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1
Campbell, Bruce T., and Franklin M. Orr. "Flow Visualization for CO2/Crude-Oil Displacements." Society of Petroleum Engineers Journal 25, no. 05 (October 1, 1985): 665–78. http://dx.doi.org/10.2118/11958-pa.
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Abstract Results of visual observations of high-pressure CO2 floods are reported. The displacements were performed in two-dimensional (2D) pore networks etched in glass plates. Results of secondary and tertiary first-contact miscible displacements and secondary and tertiary multiple-contact miscible displacements are compared. Three displacements with no water present were performed in each of three pore networks:displacement of a refined oil by the same oil dyed a different color;displacement of a refined oil by CO2 (first-contact miscible); anddisplacement of a crude oil at a pressure above the minimum miscibility pressure. In addition, three tertiary displacements were performed in the same pore networks;displacement of the refined oil by water, followed by displacement by the same refined oil dyed to distinguish it from the original oil;tertiary displacement of the refined oil by CO2; andtertiary displacement of crude oil by CO2. In addition, recovery of oil from dead-end pores, with and without water barriers shielding the oil, was investigated. Visual observations of pore-level displacement events indicate that CO2 displaced oil much more efficiently in both first-contact and multiple-contact miscible displacements when water was absent. In tertiary displacements of a refined oil, CO2 effectively displaced the oil it contacted, but high water saturations restricted access of CO2 to the oil. The low viscosity of CO2 aggravated effects of high water saturations because the CO2 did not displace water efficiently. CO2 did, however, contact trapped oil by diffusing through water to reach, to swell, and to reconnect isolated droplets. Finally, CO2 displaced crude oil more efficiently than it did the refined oil in tertiary displacements. Differences in wetting behavior between the refined and crude oils appear to account for the different flow behavior. Introduction If high-pressure CO2 displaces oil in a one-dimensional (1D), uniform porous medium (in which the effects of viscous fingering are necessarily absent), the displacement efficiency is controlled by the phase behavior of the CO2/crude-oil mixtures. The conventional description of the effects of phase behavior was given by Hutchinson and Braun1 for vaporizing gas drives and was extended to CO2 systems by Rathmell et al.2 In a rigorous mathematical treatment of the flow of three-component mixtures. Helfferich3 proved that the displacement will develop miscibility if the oil composition lies outside the region of tie-line extensions on a ternary diagram. Helfferich's analysis was for 1D flows in which fluids are mixed well locally, and the effects of dispersion are absent. Sigmund et al.,4 Gardner et al.,5 and Orr et al.6 showed that results of slim-tube displacements, which are nearly 1D and come close to eliminating the effects of viscous instability, can be predicted quantitatively by 1D process simulations based on independent measurements of the phase behavior and fluid properties of the CO2/crude-oil mixtures. Thus there is good experimental confirmation that the simple theory of the effects of phase behavior on displacement performance describes accurately the behavior of flow in an ideal displacement, such as a slim tube. In a CO2 flood in reservoir rock, however, a variety of other factors will influence process performance. Because the viscosity CO2 is much lower than that of most oils, viscous instability will limit the sweep efficiency of the injected CO2. In addition, Gardner and Ypma7 predicted, based on 2D simulations of the growth of a viscous finger, that an interaction between viscous instability and phase behavior would lead to higher residual oil saturation in regions penetrated by a viscous finger. Pore-structure heterogeneity may also influence displacement efficiency. Spence and Watkins8 found that residual oil saturations after CO2 waterfloods increased as the heterogeneity of the core increased. Several investigators have reported that high water saturations can alter mixing between oil and injected solvent. Raimondi and Torcaso9 found, in displacements in Berea sandstone cores, that significant fractions of the oil phase could not be contacted by injected solvent when the water saturation was high. Thomas et al.10 reported that a portion of the nonwetting phase can exist in "dendritic" pores whose shapes were determined by the surrounding wetting phase. They argued that material in the dendritic pores mixed with fluid in the flowing fraction only by diffusion. Stalkup11 and Shelton and Schneider12 also investigated effects of mobile water saturations in miscible displacements. Stalkup found that the flowing fraction decreased as the water saturation increased. Shelton and Schneider reported that the presence of a second mobile phase slowed recovery of either phase, but the nonwetting phase was affected more strongly. In their tests, all of the wetting phase was recovered by a miscible displacement, but significant amounts of nonwetting phase remained unrecovered.
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Kamali, Fatemeh, Furqan Hussain, and Yildiray Cinar. "An Experimental and Numerical Analysis of Water-Alternating-Gas and Simultaneous-Water-and-Gas Displacements for Carbon Dioxide Enhanced Oil Recovery and Storage." SPE Journal 22, no. 02 (August 30, 2016): 521–38. http://dx.doi.org/10.2118/183633-pa.
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Summary This paper presents an experimental and numerical study that delineates the co-optimization of carbon dioxide (CO2) storage and enhanced oil recovery (EOR) in water-alternating-gas (WAG) and simultaneous-water-and-gas (SWAG) injection schemes. Various miscibility conditions and injection schemes are investigated. Experiments are conducted on a homogeneous, outcrop Bentheimer sandstone sample. A mixture of hexane (C6) and decane (C10) is used for the oil phase. Experiments are run at 70°C and three different pressures (1,300, 1,700, and 2,100 psi) to represent immiscible, near-miscible, and miscible displacements, respectively. WAG displacements are performed at a WAG ratio of 1:1, and a fractional gas injection (FGI) of 0.5 is used for SWAG displacements. The effect of varying FGI is also examined for the near-miscible SWAG displacement. Oil recovery, differential pressure, and compositions are recorded during experiments. A co-optimization function for CO2 storage and incremental oil production is defined and calculated by use of the measured data for each experiment. The results of SWAG and WAG displacements are compared with the experimental data of continuous-gas-injection (CGI) displacements. A compositional commercial reservoir simulator is used to examine the recovery mechanisms and the effect of mobile water on gas mobility. Experimental observations demonstrate that the WAG displacements generally yield higher co-optimization function than CGI and SWAG with FGI = 0.5 displacements. Numerical simulations show a remarkable reduction in gas relative permeability for the WAG and SWAG displacements compared with CGI displacements, as a result of which the vertical-sweep efficiency of CO2 is improved. More reduction of gas relative permeability is observed in the miscible and near-miscible displacements than in the immiscible displacement. The reduced gas relative permeability lowers the water-shielding effect, thereby enhancing oil recovery and CO2-storage efficiency. More water-shielding effect is observed in SWAG with FGI = 0.5 than in WAG. However, increasing FGI from 0.5 to 0.75 in the near-miscible SWAG displacement shows a significant increase in oil recovery, which is attributed to reduced water-shielding effect. So, an optimal FGI needs to be determined to minimize the water-shielding effect for efficient SWAG displacements.
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Bera, Bijoyendra, Ines Hauner, Mohsin Qazi, Daniel Bonn, and Noushine Shahidzadeh. "Oil-water displacements in rough microchannels." Physics of Fluids 30, no. 11 (November 2018): 112101. http://dx.doi.org/10.1063/1.5053625.
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Brailovsky, I., A. Babchin, M. Frankel, and G. Sivashinsky. "Fingering Instability in Water-Oil Displacement." Transport in Porous Media 63, no. 3 (June 2006): 363–80. http://dx.doi.org/10.1007/s11242-005-8430-z.
