Browsing by Subject "Viscous fingering"
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Item Alternate-slug fracturing using foam(2016-08) Shrivastava, Kaustubh; Sharma, Mukul M.; Mohanty, Kishore K.The success of a hydraulic fracturing job depends primarily on the proper distribution of proppant inside the fracture. Fracture length and conductivity are the two prime characteristics that determine the productivity of fractured wells (Liu & Sharma, 2005). Slick-water fracturing involves the use of large volumes of water for fracturing shales and mudstones (Palisch, et al., 2010). The low viscosity of water increases the settling velocity of proppant, resulting in an ineffective lateral placement of the proppant. It also affects the vertical coverage of the proppant across the pay zone(s), rendering the fracturing process inefficient (Gadde, et al., 2004). To improve proppant placement, a new technique was proposed by Malhotra et al. (2014), that involves pumping slugs of high viscosity and low viscosity fluids alternately, with most of the proppant being carried by the low viscosity fluid. Alternate injection of high viscosity and low viscosity slugs creates a mobility contrast between the fluids and leads to the formation of viscous fingers. The viscous fingers provide a pathway for proppant transport. The higher velocity of the viscous fingers compared to the injection velocity of the fluid leads to deeper placement of proppant. In addition, viscous sweeps, due to the high viscosity slugs, push any proppant bank formed near the wellbore deeper into the fracture, thus creating longer fractures (Malhotra, et al., 2014). In this study, we conducted an experimental investigation to obtain a fundamental understanding of the viscous fingering phenomena when water and foam are used as the low and high viscosity fluids, over a wide range of viscosity ratios. We have derived a relationship between finger-tip velocity and viscosity ratio of the fluids. This relationship will help in designing Alternate-slug fracturing treatments for the foam-water system.Item Enhanced oil recovery of heavy oils by non-thermal chemical methods(2013-05) Kumar, Rahul, active 2013; Mohanty, Kishore KumarIt is estimated that the shallow reservoirs of Ugnu, West Sak and Shraeder Bluff in the North Slope of Alaska hold about 20 billion barrels of heavy oil. The proximity of these reservoirs to the permafrost makes the application of thermal methods for the oil recovery very unattractive. It is feared that the heat from the thermal methods may melt this permafrost leading to subsidence of the unconsolidated sand (Marques 2009; Peyton 1970; Wilson 1972). Thus it is necessary to consider the development of cheap non-thermal methods for the recovery of these heavy oils. This study investigates non-thermal techniques for the recovery of heavy oils. Chemicals such as alkali, surfactant and polymer are used to demonstrate improved recovery over waterflooding for two oils (A:10,000cp and B:330 cp). Chemical screening studies showed that appropriate concentrations of chemicals, such as alkali and surfactant, could generate emulsions with oil A. At low brine salinity oil-in-water (O/W) emulsions were generated whereas water-in-oil (W/O) emulsions were generated at higher salinities. 1D and 2D sand pack floods conducted with alkali surfactant (AS) at different salinities demonstrated an improvement of oil recovery over waterflooding. Low salinity AS flood generated lower pressure drop, but also resulted in lower oil recovery rates. High salinity AS flood generated higher pressure drop, high viscosity emulsions in the system, but resulted in a greater improvement in oil recovery over waterfloods. Polymers can also be used to improve the sweep efficiency over waterflooding. A 100 cp polymer flood improved the oil recovery over waterflood both in 1D and 2D geometry. In 1D geometry 1PV of polymer injection increased the oil recovery from 30% after waterflood to 50% OOIP. The tertiary polymer injection was found to be equally beneficial as the secondary polymer injection. It was also found that the combined application of AS and polymer did not give any major advantage over polymer flood or AS flood alone. Chemical EOR technique was considered for the 330cp oil B. Chemical screening studies showed that microemulsions could be generated in the system when appropriate concentrations of alkali and surfactant were added. Solubilization ratio measurement indicted that the interfacial tension in the system approached ultra-low values of about 10-3 dynes/cm. The selected alkali surfactant system was tested in a sand pack flood. Additionally a partially hydrolyzed polymer was used to provide mobility control to the process. The tertiary injection of ASP (Alkali-Surfactant-Polymer) was able to improve the oil recovery from 60% OOIP after the waterflood to almost 98% OOIP. A simple mathematical model was built around viscous fingering phenomenon to match the experimental oil recoveries and pressure drops during the waterflood. Pseudo oil and water relative permeabilities were calculated from the model, which were then used directly in a reservoir simulator in place of the intrinsic oil-water relative permeabilities. Good agreement with the experimental values was obtained. For history matching the polymer flood of