Browsing by Subject "Microemulsion"

Now showing 1 - 14 of 14

A study of transport of micellar fluids in porous media
(1986) Delshad, Mojdeh; Pope, G. A.; Lake, Larry W.
Two- and three-phase relative permeabilities have been measured for a low interfacial tension brine-oil-surfactant-alcohol mixture in a Berea sandstone core. The measurements were done at steady-state with a constant nominal capillary number of 10⁻². Residual phase saturation (capillary desaturation curve) and endpoint relative permeability have also been measured for three-phase micellar fluids as a function of capillary number in a Berea core. Continuous and slug displacements of both partitioning and non-partitioning radioactive tracers were run for each steady-state experiment. The experimental effluent tracer data from these experiments were analyzed by a capacitance model. The phase dispersivities and dispersion coefficients estimated from the capacitance analysis as a function of phase saturation and velocity are illustrated. Both excess phases (oil and brine) flowing with the microemulsion showed significant capacitance effects, but the microemulsion did not. The absence of capacitance and higher residual saturation than those of excess phases at the same capillary number indicate that the microemulsion was probably the wetting phase in these low interfacial tension flows, even more wetting than the excess brine phase. The relative permeability of each phase is a function only of its own saturation during three-phase flow. Based on this observation and the trend of experimental data, an exponential function is recommended to model three-phase relative permeability at high capillary number
Enhanced oil recovery of heavy oils by non-thermal chemical methods
(2013-05) Kumar, Rahul, active 2013; Mohanty, Kishore Kumar
It 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.
Enhanced oil recovery using low tension gas flooding in high salinity, low permeability carbonate reservoirs
(2018-12) Das, Alolika; Nguyen, Quoc P.; Mohanty, Kishore; Bonnecaze, Roger; DiCarlo, David; Prodanovic, Masa
Chemical enhanced oil recovery (EOR) in carbonate reservoirs is a technically and economically challenging process. Low-Tension Gas flooding is developed as an attractive alternative to conventional EOR methods for application in low permeability and high salinity formations, especially in the presence of divalent cations. The process of Low-Tension Gas (LTG) flooding has been investigated on the laboratory scale as a tertiary and secondary recovery process for a low permeability (<10 mD) Middle Eastern carbonate reservoir with high formation salinity (~200,000 ppm TDS; 19,000 ppm of Ca ²⁺ and Mg ²⁺). LTG flooding design is based on two main mechanisms: mobilizing residual oil by generating ultra-low interfacial tension (IFT) conditions in the reservoir between oil and water, and efficient displacement of the mobilized oil by using foam as a mobility control agent. A novel surfactant formulation using non-ionic alkyl-polyglucoside (APG), anionic ethoxylated propoxylated carboxylate and internal olefin sulfonate (IOS) was developed which could generate ultra-low IFT, show good aqueous stability, fast equilibration, low microemulsion viscosity and support foam stability in presence of the high salinity formation brine. Microemulsion properties were studied to understand the interaction between microemulsion and foam stability at a microscopic scale. Measured oil-water IFT values for Type I microemulsion were as low as 10 ⁻³ dyne/cm, indicating an efficient formulation for oil mobilization. In the Type I microemulsion range, increase in salinity was observed to comparatively lower the foam stability. Measurement of micelle diameter and concentration showed that increase in salinity led to increase in volume of solubilized oil and increased size of oil-swollen micelles. The reduced inter-micellar repulsion because of larger, disperse oil-swollen micelles decreased the ordered structuring of micelles necessary for the stepwise thinning of film lamellae, which reduced the foam stability. LTG flooding strategy for tertiary oil recovery (post waterflood) was then investigated in coreflood experiments through co-injection of surfactant solution and gas (N2). The effect of injection parameters such as surfactant concentration, injected gas fraction (foam quality), drive composition and injected slug salinity on oil recovery and foam stability and hence mobility control (between displacing phase and oil) was examined. Results indicate oil recovery of over 80% ROIP (residual oil in place after waterflood) and 50% OOIP (original oil in place) with residual oil after LTG flooding (SorLTG) around 6%. This proves that the LTG flooding process exhibits favorable mobilization and displacement of residual oil. Qualitative assessment of the results was performed by studying oil recovery, oil fractional flow, oil bank breakthrough, effluent salinity and pressure drop characteristics. The high cost of chemicals and/or the limited supply of gas can make this process economically challenging. Injection strategy for tertiary oil recovery was optimized such that the oil recovery can be maximized using a minimum amount of the injected gas and the surfactant, thereby ensuring a more economically-viable recovery process. Surfactant injection strategy was optimized by varying the concentration and pore volumes of the surfactant slug injected. Nitrogen gas was co-injected during select time periods throughout the entire chemical injection in order to identify the significance of mobility control during the crucial phases of the LTG flooding. The coreflood results emphasized the significance of the injection of gas, even at lower foam quality, for the maintenance of mobility control. Ultimate oil