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Namdar Zanganeh, M., S. I. I. Kam, T. C. C. LaForce, and W. R. R. Rossen. "The Method of Characteristics Applied to Oil Displacement by Foam." SPE Journal 16, no. 01 (August 19, 2010): 8–23. http://dx.doi.org/10.2118/121580-pa.
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Summary Solutions obtained by the method of characteristics (MOC) provide key insights into complex foam enhanced-oil-recovery (EOR) displacements and the simulators that represent them. Most applications of the MOC to foam have excluded oil. We extend the MOC to foam flow with oil, where foam is weakened or destroyed by oil saturations above a critical oil saturation and/or weakened or destroyed at low water saturations, as seen in experiments and represented in foam simulators. Simulators account for the effects of oil and capillary pressure on foam using algorithms that bring foam strength to zero as a function of oil or water saturation, respectively. Different simulators use different algorithms to accomplish this. We examine SAG (surfactant-alternating-gas) and continuous foam-flood (coinjection of gas and surfactant solution) processes in one dimension, using both the MOC and numerical simulation. We find that the way simulators express the negative effect of oil or water saturation on foam can have a large effect on the calculated nature of the displacement. For instance, for gas injection in a SAG process, if foam collapses at the injection point because of infinite capillary pressure, foam has almost no effect on the displacement in the cases examined here. On the other hand, if foam maintains finite strength at the injection point in the gas-injection cycle of a SAG process, displacement leads to implied success in several cases. However, successful mobility control is always possible with continuous foam flood if the initial oil saturation in the reservoir is below the critical oil saturation above which foam collapses. The resulting displacements can be complex. One may observe, for instance, foam propagation predicted at residual water saturation, with zero flow of water. In other cases, the displacement jumps in a shock past the entire range of conditions in which foam forms. We examine the sensitivity of the displacement to initial oil and water saturations in the reservoir, the foam quality, the functional forms used to express foam sensitivity to oil and water saturations, and linear and nonlinear relative permeability models.
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Zhou, Wen Sheng, Xiao Ru He, Zhan Li Geng, and Ji Cheng Zhang. "Water Displacement Rule at Extra-High Water Cut Stage." Advanced Materials Research 1073-1076 (December 2014): 2239–43. http://dx.doi.org/10.4028/www.scientific.net/amr.1073-1076.2239.
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During the development of the oilfield, the water cut of the water controlled field is an aggregative indicator which is affected by various factors. It can reflect the restriction of liquid flowing rules from the oil layer and crude oil physical property, and the effect of serious technical measures during the exploitation. Water cut increasing rate is closely related with water cut. The level of water-cut increasing rate of various well network was evaluated during oil producing with extra-high water cut in Xingnan development area, compared the differences among various well networks, and analyzed the geology causes and development causes.
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Zhao, Jin, Guice Yao, and Dongsheng Wen. "Pore-scale simulation of water/oil displacement in a water-wet channel." Frontiers of Chemical Science and Engineering 13, no. 4 (October 1, 2019): 803–14. http://dx.doi.org/10.1007/s11705-019-1835-y.
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Abstract Water/oil flow characteristics in a water-wet capillary were simulated at the pore scale to increase our understanding on immiscible flow and enhanced oil recovery. Volume of fluid method was used to capture the interface between oil and water and a pore-throat connecting structure was established to investigate the effects of viscosity, interfacial tension (IFT) and capillary number (Ca). The results show that during a water displacement process, an initial continuous oil phase can be snapped off in the water-wet pore due to the capillary effect. By altering the viscosity of the displacing fluid and the IFT between the wetting and non-wetting phases, the snapped-off phenomenon can be eliminated or reduced during the displacement. A stable displacement can be obtained under high Ca number conditions. Different displacement effects can be obtained at the same Ca number due to its significant influence on the flow state, i.e., snapped-off flow, transient flow and stable flow, and ultralow IFT alone would not ensure a very high recovery rate due to the fingering flow occurrence. A flow chart relating flow states and the corresponding oil recovery factor is established.
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Suleimanov, B. A., F. S. Ismayilov, O. A. Dyshin, and N. I. Huseynova. "Fractal analysis of oil - water displacement front." "Proceedings" of "OilGasScientificResearchProjects" Institute, SOCAR, no. 4 (December 30, 2011): 36–43. http://dx.doi.org/10.5510/ogp20110400091.
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Liu, Haohan. "New Water-Oil Displacement Efficiency Prediction Method." Open Petroleum Engineering Journal 7, no. 1 (January 9, 2015): 88–91. http://dx.doi.org/10.2174/1874834101407010088.
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Abbasov, É. M., and T. S. Kengerli. "Integral Simulation of Oil Displacement by Water." Journal of Engineering Physics and Thermophysics 92, no. 2 (March 2019): 441–49. http://dx.doi.org/10.1007/s10891-019-01949-z.
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Argüelles-Vivas, F. J., and T. Babadagli. "Analytical Solutions and Derivation of Relative Permeabilities for Water-Heavy Oil Displacement and Gas-Heavy Oil Gravity Drainage Under Non-Isothermal Conditions." SPE Reservoir Evaluation & Engineering 19, no. 01 (January 20, 2016): 181–91. http://dx.doi.org/10.2118/179722-pa.
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Summary Analytical models were developed for non-isothermal gas/heavy-oil gravity drainage and water-heavy oil displacements in round capillary tubes including the effects of a temperature gradient throughout the system. By use of the model solution for a bundle of capillaries, relative permeability curves were generated at different temperature conditions. The results showed that water/gas-heavy oil interface location, oil-drainage velocity, and production rate depend on the change of oil properties with temperature. The displacement of heavy oil by water or gas was accelerated under a positive temperature gradient, including the spontaneous imbibition of water. Relative permeability curves were greatly affected by temperature gradient and showed significant changes compared with the curves at constant temperature. Clarifications were made as to the effect of variable temperature compared with the constant (but high) temperatures throughout the bundle of capillaries.
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Graue, Arne, Johannes Ramsdal, and Martin A. Fernø. "Mobilization of Immobile Water: Connate-Water Mobility During Waterfloods In Heterogeneous Reservoirs." SPE Journal 20, no. 01 (June 18, 2014): 88–98. http://dx.doi.org/10.2118/170249-pa.
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Summary In a series of laboratory waterfloods, we investigate the extent of mixing of injection water and connate water, connate-water mobility, and connate-water banking during water injection for enhanced oil recovery (EOR). Local dynamic water saturations of connate water and injected water were imaged individually by use of a nuclear-tracer technique. The connate water was displaced from the pore space by the injected water and accumulated downstream in a connate-water bank that advanced toward the production end. The connate-water bank significantly reduced the contact between the injected water and mobile oil. During capillary displacement—i.e., during spontaneous imbibition without a viscous pressure drop—the connate water was also mobilized and accumulated downstream in the core. During viscous displacement—i.e. with a pressure gradient as small as 0.3 mbar/cm—the accumulated connate water was mobilized in a miscible displacement and produced from the core. Only a small mixing zone was observed between the injected and connate waters, even with fully miscible conditions by use of identical brine compositions. The results of the displacement mechanisms experimentally visualized in this work are important for water-based EOR techniques, including low-salinity-water and polymer injections, as well as any tertiary oil-recovery method based on chemical injection.
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Wingard, J. S., and F. M. Orr. "An Analytical Solution for Steam/Oil/Water Displacements." SPE Advanced Technology Series 2, no. 02 (April 1, 1994): 167–76. http://dx.doi.org/10.2118/19667-pa.
