture patterns examined are patterns of development of a population of fractures involving nucleation, growth, branching, interaction and coalescence created by a multiscale cellular automaton model. The objective is to examine the behaviour of scattering attenuation at different fracture patterns characterised by different statistical properties, fracture population geometry and criticality. We examine scattering attenuation in a range of frequencies for each one of the fracture patterns and demonstrate the frequency dependence. The comparison of the pattern of scattering attenuation with frequency between different fracture patterns shows that there is a change that can be attributed to the changes in the statistical properties of the fracture population. We conclude by examining the existence of direct links between fracture properties and scattering attenuation patterns, which can be used for the characterisation of fractured reservoirs.
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Fitzgerald, Shaun David. "Fluid dynamics and phase change in geothermal reservoirs." Thesis, University of Cambridge, 1993. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.309335.
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Idris, Ahmad Kamal Bin. "Some effects of wettability and fluid properties on immiscible displacement in porous media." Thesis, Imperial College London, 1990. http://hdl.handle.net/10044/1/11384.
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Djatmiko, Wahju. "Well testing in multi-phase flow reservoirs." Thesis, Imperial College London, 1996. http://hdl.handle.net/10044/1/8128.
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Shaik, Abdul Ravoof Petroleum Engineering Faculty of Engineering UNSW. "Simulation of stress dependent fluid flow in naturally fractured reservoirs." Publisher:University of New South Wales. Petroleum Engineering, 2008. http://handle.unsw.edu.au/1959.4/43266.
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Naturally fractured reservoirs represent significant portion of the world's oil and gas reserves. In most of the reservoirs, fractures are important contributors to fluid flow. Thus, modeling and simulation of discrete fracture network is essential to assess responses of the reservoirs under stimulation pressure, develop the best hydraulic fracture treatments, carry out feasibility studies, design optimum production methods and improve reservoir potentials. It is also a very complicated process. Natural fractures are by nature highly heterogeneous with different size, orientation and spatial distribution. The complexity is further raised, taking into account the role of matrix, the flow interaction between matrix and fractures, the effect of production-induced stress on fluid flow. Previous works fail to balance sufficient geological complexity and excessive needs of high computational resources. This thesis presents an innovative procedure to simulate stress-dependent fluid flow through discrete fracture network. Three numerical models (tensor, flow and deformation) are developed and coupled iteratively for this purpose. - A tensor model calculates grid based permeability tensor from discrete fracture network model, which includes individual fracture properties such as spatial distribution, length, location and orientation. The tensor model accounts for fluid flow from the matrix to matrix and matrix to fracture. It also includes flow through connected and disconnected fractures. - An unsteady state simulation model investigates fluid flow through the fracture system and gives pressure profile, velocity profile as output. - A dual continuum deformation model studies the reservoir rock deformation and its effects on fluid flow. The geo-mechanic solution is decomposed into matrix and fracture parts that allow calculation of dynamic porosity and permeability separately. The proposed work procedure has been validated to match nicely with analytical results. Furthermore, several case study scenarios are carried out to illustrate how it could help evaluate different aspects of reservoir performance including fracture connectivity, rock deformation, well injectivity and productivity, recovery and even distribution of fluid inside reservoir as a result of rock deformation. The case studies have proven the method to be very efficient in terms computational resources. It also eliminates most of the limitations in the previous models such as handling fracture connectivity, permeability anisotropy and change in effective stress.
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Castoro, Alessandro. "Mapping reservoir properties through pre-stack seismic attribute analysis." Thesis, Birkbeck (University of London), 1999. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.327052.
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Malpani, Rajgopal Vijaykumar. "Selection of fracture fluid for stimulating tight gas reservoirs." Texas A&M University, 2006. http://hdl.handle.net/1969.1/4719.