heavy oil, intrinsic oil-water relative permeabilities were found to be adequate. Laboratory data showed that polymer viscosity is dependent on the polymer concentration and the effective brine salinity. Both these effects were taken into account when simulating the polymer flood or the ASP flood. The filtration theory developed by Soo and Radke (1984) was used to simulate the dilute oil-in-water emulsion flow in the porous media when alkali-surfactant flood of the heavy oil was conducted. The generation of emulsion in the porous media is simulated via a reaction between alkali, surfactant, water and heavy oil. The theory developed by Soo and Radke (1984) states that the flowing emulsified oil droplets clog in pore constrictions and on the pore walls, thereby restricting flow. Once captured, there is a negligible particle re-entrainment. The simulator modeled the capture of the emulsion droplets via chemical reaction. Next, the local water relative permeability was reduced as the trapping of the oil droplets will reduce the mobility of the water phase. This entrapment mechanism is responsible for the increase in the pressure drop and improvement in oil recovery. The model is very sensitive to the reaction rate constants and the oil-water relative permeabilities. ASP process for lower viscosity 330 cp oil was modeled using the UTCHEM multiphase-multicomponent simulator developed at the University of Texas at Austin. The simulator can handle the flow of three liquid phases; oil, water and microemulsion. The generation of microemulsion is modeled by the reaction of the crude oil with the chemical species present in the aqueous phase. The experimental phase behavior of alkali and surfactant with the crude oil was modeled using the phase behavior mixing model of the simulator. Oil and water relative permeabilities were enhanced where microemulsion is generated and interfacial tension gets reduced. Experimental oil recovery and pressure drop data were successfully history matched using UTCHEM simulator.Item Numerical simulation of acid stimulation treatments in carbonate reservoirs(2021-08-13) Dong, Rencheng; Wheeler, Mary F. (Mary Fanett); Mohanty, Kishore K; DiCarlo, David A; Okuno, Ryosuke; Saaf, FredrikMatrix acidizing and acid fracturing are two main types of acid stimulation treatments that are extensively employed by industry in carbonate reservoirs to improve permeability and enhance production. Matrix acidizing involves injecting acid to dissolve minerals in order to create long highly conductive channels (wormholes) whereas acid fracturing is used to etch fracture surfaces and create fracture conductivity. Numerical modeling of acid stimulation treatments couples processes of fluid flow, reactive transport, and rock dissolution, which imposes great computational challenges. The purpose of this dissertation is to develop efficient and accurate numerical models for acidizing process and acid fracturing process respectively. In most of matrix acidizing simulations, acid transport is generally solved by a single-point upwinding (SPU) scheme based on finite volume method. Simulation results of wormhole growth may have large numerical errors due to grid orientation effect of SPU scheme. In this work, we apply adaptive enriched Galerkin (EG) methods for solving coupled flow and reactive transport equations of acidizing model. EG is constructed by enriching the standard continuous Galerkin (CG) finite element method with piecewise constant functions. Since EG is a higher-order method compared with standard finite volume method, EG reduces non-physical numerical errors caused by grid orientation effect. Wormhole growth usually exhibits fingering patterns, which requires very fine mesh to resolve. Instead of global mesh refinement, we apply adaptive mesh refinement technique to dynamically refine the mesh in the vicinity of wormhole interfaces and coarsen the mesh after dissolution fronts pass. The simulation runtime using adaptive mesh is only about 30% of the runtime using globally refined mesh in our numerical examples. The key to success in acid fracturing treatments is to achieve non-uniform acid etching on fracture surfaces. Carbonate reservoir heterogeneity such as heterogeneous mineral distribution can lead to non-uniform acid etching. In addition, the non-uniform acid etching can be enhanced by the viscous fingering mechanism. By injecting a low-viscosity acid into a high-viscosity polymer pad fluid, acid tends to form viscous fingers and etch fracture surfaces non-uniformly. Acid fracturing simulations rarely modeled the effect of acid viscous fingering. In this work, a 3D acid fracturing model is developed to simulate acid etching process with acid viscous fingering. Our acid fracturing model considers fluid flow inside the fracture, acid and polymer transport, and change of fracture geometry due to mineral dissolution. A numerical simulator is developed to solve the acid fracturing model and compute the rough acid fracture geometry induced by non-uniform acid etching. We investigate the effects of viscous fingering, perforation design, and alternating injection of pad and acid fluids on the acid etching process. Our model is capable of simulating growth of acid-etched channels caused by acid viscous fingering. According to our simulation results, properly increasing the number of perforations can restrain the height of acid-etched channels and help sustain acid fracture conductivity under the reservoir closure stress. Compared with single-stage acid injection, multi-stage alternating injection of pad and acid fluids leads to narrower and longer acid-etched channels, which improves the effectiveness of acid fracturing treatments.Item Understanding unstable immiscible displacement in porous media(2015-05) Doorwar, Shashvat; Mohanty, Kishore Kumar; Pope, Gary; DiCarlo, David; Huh, Chun; Weerasooriya, Upali; Hidrovo, CarlosOur global heavy and viscous oil reserves are immense. 