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Kortekaas, T. F. M. "Water/Oil Displacement Characteristics in Crossbedded Reservoir Zones." Society of Petroleum Engineers Journal 25, no. 06 (December 1, 1985): 917–26. http://dx.doi.org/10.2118/12112-pa.
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Kortekaas, T.F.M., SPE, Shell Research B.V. Abstract Festoon crossbedding is a typical sedimentary structure in sandstone reservoirs. It is especially common in fluvial deposits. The important elements are the foreset laminae, which vary in permeability, and the bottomsets of lower permeability. To understand the complex, direction-dependent displacement characteristics of a crossbedded reservoir zone, we first conducted numerical simulations on a centimeter scale in a small part of a water-wet crossbedded reservoir zone. The simulations indicate that, during water/oil displacement, considerable amounts of movable oil initially are left behind in the higher-permeability foreset laminae with fluid flow perpendicular to the foreset laminae, while with flow parallel to the foreset laminae the displacement efficiency is good. To describe the displacement characteristics on a reservoir scale, we developed a procedure for calculating direction-dependent pseudo relative-permeability and capillary-pressure curves to be used as input for the simulations of water/oil displacement in a crossbedded reservoir zone. On a reservoir scale, the displacement characteristics in a water-wet crossbedded reservoir zone are slightly more favorable with the main fluid flow perpendicular to the foreset laminae. perpendicular to the foreset laminae. In addition, the sensitivity of the displacement characteristics to moderate reductions in interfacial tensions (IFT's) and to increases in water viscosity was investigated, both on a centimeter scale and on a reservoir scale. The simulations indicate the potential for substantial improvement in recovery from crossbedded reservoir zones if diluted surfactant or polymer is added to the drive water. Introduction Detailed studies of the effect of reservoir heterogeneities on water/oil displacement characteristics have been conducted on a well-to-well (layering) scale and on a pore scale, but few studies on an intermediate scale have been done. Therefore, we embarked on a study of the effect of centimeter-scale heterogeneities on water/oil displacement characteristics. We studied festoon crossbedding, one of the typical sedimentary structures in sandstone reservoirs, particularly common in fluvial deposits. A schematic particularly common in fluvial deposits. A schematic representation of a small part of a crossbedded reservoir zone is given in Fig. 1A. The important elements are the foreset laminae, which vary in permeability, and the bottom-sets, which are of lower permeability. The width of the foreset laminae is exaggerated in Fig. 1A; typically it is a few centimeters. First, we will discuss a mathematical simulation study in a very limited area of a water-wet crossbedded reservoir zone (1.97 × 26.2 × 0.66 ft [0.6 × 8 × O.2 m]). After a brief discussion of the water/oil displacement characteristics near a single permeability transition, we present the water/oil displacement characteristics in some cross sections of a simplified model (Fig. 1B) of a small part of a crossbedded reservoir zone. In addition, their sensitivity to moderate reductions in IFT's and increases in water viscosity are discussed. Second, we describe the effect of crossbedding on water/oil displacement characteristics on a reservoir scale, discuss a procedure for calculating dynamic, direction-dependent pseudo relative-permeability and capillary-pressure curves, and present the results of a reservoir-scale mathematical simulation study, including the pseudo-properties. Also, the sensitivity of the results to changes pseudo-properties. Also, the sensitivity of the results to changes in IFT and water viscosity is discussed. One-Dimensional Water/Oil Displacement Characteristics Near an Abrupt Permeability Transition Permeability Transition suppose we have a one-dimensional (1D) system consisting of two zones with different absolute, but identical relative, permeabilities. Furthermore, the system is horizontal and contains oil and connate water. The Buckley-Leverett first-order partial differential equation describes the water/oil displacement in each zone.In the absence of capillary and gravitational forces, the water fractional flow Fwo) is given byEq. 1, together with Eq. 2, usually leads to a sharp shock front: at each location, water saturation will instantaneously jump from connate water to shock-front saturation when the water arrives. SPEJ p. 917
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Korsbech, Uffe, Helle Aage, Kathrine Hedegaard, Bertel L. Andersen, and Niels Springer. "Measuring and Modeling the Displacement of Connate Water in Chalk Core Plugs During Water Injection." SPE Reservoir Evaluation & Engineering 9, no. 03 (June 1, 2006): 259–65. http://dx.doi.org/10.2118/78059-pa.
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Summary The movement of connate water spiked with gamma-emitting 22 Na (a radioactive sodium isotope) was studied during laboratory waterflooding of oil-saturated chalk at connate-water saturation from a North Sea reservoir. Using a 1D gamma-monitoring technique, it was observed that connate water is piled up at the front of the injection water and forms a mixed water bank with almost 100% connate water in the front, behind which a gradual transition to pure injection water occurs. This result underpins log interpretations from waterflooded chalk reservoirs. An ad hoc model was set up by use of the results, and the process was examined theoretically at a larger scale. Introduction The behavior of the in-situ, or connate, water in an oil reservoir under waterflooding has been investigated only sparsely in the past. A study of the mobility of connate water in sandpacks during waterflooding showed that the connate water became mobile and formed a buffer zone between the injection water and the mobilized oil phase (Brown 1957). Water imbibition in a fractured chalk plug using D2O (labeled connate water) and nuclear magnetic resonance (NMR) imaging showed that the connate water was swept up in front of the imbibing water (Nielsen et al. 2000). If these observations are valid on a reservoir scale, it means that it is the connate water that actually displaces the oil during a waterflood. Laboratory corefloods have demonstrated that the remaining oil saturation after a waterflood depends on chalk type, chalk porosity, and initial oil saturation. Waterflooding of oil-saturated chalk cores develops an oil/water shock front that displaces the mobile oil in a nearly pistonlike manner with very little oil cut after water breakthrough, in agreement with theoretical expectations (Dake 1978). Sharp oil/water fronts have been observed from logging of waterflooded zones in North Sea chalk reservoirs (Ovens et al. 1998). The actual oil saturation and its potential variation within the waterflooded zone is, however, often difficult to assess from standard petrophysical logs of a waterflooded zone because of a change in resistivity and temperature after injection of cold seawater. An a priori model has been proposed by Ovens et al. (1998) from an inspection of resistivity profiles across waterflooded zones in the Danish North Sea. The observations indicate that the injection of cold seawater into an oil-bearing chalk reservoir will generate a bank of reservoir-temperature formation water between the cold injection water and the displaced oil. The logs (porosity, water saturation, and deep resistivity) show that the injected water does not mix thoroughly with the formation water when the oil/water front progresses through the reservoir. In an attempt to verify the a priori model, a dedicated laboratory waterflooding program was developed. Synthetic seawater with a chemical composition corresponding to diluted Dan field brine was injected into plugs saturated with oil and connate water of the same chemical composition as the synthetic seawater. The connate water, however, was spiked with 22Na (gamma ray emitter), whereby the movement of connate water could be followed in time and space. Basic parameters have been determined from the experiments, and an ad hoc model describing the interaction between injection water, oil, and connate water has been constructed. Finally, this model has been used to predict what will happen for a deep penetration of injection water into chalk saturated with oil and connate water.
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Zhang, Fu Sheng, Jian Ouyang, De Wei Wang, Xin Fang Feng, and Li Qing Xu. "Mechanisms of Enhancing Recovery of the Superficial Heavy Oil Reservoir." Advanced Materials Research 550-553 (July 2012): 468–71. http://dx.doi.org/10.4028/www.scientific.net/amr.550-553.468.