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Essentially all producing wells drilled in tight gas sands and shales are stimulated using
hydraulic fracture treatments. The development of optimal fracturing procedures,
therefore, has a large impact on the long-term economic viability of the wells. The
industry has been working on stimulation technology for more than 50 years, yet
practices that are currently used may not always be optimum. Using information from the
petroleum engineering literature, numerical and analytical simulators, surveys from
fracturing experts, and statistical analysis of production data, this research provides
guidelines for selection of the appropriate stimulation treatment fluid in most gas shale
and tight gas reservoirs. This study takes into account various parameters such as the type
of formation, the presence of natural fractures, reservoir properties, economics, and the
experience of experts we have surveyed. This work provides a guide to operators
concerning the selection of an appropriate type of fracture fluid for a specific set of
conditions for a tight gas reservoir.
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Leckenby, Robert James. "Dynamic characterisation and fluid flow modelling of fractured reservoirs." Thesis, Imperial College London, 2005. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.423031.
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Susuz, Onur. "Assessment Of Reservoir Rock And Fluid Data For Black Oil Simulation." Master's thesis, METU, 2010. http://etd.lib.metu.edu.tr/upload/2/12611561/index.pdf.
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Reservoir simulation studies are one of the key tools in an integrated reservoir management study. A successful reservoir simulation application requires representative input data for reservoir rock and fluid properties. This study aims to develop a road map from laboratory measurements to the input data file of reservoir simulation and to make a probabilistic approach for the estimation of unknown parameters. Raw data of reservoir rock and fluid properties of a selected oil field of Turkey will be interpreted and prepared in a way that they will be used as input data of a simulator.
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Martínez-Garzón, Patricia [Verfasser]. "Seismo-mechanical reservoir characterization from fluid-induced seismicity / Patricia Martínez-Garzón." Berlin : Freie Universität Berlin, 2014. http://d-nb.info/1056908165/34.
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Izgec, Bulent. "Transient fluid and heat flow modeling in coupled wellbore/reservoir systems." Thesis, [College Station, Tex. : Texas A&M University, 2008. http://hdl.handle.net/1969.1/ETD-TAMU-2801.
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Hnidei, Stephen D. "Selective withdrawal of a linearly stratified fluid in a triangular reservoir." Thesis, University of British Columbia, 1990. http://hdl.handle.net/2429/28834.
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The water in most reservoirs is density stratified with depth. This stratification leads to the inhibition of vertical movement, consequently, when water is withdrawn from the reservoir it tends to move in a jet-like layer called a withdrawal layer, towards the sink. By placing the sink at a certain depth, one is able to selectively withdrawal water from a limited range of depths and thus obtain water of a desired quality.
Much work has been done in this field by considering a simplified boundary geometry, usually rectangular. However little attention has been given to the effects of accurate boundary geometry. For this thesis, five numerical experiments were conducted for the problem of a two-dimensional, viscous, incompressible, slightly-stratified flow towards a sink in a triangular reservoir.Science, Faculty of
Mathematics, Department of
Graduate
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Jennings, David Anthony. "Some effects of pore structure and fluid properties on multiphase displacements in porous media." Thesis, Imperial College London, 1988. http://hdl.handle.net/10044/1/11383.
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Harland, Sophie Rebekah. "Quantifying the role of microporosity in fluid flow within carbonate reservoirs." Thesis, University of Edinburgh, 2016. http://hdl.handle.net/1842/25961.
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Micropores can constitute up to 100% of the total porosity within carbonate hosted hydrocarbon reservoirs, usually existing within micritic fabrics. There is, however, only a rudimentary understanding of the contribution that these pores make to reservoir performance and hydrocarbon recovery. To further our understanding, a flexible, object-based algorithm has been developed to produce 3D computational representations of end-point micritic fabrics. By methodically altering model parameters, the state-space of microporous carbonates is explored. Flow properties are quantified using lattice-Boltzmann and network modelling methods. In purely micritic fabrics, it has been observed that average pore radius has a positive correlation with single-phase permeability and results in decreasing residual oil saturations under both water-wet and 50% fractionally oil-wet states. Similarly, permeability increases by an order of magnitude (from 0.6md to 7.5md) within fabrics of varying total matrix porosity (from 18% to 35%) due to increasing pore size, but this has minimal effect on multi-phase flow. Increased pore size due to micrite rounding notably increases permeability in comparison to original rhombic fabrics with the same porosity, but again, multi-phase flow properties are unaffected. The wetting state of these fabrics, however, can strongly influence multi-phase flow; residual oil saturations vary from 30% for a water-wet state and up to 50% for an 80% oil wet fraction. flow when directly connected. Otherwise, micropores control single-phase permeability magnitude. Importantly in these fabrics, recovery is dependent on both wetting scenario and pore-network homogeneity; under water-wet imbibition, increasing proportions of microporosity yield lower residual oil saturations. Finally, in grain-based fabrics where mesopores form an independently connected pore network, micropores do not affect permeability, even when they constitute up to 50% of the total porosity. Through examination of these three styles of microporous carbonates, it is apparent that micropores can have a significant impact on flow and sweep characteristics in such fabrics.