70% of our current global oils reserves are viscous or heavy. For an energy secure future, exploitation of heavy oil reserves is necessary to mitigate the impact of steadily declining conventional reserves. Though most viscous and heavy oils are produced by thermal stimulation, several cases do exist where thermal methods are neither technically feasible nor economically profitable. In such cases, non-thermal EOR methods have to be applied. Any displacement process at such high viscosity ratio will be influenced by viscous fingering. Polymers are typically added to the water to stabilize the displacement but for oils above a couple of 100 cp viscosity a stable displacement is not feasible. As unstable displacements are not very well understood, visualization along with experimentation is critical for understanding and modeling the process. In this study, multi-scale experimental strategy was employed; experiments were conducted in cores at lab-scale to generate quantifiable data and were repeated in small micro-fluidic cells for visualization of the mechanism. Polymer flood as an alternative non-thermal process in a structurally complex carbonate formation was tested. In carbonates formations, thermal methods are not preferred as mineral dissolution and precipitation lead to formation damage. Effect of timing of polymer flood was studied in great details. Result from both the micromodels and core-floods indicate that for heavy oils, unlike light oils, timing of polymer injection is not critical and a tertiary polymer flood at the completion of waterflood can also produce significant incremental oil. In some cases, tertiary polymer flood even out-performs a secondary polymer flood. A major problem with modeling and predicting the performance of an unstable flood is largely due to our inability to accurately capture viscous fingering or its effects. Viscous fingering is a complex phenomenon and is dependent on several parameters such as injection rate, viscosity ratios, heterogeneity and dimensions. The micromodels were used to visualize the variation in flow pattern at different viscosity ratio and injection rates while core floods provided essential modeling data. Based on the results two new models were developed: a simplified network model that could accurately predict the viscous fingers for all viscosity ratios and a lumped model that capture the effect of viscous fingers at larger scales through pseudo-relative permeability functions. A dimensionless scaling parameter similar to the instability parameter of Peters and Flock (1981) was also developed that is useful in predicting the recoveries of all unstable displacement at various viscosity ratios, injection rate, permeability and width. The scaling parameter showed excellent fit with experimental data of over 60 experiments.Item Unstable immiscible displacement study in oil-wet rocks(2016-05) Worawutthichanyakul, Thanawut; Mohanty, Kishore Kumar; Delshad, MojdehDisplacement of a viscous fluid by a lower viscosity immiscible fluid (such as waterflood of the viscous oil) in a porous medium is unstable. The displacement front generates viscous fingers which lead to less oil recovery efficiency. Another important problem related to instability in immiscible flow is the lack of reservoir modeling to capture viscous fingerings in simulation grid blocks. Few approaches to represent this phenomenon in reservoir modeling have been proposed previously. A dimensionless scaling group (viscous finger number) has been suggested which have a power-law relationship with the breakthrough recovery and cumulative recovery in unstable core floods. The relative permeability used in large grid-block simulations has been modified to so-call “pseudo-relative permeability” on the basis of the dimensionless group, thus incorporating the effect of fingers in waterflood predictions. However, the previous proposed models were constructed from experiments only in water-wet systems. This research extends the recent viscous fingering models to oil-wet systems. Sandstone cores are treated to alter the wettability to oil-wet. Series of experimental studies are performed in both water-wet and oil-wet cores. Viscosity ratio, velocity and diameter are varied. It is shown that the previously developed viscous finger number works for the new water-wet experiments. However, for oil-wet experiments, the correlating dimensionless number is different. A pseudo-relative permeability model has been developed for oil-wet cores. The core flood experiments have been matched by the new pseudo-relative permeability model. This pseudo-relative permeability model can be used for reservoir simulation of viscous oil waterfloods and polymer floods.