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The core displacement experiments show that displacement system containing chemical agent can enhance oil recovery by over 20% comparing to water flooding. Mechanisms by which chemical agent enhance oil recovery of heavy oil reservoir water flooding are: (1) improving mobility ratio by significantly decreasing viscosity of heavy oil, volumetric sweep efficiency is improved; (2) increasing capillary number by significantly decreasing oil-water interfacial tension, oil displacement efficiency is increased; (3) changing wettability of the rock surface from oil-wet to water-wet by significantly reducing the contact angle between displacement liquid and sandstone surface, capillary force is changed from the resistance force to the motive force, the residual oil is expelled from the small pores and the wall of pores, oil displacement efficiency is significantly increased.
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Xiao, Huaping, Dan Guo, Shuhai Liu, Guoxin Xie, Guoshun Pan, Xinchun Lu, and Jianbin Luo. "Direct observation of oil displacement by water flowing toward an oil nanogap." Journal of Applied Physics 110, no. 4 (August 15, 2011): 044906. http://dx.doi.org/10.1063/1.3624732.
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Bakurov, V. G., V. I. Gusev, A. F. Izmailov, and A. R. Kessel. "Dynamical percolation model of oil displacement by water in the oil reservoir." Journal of Physics A: Mathematical and General 23, no. 12 (June 21, 1990): 2507–21. http://dx.doi.org/10.1088/0305-4470/23/12/028.
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Tangparitkul, Suparit, Thibaut Charpentier, Diego Pradilla, and David Harbottle. "Interfacial and Colloidal Forces Governing Oil Droplet Displacement: Implications for Enhanced Oil Recovery." Colloids and Interfaces 2, no. 3 (July 18, 2018): 30. http://dx.doi.org/10.3390/colloids2030030.
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Growing oil demand and the gradual depletion of conventional oil reserves by primary extraction has highlighted the need for enhanced oil recovery techniques to increase the potential of existing reservoirs and facilitate the recovery of more complex unconventional oils. This paper describes the interfacial and colloidal forces governing oil film displacement from solid surfaces. Direct contact of oil with the reservoir rock transforms the solid surface from a water-wet to neutrally-wet and oil-wet as a result of the deposition of polar components of the crude oil, with lower oil recovery from oil-wet reservoirs. To enhance oil recovery, chemicals can be added to the injection water to modify the oil-water interfacial tension and solid-oil-water three-phase contact angle. In the presence of certain surfactants and nanoparticles, a ruptured oil film will dewet to a new equilibrium contact angle, reducing the work of adhesion to detach an oil droplet from the solid surface. Dynamics of contact-line displacement are considered and the effect of surface active agents on enhancing oil displacement discussed. The paper is intended to provide an overview of the interfacial and colloidal forces controlling the process of oil film displacement and droplet detachment for enhanced oil recovery. A comprehensive summary of chemicals tested is provided.
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Zhang, Xiang Chun, Wei Sun, Tian Li Rao, Hai Zeng Jing, Yong Jing, Qiang Chen, Bin Chen, and Hang Li. "Characteristics and Influence Factors for Oil Displacement Efficiency by the Micro-Model Water Flooding Experiment in Low Permeability Reservoir." Advanced Materials Research 1092-1093 (March 2015): 1371–74. http://dx.doi.org/10.4028/www.scientific.net/amr.1092-1093.1371.
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Through the displacement experiment of low permeability sandstone micro model of water Erdos basin, summing up the water displacing oil characteristics, and to explore the influencing factors of micro water oil displacement efficiency. The study found that, the water flooding characteristic main performance for: flooding mode mainly by non piston displacement; heterogeneity is strong, the oil displacement efficiency is low; the crude oil viscosity is low, the oil displacement efficiency is high; the main influencing factors are: physical; heterogeneity; displacement ratio. Therefore, for low permeability sandstone reservoir development, process parameters should be selected reasonably, in order to ensure the good development effect.
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Lv, Mingming, and Shuzhong Wang. "Pore-scale modeling of a water/oil two-phase flow in hot water flooding for enhanced oil recovery." RSC Advances 5, no. 104 (2015): 85373–82. http://dx.doi.org/10.1039/c5ra12136a.
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Yin, Dai Yin, Shuai Wang, Bo Ying, and Cheng Li Zhang. "Laboratory Experimental Study on Advanced Water Injection." Applied Mechanics and Materials 229-231 (November 2012): 661–64. http://dx.doi.org/10.4028/www.scientific.net/amm.229-231.661.
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Advanced water injection can keep a high level of formation pressure, reduce the damage of permeability caused by the drop of formation pressure, and improve the oil displacement efficiency. Through pressure sensitive experiment and Micro-CT scan method, this paper study the influence on rock parameters by formation pressure. The results show that permeability decreases greatly in depressurization development, the permeability restores a small degree after restoring pressure, the change of coordination number and pore throat radius is similar with permeability, and porosity is not sensitive to pressure. Through the research on the influence of oil displacement efficiency by drive pressure, the results show that advanced water injection can improve the oil phase relative permeability, the average increase rate is 5.02%, and also increase oil displacement efficiency, the increase rate is 1%. The core fluorescence images indicate that the remaining oil by advance water injection is obviously less than the conventional production.
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Graue, Arne, Martin A. Fernø, Robert W. Moe, Bernard A. Baldwin, and Riley Needham. "Water Mixing During Waterflood Oil Recovery: The Effect of Initial Water Saturation." SPE Journal 17, no. 01 (November 30, 2011): 43–52. http://dx.doi.org/10.2118/149577-pa.
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Summary This work studies the mixing of injected water and in-situ water during waterfloods and demonstrates that the mixing process is sensitive to the initial water saturation. The results illustrate differences between a waterflooded zone and a preflooded zone during, for example, water-based EOR displacement processes. The mixing of in-situ, or connate, water and injected water during laboratory waterfloods in a strongly water-wet chalk core sample was determined at different initial water saturations. Dynamic 1D fluid-saturation profiles were determined with nuclear-tracer imaging (NTI) during waterfloods, distinguishing between the oil phase, connate water, and injected water. The mixing of connate and injected water during waterfloods, with the presence of an oil phase, resulted in a displacement of all connate water from the core plug. During displacement, connate water banked in front of the injecting water, separating (or partially separating) the injected water from the mobile oil phase. This may impact the ability of chemicals dissolved in the injected water to contact the oil during secondary recovery and EOR processes. The effect of the connate-water-bank separation was sensitive to the initial water saturation (Swi). The time difference between breakthrough of connate water and breakthrough of injected water at the outlet showed a linear correlation to the initial water saturation Swi. The results obtained in chalk confirmed earlier findings in sandpacks (Brown 1957) and thus demonstrated the generality in the results.
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Maya Toro, Gustavo, Luisana Cardona Rojas, Mayra Fernanda Rueda Pelayo, and Farid B. Cortes Correa. "Effect of ionic strength in low salinity water injection processes." CT&F - Ciencia, Tecnología y Futuro 10, no. 2 (December 17, 2020): 17–26. http://dx.doi.org/10.29047/01225383.269.
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Low salinity water injection has been frequently studied as an enhanced oil recovery process (EOR), mainly due to promising experimental results and because operational needs are not very different from those of the conventional water injection. However, there is no agreement on the mechanisms involved in increasing the displacement of crude oil, except for the effects of wettability changes. Water injection is the oil recovery method mostly used, and considering the characteristics of Colombian oil fields, this study analyses the effect of modifying the ionic composition of the waters involved in the process, starting from the concept of ionic strength (IS) in sandstone type rocks.