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Clayton, Leslie Noël. "Analysis of Small Faults in a Sandstone Reservoir Analog, San Rafael Desert: Implications for Fluid Flow at the Reservoir-Scale." DigitalCommons@USU, 2019. https://digitalcommons.usu.edu/etd/7438.
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We examined small-displacement faults in the Jurassic Entrada Sandstone adjacent to the Iron Wash Fault, central Utah east of the San Rafael Swell, in order to describe the nature and timing of past fluid movement and deformation in the Entrada Sandstone. Using field studies, microscopy, and X-ray diffraction analysis, we identified mineralized fractures and cementation features in association with deformation bands and fractures at the interface of the Earthy and Slick Rock Members of the Entrada Sandstone.
Where the faults cross the Earthy-Slick Rock Member interface, deformation band faults in the Slick Rock Member become opening-mode fractures in the Earthy Member. These fractures are frequently mineralized with calcite, and goethite pseudomorphs after pyrite, providing evidence of at least two phases of fluid flow from the Entrada reservoir into the caprock in connection with deformation bands. We also observe mineralized fractures, poikilotopic cementation, and spherical to elongate concretions on and within deformation band fins in the Slick Rock Member. These features indicate the presence and movement of fluids parallel to and between deformation band fins.
At some sites, deformation band faults and fractures cross and offset the interface; at others, they are present in both units, but deformation band faults do not cross the interface and fractures are not directly connected to any bands. Mineralized fractures are only found at breached-interface sites; evidence for fluid flow in the Slick Rock Member is only found in deformation band fins. Interface crossing and fracture formation is not related to proximity to the Iron Wash Fault.
We propose that mesoscale faults can act as seal bypass systems and allow fluid leakage from reservoir rock into overlying less permeable rocks. Deformation bands act as both conduits for and barriers to flow, seen most clearly in deformation band fins where iron staining and mineralization is constrained between sets of bands within the fin. In CO2 or wastewater injection scenarios, interface deformation may prevent successful fluid trapping and cause re-emission of injected fluids.
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Saleh, Amer Mohamed. "Well test and production prediction of gas condensate reservoirs." Thesis, Heriot-Watt University, 1992. http://hdl.handle.net/10399/813.
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Bunney, John Reuben. "Quantifying the dissolution/precipitation geochemistry of fluid/rock interactions in reservoir systems." Thesis, Heriot-Watt University, 1998. http://hdl.handle.net/10399/1284.
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Welch, Nathan James. "Imaging and fluid flow measurements of reservoir cap rock and ceramic analogues." Thesis, Imperial College London, 2016. http://hdl.handle.net/10044/1/41985.
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The study of reservoir seal formation characteristics is vital to the success of carbon sequestration projects. The unique properties of these formations allows for the safe long-term storage of carbon dioxide. These intrinsic properties also give rise to numerous experiment complexities outside of the realm of traditional core characterization techniques. Samples were obtained to represent the main classes of cap rocks; shales from both a quarry in the UK and a Spanish carbon storage pilot site, anhydrite from UK extraction mines, and a evaporite sample from a reservoir located in the Middle East. An apparatus has been constructed capable of measuring the permeability and capillary threshold pressure of reservoir cap rocks. The pressure decay technique was used to measure the permeability relationship of clay-rich and evaporite samples with varying applied stresses was measured. Unique trends are observed for each geologic sample exhibiting minimums in permeability. The initial reduction of permeability as effective pressure was increased was due compaction and the subsequent increase at high stresses was due to the opening of micro-fractures. The capillary threshold pressures of each sample were determined using three different techniques. A novel technique takes advantage of the pressure decay permeability measurements technique in quantifying extremely small fluid volumes during initial sample drainage. Capillary threshold pressures were shown to also be dependant on applied system stress. The capillary threshold pressure was observed to decrease dramatically following the increase in permeability with further increasing effective pressure. Imaging capabilities were also explored, ranging from core scale to nanometre scale techniques. Computerized micro-tomography was used in plug sample evaluation, and in the observation of fractured system behaviour under varying stress. Scanning electron microscopy paired with focused ion beam milling was used to extract the 3D pore space of the ceramic allowing for permeability estimates from numerical simulations.