The experimental plan for this research includes the evaluation of spontaneous imbibition (SI), contact angles, and displacement efficiencies in Berea core plugs. Interfacial tension and pH measurements were also carried out. The initial scenario consists in formation water (FW), with a total concentration of 9,800 ppm (TDS) (IS ~ 0.17) and a 27 °API crude oil. Magnesium and Calcium brine were also used in a first approach to assess the effect of the divalent ions.
Displacement efficiency tests are performed using IS of 0.17, 0.08, and 0.05, as secondary and tertiary oil recovery and the recovery of oil increases in both scenarios. Spontaneous imbibition curves and contact angle measurements show variations as a function of the ionic strength, validating the displacement efficiencies.
Interfacial tension and pH collected data evidence that fluid/fluid interactions occur due to ionic strength modifications. However, as per the conditions of this research, fluid/fluid mechanisms are not as determining as fluid/rock.
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Khalilov, M. S. "Predicting development parameters for gas-condensate deposits with oil banks in the exploitation of horizontal wells." Azerbaijan Oil Industry, no. 4 (April 15, 2020): 19–24. http://dx.doi.org/10.37474/0365-8554/2020-4-19-24.
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The paper presents comparative analysis of technological parameters of depletion and water-oil displacement modes during the exploitation of oil banks in gas-condensate deposit with horizontal well in gas-free production rates based on the three-phase multi-component filtration model. In water-oil displacement regime the oil recovery factors were higher compared to the depletion mode. The development profitability was justified. The increase of oil recovery factor in water-oil displacement regime is achieved due to the weak rate of flooding in well production and unrecoverable capacity of the fluid injected into the reservoir. The practicability of oil banks exploitation in gas-condensate deposit in gas-free rates at the first stage of development in depletion and in water-oil displacement modes at further stage correspondingly is justified.
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Kamali, Fatemeh, Furqan Hussain, and Yildiray Cinar. "A Laboratory and Numerical-Simulation Study of Co-Optimizing CO2 Storage and CO2 Enhanced Oil Recovery." SPE Journal 20, no. 06 (December 18, 2015): 1227–37. http://dx.doi.org/10.2118/171520-pa.
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Summary This paper presents experimental observations that delineate co-optimization of carbon dioxide (CO2) enhanced oil recovery (EOR) and storage. Pure supercritical CO2 is injected into a homogeneous outcrop sandstone sample saturated with oil and immobile water under various miscibility conditions. A mixture of hexane and decane is used for the oil phase. Experiments are run at 70°C and three different pressures (1,300, 1,700, and 2,100 psi). Each pressure is determined by use of a pressure/volume/temperature simulator to create immiscible, near-miscible, and miscible displacements. Oil recovery, differential pressure, and compositions are recorded during experiments. A co-optimization function for CO2 storage and incremental oil is defined and calculated using the measured data for each experiment. A compositional reservoir simulator is then used to examine gravity effects on displacements and to derive relative permeabilities. Experimental observations demonstrate that almost similar oil recovery is achieved during miscible and near-miscible displacements whereas approximately 18% less recovery is recorded in the immiscible displacement. More heavy component (decane) is recovered in the miscible and near-miscible displacements than in the immiscible displacement. The co-optimization function suggests that the near-miscible displacement yields the highest CO2-storage efficiency and displays the best performance for coupling CO2 EOR and storage. Numerical simulations show that, even on the laboratory scale, there are significant gravity effects in the near-miscible and miscible displacements. It is revealed that the near-miscible and miscible recoveries depend strongly on the endpoint effective CO2 permeability.
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Feyzulaev, H. A., and S. V. Agalarova. "Forecasting of the technological parameters of the oil displacement with the various mineral content water in the clay storage collector." SOCAR Proceedings, no. 3 (September 30, 2020): 135–41. http://dx.doi.org/10.5510/ogp20200300454.
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A multicomponent hydrodynamic model of the process of oil displacement with water with different mineralogical composition in clay-containing collectors is proposed on the basis of combination of equations of continuity, filtration law and equation of state, equation of salt concentration in water and equation of saturation between phases which enables prediction of process parameters of oil displacement with fresh and formation waters with and without consideration of clay swelling.
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Yang, Manping, Lu Jiang, Shuxiang Guo, Liming Zheng, and Ling Meng. "Experimental Study on Rational Water Injection Rate in Continental Sandstone Reservoirs." Open Chemical Engineering Journal 13, no. 1 (November 15, 2019): 114–21. http://dx.doi.org/10.2174/1874123101913010114.
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Objective: In this paper, an experimental model of water flooding was designed and manufactured, and experiments on high permeability and low permeability models were carried out. Methods: The relationship between injection rate, injection pore volume multiple and oil displacement efficiency, injection rate, injection pore volume multiple and water content in two kinds of permeability was analyzed. Results: There is a certain relationship between oil displacement efficiency and water injection speed. There is a reasonable water injection speed, which can achieve the highest oil displacement efficiency. The lower the permeability the lower will be the reasonable injection rate . In the reasonable range of water injection rate, the injection rate increases gradually, and the best oil displacement effect can be obtained. Conclusion: Through analysis, it was concluded that the oil displacement efficiency of artificial rocks with various water injection rates was different even in the same permeability experimental model. It was indicated that the water flooding recovery of the reservoir can be improved by using the method of strong injection and strong production in the middle and later stage of development.
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Xiong, Sheng Chun, Ying He, and Mao Lei Cui. "Petroleum Sulfonates as Oil Displacement Agent and Application." Advanced Materials Research 529 (June 2012): 512–16. http://dx.doi.org/10.4028/www.scientific.net/amr.529.512.
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In terms of the condition of injection water after polymer flooding of Gudao oilfield, the following water quickly broke though the bank to the production wells, while most of residual oil remains in the formation. To solve the problem, two kind of petroleum sulfonates made in China are selected to form oil displacement agent (ODA) solution. The petroleum sulfonate available for crude oil of Gudao oilfield with the ultra-low interfacial tension is found by drawing an oil/water interfacial tension contour diagram. The results show that the interfacial tension can be lower than 3.6×10-4mN/m when the active agent contained with 0.25%KPS+0.225%APS, and the agent reduces water resistance of entering the hole to improve sweep coefficient and oil displacement efficiency. The existence of the polymer has no influence on the balanced value of interfacial tension, but just delays the interfacial tension to reach the balance. Pouring into 0.3 pore volume (PV) high-efficient ODA can improve 17% oil recovery. Synergistic effect of two kind of petroleum sulfonate with low cost to enhance oil recovery will have a great prospect for enhanced oil recovery (EOR)
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Liu, Xiong, Desheng Zhou, Le Yan, Shun Liu, and Yafei Liu. "On the Imbibition Model for Oil-Water Replacement of Tight Sandstone Oil Reservoirs." Geofluids 2021 (May 23, 2021): 1–7. http://dx.doi.org/10.1155/2021/8846132.
Full textAbstract:
A model suitable for evaluating a tight sandstone reservoir is established. The model includes two oil-water replacement modes: capillary force mode and osmotic pressure mode. The relationship between oil-water displacement rate and dimensionless time under different parameters is drawn considering the influence of capillary force, osmotic pressure, production pressure difference, and starting pressure gradient. Results indicate that the higher the relative permeability of the water phase, the lower the relative permeability of the oil phase, the smaller the oil-water viscosity ratio, and the higher the oil-water replacement rate. The relative permeability of the water phase also affects the infiltration stabilization time. Low salinity fracturing fluid infiltration helps to improve the oil-water replacement rate.
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Freire Rigatto da Cruz, Suellen, Andreas Nascimento, and Oldrich Joel Romero. "PORE SCALE MODELING OF WETTABILITY EFFECTS ON WATER-OIL DISPLACEMENT." Latin American Applied Research - An international journal 50, no. 4 (September 25, 2020): 329–37. http://dx.doi.org/10.52292/j.laar.2020.474.
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Due to the concern about oil’s extraction efficiency decline throughout the time, researchers have looked for alternatives to raise the displacement efficiency of trapped oil within micropores, which has a known complex geometry. The use of numerical simulation presents advantages since it is an economically viable technology with good precision. The current proposition analyzes numerically and with the aid of the Ansys Fluent software, the influence of wettability in microcavity geometry in the displacement of oil by water. Several cases with different radius curvatures of the geometry, contact angles and their influence in displacement efficiency of residual oil are evaluated. The results led to a more realistic analysis regarding the mobilization of trapped oil within the microcavities.
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Astafiev, V. I., and A. E. Kasatkin. "WATERFLOODING FRONT MOVING TASK IN DUAL PERIODICAL AREA: PISTON-LIKE DISPLACEMENT CASE." Vestnik of Samara University. Natural Science Series 20, no. 10 (May 29, 2017): 116–29. http://dx.doi.org/10.18287/2541-7525-2014-20-10-116-129.
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Water-oil contact moving task has a high significance in a waterflooding the- ory: it’s possible to improve oil recovering characteristics due to prediction of flow features for both liquids - oil and water displaced it. There is the simplest mathematical pattern for conjoint oil-water flow presenting: it is called ”versi- color” liquids model and it suggests making oil and water physically identical to simplify solving process for water-oil contact moving task. However, another pattern was used in research described in this paper: it is called pistonlike dis- placement model and it supposes that oil and water physical characteristics, for example, viscosities, may be different. As for the oil-keeping reservoir pattern used in this research it was presented as homogeneous and infinity, with fixed thickness: furthermore its surface was covered by dual periodical lattice included production and injection wells in its cells.
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Huang, Bin, Chen Wang, Weisen Zhang, Cheng Fu, Haibo Liu, and Hongwei Wang. "Study on the Stability of Produced Water from Alkali/Surfactant/Polymer Flooding under the Synergetic Effect of Quartz Sand Particles and Oil Displacement Agents." Processes 8, no. 3 (March 9, 2020): 315. http://dx.doi.org/10.3390/pr8030315.
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With the wide application of ASP (alkali/surfactant/polymer) flooding oil recovery technology, the produced water from ASP flooding has increased greatly. The clay particles carried by crude oil in the process of flow have a synergetic effect with oil displacement agents in the produced water, which increases the treatment difficulty of produced water. The stability of produced water is decided by the stability of oil droplets in the ASP-flooding-produced water system. The oil content, Zeta potential, interfacial tension and oil droplet size are important parameters to characterize the stability of produced water. In this paper, the changes of the oil content, Zeta potential, interfacial tension and oil droplet size of ASP flooding oily wastewater under the synergetic effect of different concentrations of quartz sand particles and oil displacement agents were studied by laboratory experiments. The experimental results show that the negatively charged quartz sand particles can absorb active substances in crude oil and surfactant molecules in the water phase and migrate to the oil–water interface, which increases the repulsion between quartz sand particles, decreasing the oil–water interfacial tension. Thus, the stability of oil droplets is enhanced, and the aggregation difficulty between oil droplets and quartz sand particles is increased. With the continually increasing quartz sand concentration, quartz sand particles combine with surfactant molecules adsorbed on the oil–water interface to form an aggregate. Meanwhile, the polymer molecules crimp from the stretching state, and the number of them surrounding the surface of the flocculation structure is close to saturation, which makes the oil droplets and quartz sand particles prone to aggregation, and the carried active substances desorb from the interface, resulting in the instability of the produced water system. The research on the synergetic effect between quartz sand particles and oil displacement agents is of great significance for deepening the treatment of ASP-produced water.
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Tang, Shan Fa, Xiao Dong Hu, Xiang Nan Ouyang, Shuang Xi Yan, Shou Cheng Wen, and Yan Ling Lai. "Experimental Study of Anionic Gemini Surfactant Enhancing Waterflooding Recovery Ratio." Advanced Materials Research 361-363 (October 2011): 469–72. http://dx.doi.org/10.4028/www.scientific.net/amr.361-363.469.
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The oil-water interfacial tension measurement and enhancing water displacement recovery experiment were carried out, and the effects of various parameters such as category of surfactants, anionic Gemini surfactant concentration, water medium salinity, core permeability, polymer and non-ionic surfactant on anionic Gemini surfactants enhancing water displacement recovery were investigated in detail. The results show that surfactants category is different, its enhancing water flooding recovery efficiency is different, and effect of enhanced oil recovery is consistent with surfactant ability to reduce oil-water interfacial tension. The anionic Gemini surfactant AN12-4-12 is the best in enhancing water flooding recovery efficiency, because it can reduce the oil-water interfacial tension to 5×10-3 mN•m-1. Increasing the concentration of AN12-4-12 is favorable to enhance water displacement recovery. Such as when injecting 0.5PV solution containing 800mg•L-1 AN12-4-12, enhancing water displacement recovery is 11.67%. AN12-4-12 has good adaptability to different salinities (5~25×104 mg•L-1) and low permeability reservoir in improving water displacement recovery. Adding non-ionic surfactant ANT into AN12-4-12 solution can further reduce oil-water interfacial tension and enhance water flooding recovery efficiency. For example, injecting 0.5PV surfactant solution containing 400mg•L-1 AN12-4-12 and 100mg•L-1 can enhance water displacement recovery of 10.7%.
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Tan, Fengqi, Changfu Xu, Yuliang Zhang, Gang Luo, Yukun Chen, and Wentao Liu. "Differences of microscopic seepage mechanisms of water flooding and polymer flooding and prediction models of final oil recovery for conglomerate reservoir." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 74 (2019): 13. http://dx.doi.org/10.2516/ogst/2018086.
Full textAbstract:
The special sedimentary environments of conglomerate reservoir lead to pore structure characteristics of complex modal, and the reservoir seepage system is mainly in the “sparse reticular-non reticular” flow pattern. As a result, the study on microscopic seepage mechanism of water flooding and polymer flooding and their differences becomes the complex part and key to enhance oil recovery. In this paper, the actual core samples from conglomerate reservoir in Karamay oilfield are selected as research objects to explore microscopic seepage mechanisms of water flooding and polymer flooding for hydrophilic rock as well as lipophilic rock by applying the Computed Tomography (CT) scanning technology. After that, the final oil recovery models of conglomerate reservoir are established in two displacement methods based on the influence analysis of oil displacement efficiency. Experimental results show that the seepage mechanisms of water flooding and polymer flooding for hydrophilic rock are all mainly “crawling” displacement along the rock surface while the weak lipophilic rocks are all mainly “inrushing” displacement along pore central. Due to the different seepage mechanisms among the water flooding and the polymer flooding, the residual oil remains in hydrophilic rock after water flooding process is mainly distributed in fine throats and pore interchange. These residual oil are cut into small droplets under the influence of polymer solution with stronger shearing drag effect. Then, those small droplets pass well through narrow throats and move forward along with the polymer solution flow, which makes enhancing oil recovery to be possible. The residual oil in weak lipophilic rock after water flooding mainly distributed on the rock particle surface and formed oil film and fine pore-throat. The polymer solution with stronger shear stress makes these oil films to carry away from particle surface in two ways such as bridge connection and forming oil silk. Because of the essential attributes differences between polymer solution and injection water solution, the impact of Complex Modal Pore Structure (CMPS) on the polymer solution displacement and seepage is much smaller than on water flooding solution. Therefore, for the two types of conglomerate rocks with different wettability, the pore structure is the main controlling factor of water flooding efficiency, while reservoir properties oil saturation, and other factors have smaller influence on flooding efficiency although the polymer flooding efficiency has a good correlation with remaining oil saturation after water flooding. Based on the analysis on oil displacement efficiency factors, the parameters of water flooding index and remaining oil saturation after water flooding are used to establish respectively calculation models of oil recovery in water flooding stage and polymer flooding stage for conglomerate reservoir. These models are able to calculate the oil recovery values of this area controlled by single well control, and further to determine the oil recovery of whole reservoir in different displacement stages by leveraging interpolation simulation methods, thereby providing more accurate geological parameters for the fine design of displacement oil program.