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Husain, Me'ad Ibrahim. "The development of micromodelling techniques for investigating multiphase flow phenomena under reservoir conditions." Thesis, Heriot-Watt University, 1985. http://hdl.handle.net/10399/818.
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Fadipe, Oluwaseun Adejuwon. "Reservoir quality, structural architecture, fluid evolution and their controls on reservoir performance in block 9, F-O gas field, Bredasdorp Basin, offshore South Africa." Thesis, University of the Western Cape, 2012. http://hdl.handle.net/11394/4005.
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Philosophiae Doctor - PhDThe use of integrated approach to evaluate the quality of reservoir rocks is increasingly becoming vital in petroleum geoscience. This approach was employed to unravel the reason for the erratic reservoir quality of sandstones of the F-O gas field with the aim of predicting reservoir quality, evaluate the samples for presence, distribution and character of hydrocarbon inclusions so as to gain a better understanding of the fluid history. Information on the chemical conditions of diagenetic processes is commonly preserved in aqueous and oil fluid inclusion occurring in petroleum reservoir cements. Diagenesis plays a vital role in preserving, creating, or destroying porosity and permeability, while the awareness of the type of trap(s) prior to drilling serves as input for appropriate drilling designs. Thus an in-depth understanding of diagenetic histories and trap mechanisms of potential reservoirs are of paramount interest during exploration stage.This research work focused on the F-O tract located in the eastern part of Block 9 on the north-eastern flank of the Bredasdorp Basin, a sub-basin of Outeniqua Basin on the southern continental shelf, offshore South Africa. The Bredasdorp Basin experienced an onset of rifting during the Middle-Late Jurassic as a result of dextral trans-tensional stress produced by the breakup of Gondwanaland that occurred in the east of the Falkland Plateau and the Mozambique Ridge. This phenomenon initiated a normal faulting, north of the Agulhas-Falkland fracture zone followed by a widespread uplift of major bounding arches within the horst blocks in the region that enhanced an erosion of lower Valanginian drift to onset second order unconformity.This study considered 52 selected reservoir core samples from six wells(F-O1, F-O2, F-O3, F-O4, F-R1 and F-S1) in the F-O field of Bredasdorp Basin with attention on the Valanginian age sandstone. An integrated approach incorporating detailed core descriptions, wireline log analysis (using Interactive petrophysics), structural interpretation from 2D seismic lines (using SMT software) cutting across all the six wells, multi-mineral (thin section, SEM,XRD) analyses, geochemical (immobile fluid and XRF) and fluid inclusion(fluid inclusion petrography and bulk volatile) analyses were deployed for the execution of this study. Core description revealed six facies from the six wells grading from pure shale (Facies 1), through progressively coarsening interbedded sand-shale “heterolithic facies (Facies 2 - 4), to cross bedded and minor massive sandstone (Facies 5 - 6). Sedimentary structures and mineral patches varies from well to well with bioturbation, synaeresis crack, echinoid fragments, fossil burrow, foreset mudrapes, glauconite and siderite as the main observed features. All these indicate that the Valanginian reservoir section in the studied wells was deposited in the upper shallow marine settings. A combination of wireline logs were used to delineate the reservoir zone prior to core description. The principal reservoirs are tight, highly faulted Valanginian shallow-marine sandstones beneath the drift-onset unconformity, 1At1 and were deposited as an extensive sandstone “sheet” within a tidal setting. The top and base of the reservoir are defined by the 13At1 and 1At1 seismic events,respectively. This heterogeneous reservoir sandstones present low-fair porosity of between 2 to 18 % and a low-fair permeability value greater than 0.1 to 10 mD. The evolution of the F-O field was found to be controlled by extensional events owing to series of interpreted listric normal faults and rifting or graben generated possibly by the opening of the Atlantic. The field is on a well-defined structural high at the level of the regional drift-onset unconformity, 1At1.Multi-mineral analysis reveals the presence of quartz and kaolinite as the major porosity and permeability constraint respectively along with micaceous phases. The distribution of quartz and feldspar overgrowth and crystals vary from formation to formation and from bed to bed within the