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Sun, Guangyuan, Bernd Crouse, David M. Freed, Rui Xu, Juan Bautista, Raoyang Zhang, Hiroshi Otomo, et al. "Polymer flooding – Does Microscopic Displacement Efficiency Matter?" Revista Fuentes el Reventón Energético 16, no. 2 (November 20, 2018): 83–89. http://dx.doi.org/10.18273/revfue.v16n2-2018006.
Full textAbstract:
Polymer flooding is an enhanced oil recovery (EOR) technique that aims to enhance the stability of the flood front in order to increase sweep efficiency and thereby increase hydrocarbon recovery. Polymer flooding studies often focus on large-scale sweep efficiency and neglect the impact of the pore-scale displacement efficiency of the multi-phase flow. This work explores the pore-scale behavior of water vs polymer flooding, and examines the impact of rock surface wettability on the microscopic displacement efficiency using digital rock physics. In this study, a micro-CT image of a sandstone rock sample was numerically simulated for both water and polymer flooding under oil-wet and water-wet conditions. All simulations were performed at a capillary number of 1E-5, corresponding to a capillary dominated flow regime. Results of the four two-phase flow imbibition simulations are analyzed with respect to displacement character, water phase break-through, viscous/capillary fingering, and trapped oil. In the water-wet scenario, differences between water flood and polymer flood are small, with the flood front giving a piston-like displacement and breakthrough occurring at about 0.4 pore volume (PV) for both types of injected fluid. On the other hand, for the oil-wet scenario, water flood and polymer flood show significant differences. In the water flood, fingering occurs and much of the oil is bypassed early on, whereas the polymer flood displaces more oil and thereby provides better microscopic sweep efficiency throughout the flood and especially around breakthrough. Overall the results for this rock sample indicate that water flood and polymer flood provide similar recovery for a water-wet condition, while the reduced mobility ratio of polymer flood gives significantly improved recovery for an oil-wet condition by avoiding the onset of microscopic (pore-scale) fingering that occurs in the water flood. This study suggests that depending on the rock-fluid conditions, the use of polymer can impact microscopic sweep efficiency, in addition to the well-known effect on macroscopic sweep behavior
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Ashoori, E., T. L. M. L. M. van der Heijden, and W. R. R. Rossen. "Fractional-Flow Theory of Foam Displacements With Oil." SPE Journal 15, no. 02 (March 3, 2010): 260–73. http://dx.doi.org/10.2118/121579-pa.
Full textAbstract:
Summary Fractional-flow theory provides key insights into complex foam enhanced-oil-recovery (EOR) displacements and acts as a benchmark for foam simulators. In some cases with mobile oil present, the process can be represented as a two-phase displacement. We examine three such cases. A first-contact-miscible (FCM) gasflood with foam injection includes a chemical shock defining the surfactant front and a miscible shock defining the gas front. The optimal water fraction for the foam, that which gives the fastest oil recovery in 1D, maintains the gas front slightly ahead of the foam (surfactant) front. The success of a foam process with FCM CO2 and surfactant dissolved in the (supercritical) CO2 depends on the strength of foam at very low water fractional flow, such as for a surfactant- alternating-gas (SAG) process with surfactant dissolved in water. The speed of propagation of the foam front depends on surfactant adsorption on rock and on the partitioning of surfactant between water and CO2 but is always less than the velocity of the foam front in a SAG flood with surfactant ahead of the gas. A foam with surfactant that partitions preferentially into water rather than into CO2 would propagate slowly, regardless of the surfactant's absolute solubility or the level of adsorption on rock. An aqueous surfactant preflush can speed the advance of foam, however. An idealized model of a surfactant flood pushed by foam suggests that it is best to inject a relatively high water content into the foam to ensure that the gas front remains behind the surfactant front as the flood proceeds. Any gas that passes ahead of the surfactant front would finger through the oil and be wasted. We present simulations to verify the solutions obtained with fractional-flow methods and illustrate the challenges of accurate simulation of these processes.
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Romanova, D. I., V. R. Dushin, and V. F. Nikitin. "Oil Displacement by Water-Gas Mixtures with Heat Release." Moscow University Mechanics Bulletin 74, no. 6 (November 2019): 147–52. http://dx.doi.org/10.3103/s0027133019060025.
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Hirasaki, G. J., J. A. Rohan, and J. W. Dudley. "Interpretation of Oil/Water Relative Permeabilities From Centrifuge Displacement." SPE Advanced Technology Series 3, no. 01 (March 1, 1995): 66–75. http://dx.doi.org/10.2118/24879-pa.
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Oseto, Kazuhito, and Yasuyuki Mino. "MRI application to evaluation of oil and water displacement." Journal of the Japanese Association for Petroleum Technology 71, no. 6 (2006): 591–98. http://dx.doi.org/10.3720/japt.71.591.
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Fokker, Peter A., and Francesca Verga. "Application of harmonic pulse testing to water–oil displacement." Journal of Petroleum Science and Engineering 79, no. 3-4 (November 2011): 125–34. http://dx.doi.org/10.1016/j.petrol.2011.09.004.
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Mackie, Alan R., A. Patrick Gunning, Peter J. Wilde, and Victor J. Morris. "Orogenic Displacement of Protein from the Oil/Water Interface." Langmuir 16, no. 5 (March 2000): 2242–47. http://dx.doi.org/10.1021/la990711e.
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Xu, Guang-li, Guo-zhong Zhang, Gang Liu, Amos Ullmann, and Neima Brauner. "Trapped water displacement from low sections of oil pipelines." International Journal of Multiphase Flow 37, no. 1 (January 2011): 1–11. http://dx.doi.org/10.1016/j.ijmultiphaseflow.2010.09.003.
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Zhou, Dengen, and Erling H. Stenby. "Displacement of trapped oil from water-wet reservoir rock." Transport in Porous Media 11, no. 1 (April 1993): 1–16. http://dx.doi.org/10.1007/bf00614631.
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Sun, M., K. Mogensen, M. Bennetzen, and A. Firoozabadi. "Demulsifier in Injected Water for Improved Recovery of Crudes That Form Water/Oil Emulsions." SPE Reservoir Evaluation & Engineering 19, no. 04 (April 27, 2016): 664–72. http://dx.doi.org/10.2118/180914-pa.
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Summary Waterflooding for oil displacement becomes a challenge when water-in-oil (W/O) emulsion forms upon contact of injected water with oil in the porous media. We have recently reported very-high pressure drops and high pressure fluctuations for a number of crudes in waterflooding. In this work, we address the challenge by adding a small amount of a demulsifier in the injected water. The stability of W/O emulsion is affected by many factors, including oil chemistry, brine chemistry, and temperature. We find that the W/O emulsion formation may correlate closely to the low total acid number (TAN). In this work, we report the effectiveness of a demulsifier in significant reduction of pressure drop and elimination of pressure-drop fluctuations. The demulsifier can be dispersed in brine or water, and can be carried by injection fluid as an additive for improved oil recovery. Both micromodel observations and coreflooding results show that W/O-emulsion formation is avoided when 100 ppm demulsifier is injected in the carrier brine. Results also show that there is an increase in oil recovery.
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Yang, Liu, Jun Yang, Jian Gao, and Xuhui Zhang. "The Characteristics of Oil Occurrence and Long-Distance Transportation due to Injected Fluid in Tight Oil Reservoirs." Advances in Polymer Technology 2019 (December 1, 2019): 1–14. http://dx.doi.org/10.1155/2019/2707616.
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In tight oil reservoirs, the injected fluid needs to travel a long distance to expel oil from the micro/nano-size pores to natural fractures or man-made fractures. The flow characteristics of injected fluid are not known well due to the long distance displacement and complex pore structure. In this study, the tight reservoir samples are from typical tight oilfield of China and the oil distribution characteristics are studied based on mineral composition, physical properties and pore size distribution. The long core displacement experiment is conducted based on injection of water, N2, and CO2, which aims to study the individual flooding feasibility. The results show that the oil mainly distributes in the form of spots and accumulates in the micro/nano-pores. Both oil spots and clay minerals have associated characteristics. The microfractures are not the storage space for oil spots, but can connect the oil spots to improve the mobility of the crude oil. In addition, the oil can achieve long distance migration under the injection of water, N2, and CO2, which presents different pressure distribution characteristics. The reservoir pressure of water flooding decreases first and increases later with displacement time. The reservoir pressure of N2 flooding rises gradually over displacement time. The reservoir pressure of CO2 flooding increases first and decreases over displacement time. In contrast to water flooding, N2, and CO2 can increase the reservoir energy, which contributes to tight oil production. In comparison, CO2 has better performances than N2 in terms of oil displacement efficiency. The study contributes to understanding the oil distribution characteristics and provides the guidance for field trials using different flooding techniques.
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Angang, Zhang, Fan Zifei, Zhao Lun, Wang Jincai, Zhang Xiangzhong, Song Heng, and Hou Qingying. "Technique policy for concurrent development of natural and artificial water flooding of strong edge water reservoir: A case study of central layer Yu-III of Akshabulak oilfield." E3S Web of Conferences 38 (2018): 01042. http://dx.doi.org/10.1051/e3sconf/20183801042.
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The central layer Yu-III in Akshabulak oilfield is a sandstone reservoir with strong edge water, whose major development characteristics are high oil recovery rate and heterogeneous water invasion. Aiming at this problem, the development policy chart of concurrent displacement of natural water and injected water is established on the basis of material balance principle. Injection-production ratio and oil recovery rate are the main controlling factors for the concurrent displacement of natural water and injected water. Each injection-production ratio corresponds with only one rational oil recovery rate, and the rational oil recovery rate increases with the injection-production ratio. When the actual injection-production ratio of the central Yu-III reservoir is 0.9, the rational oil recovery rate should be 4%.
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Jia, Jiangfen, Zhengdong Xu, Bin Zhang, Peng Wang, Weizhong Kong, Zhiyuan Xu, Wei Xiong, Yuanzhao Jia, and Jiefeng Cao. "Microemulsion Oil Displacement Effect of Fracture Reservoirs." E3S Web of Conferences 145 (2020): 02059. http://dx.doi.org/10.1051/e3sconf/202014502059.
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In order to compare the oil repellent effect of microemulsion drive and water drive, the remarkable effect of improving recovery rate of microemulsion drive is proved from the microemulsion aspect by analyzing the crack core oil drive experiment and the distribution law of the residual oil in the pore. The experimental results show that the yield rate of microemulsion drive can increase by 10.8% compared with the water drive, and the final recovery rate is as high as 49.7%, which shows that the recovery rate of microemulsion drive system has a significant effect. The proportion of residual oil with pore decreased with the decrease of pore radius, which shows that the pore radius has a significant effect on the distribution of residual oil. And compared with the matrix core, the proportion of residual oil pore in the fissure core is larger and the oil removal efficiency is relatively low.
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Buchgraber, M., T. Clemens, L. M. Castanier, and A. R. Kovscek. "A Microvisual Study of the Displacement of Viscous Oil by Polymer Solutions." SPE Reservoir Evaluation & Engineering 14, no. 03 (May 16, 2011): 269–80. http://dx.doi.org/10.2118/122400-pa.
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Summary Of the various enhanced-oil-recovery (EOR) polymer formulations, newly developed associative polymers show special promise. We investigate pore and pore-network scales because polymer solutions ultimately flow through the pore space of rock to displace oil. We conduct and monitor optically water/oil and polymer-solution/oil displacements in a 2D etched-silicon micromodel. The micromodel has the geometrical and topological characteristics of sandstone. Conventional hydrolyzed-polyacrylamide solutions and newly developed associative-polymer solutions with concentrations ranging from 500 to 2,500 ppm were tested. The crude oil had a viscosity of 450 cp at test conditions. Our results provide new insight regarding the ability of polymer to stabilize multiphase flow. At zero and low polymer concentrations, relatively long and wide fingers of injectant developed, leading to early water break-through and low recoveries. At increased polymer concentration, a much greater number of relatively fine fingers formed. The width-to-length ratio of these fingers was quite small, and the absolute length of fingers decreased. At a larger scale of observation, the displacement front appears to be stabilized; hence, recovery efficiency improved remarkably. Above a concentration of 1,500 ppm, plugging of the micromodel by polymer and lower oil recovery was observed for both polymer types. For tertiary polymer injection that begins at breakthrough of water, the severe fingers resulting from water injection are modified significantly. Fingers become wider and grow in the direction normal to flow as polymer solution replaces water. Apparently, improved sweep efficiency of viscous oils is possible (at this scale of investigation) even after waterflooding. The associative- and conventional-polymer solutions improved oil recovery by approximately the same amount. The associative polymers, however, showed more-stable displacement fronts in comparison to conventional-polymer solutions.
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Avendaño, Jorge, Nicolle Lima, Antonio Quevedo, and Marcio Carvalho. "Effect of Surface Wettability on Immiscible Displacement in a Microfluidic Porous Media." Energies 12, no. 4 (February 19, 2019): 664. http://dx.doi.org/10.3390/en12040664.
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Wettability has a dramatic impact on fluid displacement in porous media. The pore level physics of one liquid being displaced by another is a strong function of the wetting characteristics of the channel walls. However, the quantification of the effect is still not clear. Conflicting data have shown that in some oil displacement experiments in rocks, the volume of trapped oil falls as the porous media becomes less water-wet, while in some microfluidic experiments the volume of residual oil is higher in oil-wet media. The reasons for this discrepancy are not fully understood. In this study, we analyzed oil displacement by water injection in two microfluidic porous media with different wettability characteristics that had capillaries with constrictions. The resulting oil ganglia size distribution at the end of water injection was quantified by image processing. The results show that in the oil-wet porous media, the displacement front was more uniform and the final volume of remaining oil was smaller, with a much smaller number of large oil ganglia and a larger number of small oil ganglia, when compared to the water-wet media.