same structure. The increase in temperature that led to kaolinite formation could have triggered the low-porosity observed. Three types of kaolinite were recognized in the sandstone, (1) kaolinite growing in between expanded mica flakes; (2)vermiform kaolinite; and (3) euhedral kaolinite crystals forming matrix.Compositional study of the upper shallow marine sandstones in the Valanginian age indicates that the sandstones are geochemically classified as majorly litharenite having few F-O2 samples as subarkose with all F-O1 samples classified as sub-litharenite sandstone.Most of the studied wells are more of wet gas, characterized by strong response of C2 – C5 with F-O1 well showing more of gas condensate with oil shows (C7 – C11) based on the number of carbon atom present. In some cases,sulphur species (characterized by the presence of H2S, S2, CS2 and SO2) of probably thermal origin were identified while some log signatures revealed aromatic enriched sandstones possibly detecting nearby gas charges. The studied wells in the F-O field, based on fluid inclusion bulk volatile analysis are classified as gas discoveries except for F-O1 with gas condensate and oil shows.The integration of multi-mineral results and fluid inclusion studies show a dead oil stain with no visible liquid petroleum inclusion in the samples indicating the presence of quartz, kaolinite and stylolite as a major poro-perm constraint.
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Teimoori, Sangani Ahmad Petroleum Engineering Faculty of Engineering UNSW. "Calculation of the effective permeability and simulation of fluid flow in naturally fractured reservoirs." Awarded by:University of New South Wales. School of Petroleum Engineering, 2005. http://handle.unsw.edu.au/1959.4/22408.
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This thesis is aimed to calculate the effective permeability tensor and to simulate the fluid flow in naturally fractured reservoirs. This requires an understanding of the mechanisms of fluid flow in naturally fractured reservoirs and the detailed properties of individual fractures and matrix porous media. This study has been carried out to address the issues and difficulties faced by previous methods; to establish possible answers to minimise the difficulties; and hence, to improve the efficiency of reservoir simulation through the use of properties of individual fractures. The methodology used in this study combines several mathematical and numerical techniques like the boundary element method, periodic boundary conditions, and the control volume mixed finite element method. This study has contributed to knowledge in the calculation of the effective permeability and simulation of fluid flow in naturally fractured reservoirs through the development of two algorithms. The first algorithm calculates the effective permeability tensor by use of properties of arbitrary oriented fractures (location, size and orientation). It includes all multi-scaled fractures and considers the appropriate method of analysis for each type of fracture (short, medium and long). In this study a characterisation module which provides the detail information for individual fractures is incorporated. The effective permeability algorithm accounts for fluid flows in the matrix, between the matrix and the fracture and disconnected fractures on effective permeability. It also accounts for the properties of individual fractures in calculation of the effective permeability tensor. The second algorithm simulates flow of single-phase fluid in naturally fractured reservoirs by use of the effective permeability tensor. This algorithm takes full advantage of the control volume discretisation technique and the mixed finite element method in calculation of pressure and fluid flow velocity in each grid block. It accounts for the continuity of flux between the neighbouring blocks and has the advantage of calculation of fluid velocity and pressure, directly from a system of first order equations (Darcy???s law and conservation of mass???s law). The application of the effective permeability tensor in the second algorithm allows us the simulation of fluid flow in naturally fractured reservoirs with large number of multi-scale fractures. The fluid pressure and velocity distributions obtained from this study are important and can considered for further studies in hydraulic fracturing and production optimization of NFRs.
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Morrison, D. J. "Experimental and computational modelling of the flows in service reservoirs." Thesis, Cranfield University, 1999. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.323928.
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