recovery of over 60% (residual oil post waterflood) was achieved, even after reducing the surfactant concentration by 75% by inducing a different in-situ salinity profile as compared to earlier studies. An innovative method for measuring surfactant adsorption using Liquid Chromatography and Mass Spectrometry (LC-MS) was developed, which could provide individual dynamic adsorption data for each of the three classes of surfactants used. Finally, the inter-relation between injected foam quality, in-situ gas saturation, pressure gradient and oil recovery were examined using Computed-Tomography (CT) scans during coreflooding experiments. The scope of applicability of LTG flooding was then extended to secondary oil recovery under the same reservoir conditions. Secondary recovery using LTG flooding was compared to conventional secondary recovery methods such as waterflooding. Oil recovery was observed to increase by 16% OOIP (Original Oil in Place) as compared to waterflooding, even in case of micellar flooding without gas. On introducing mobility control during LTG flooding in the form of injected gas, the secondary oil recovery was observed to increase steadily up to 81% OOIP. Co-injecting gas and surfactant also exhibited lower pressure drop than waterflood, thus underlining the importance and efficiency of mobility control using foam in secondary recovery. Gas injection strategy was optimized in terms of injected foam quality and onset of gas injection. Chemical injection strategy was also modified to test the impact of different in-situ salinity profiles on oil recovery
Experimental investigation of the effect of increasing the temperature on ASP flooding
(2011-12) Walker, Dustin Luke; Pope, Gary A.; Weerasooriya, Upali
Chemical EOR processes such as polymer flooding and surfactant polymer flooding must be designed and implemented in an economically attractive manner to be perceived as viable oil recovery options. The primary expenses associated with these processes are chemical costs which are predominantly controlled by the crude oil properties of a reservoir. Crude oil viscosity dictates polymer concentration requirements for mobility control and can also negatively affect the rheological properties of a microemulsion when surfactant polymer flooding. High microemulsion viscosity can be reduced with the introduction of an alcohol co-solvent into the surfactant formulation, but this increases the cost of the formulation. Experimental research done as part of this study combined the process of hot water injection with ASP flooding as a solution to reduce both crude oil viscosity and microemulsion viscosity. The results of this investigation revealed that when action was taken to reduce microemulsion viscosity, residual oil recoveries were greater than 90%. Hot water flooding lowered required polymer concentrations by reducing oil viscosity and lowered microemulsion viscosity without co-solvent. Laboratory testing of viscous microemulsions in core floods proved to compromise surfactant performance and oil recovery by causing high surfactant retention, high pressure gradients that would be unsustainable in the field, high required polymer concentrations to maintain favorable mobility during chemical flooding, reduced sweep efficiency and stagnation of microemulsions due to high viscosity from flowing at low shear rates. Rough scale-up chemical cost estimations were performed using core flood performance data. Without reducing microemulsion viscosity, field chemical costs were as high as 26.15 dollars per incremental barrel of oil. The introduction of co-solvent reduced chemical costs to as low as 22.01 dollars per incremental barrel of oil. This reduction in cost is the combined result of increasing residual oil recovery and the added cost of an alcohol co-solvent. Heating the reservoir by hot water flooding resulted in combined chemical and heating costs of 13.94 dollars per incremental barrel of oil. The significant drop in cost when using hot water is due to increased residual oil recovery, reduction in polymer concentrations from reduced oil viscosity and reduction of microemulsion viscosity at a fraction of the cost of co-solvent.
Experimental investigation of viscous forces during surfactant flooding of fractured carbonate cores
(2016-08) Parra Perez, Jose Ernesto; Pope, G. A.; Balhoff, Matthew T.
The objective of this research was to investigate the effects of viscous forces on the oil recovery during surfactant flooding of fractured carbonate cores, specifically, to test the effects of using surfactants that form viscous microemulsions in-situ. The hypothesis was that a viscous microemulsion flowing inside a fracture can induce transverse pressure gradients that increase fluid crossflow between the fracture and the matrix, thus, enhancing the rate of surfactant imbibition and thereby the oil recovery. Previous experimentalists assumed the small viscous forces were not important for oil recovery from naturally fractured reservoirs (NFRs) since the pressure gradients that can be established are very modest due to the presence of the highly conductive fractures. Hence, the most common approach for studying surfactants for oil recovery from NFRs is to perform static imbibition experiments that do not provide data on the very important viscous and pressure forces. This is the first experimental study of the effect of viscous forces on the performance of surfactant floods of fractured carbonate cores under dynamic conditions. The effects of viscous forces on the oil recovery during surfactant flooding of fractured carbonate cores were tested by conducting a series of ultralow interfacial tension (IFT) surfactant floods using fractured Silurian Dolomite and Texas Cream Limestone cores. The viscosity of the surfactant solution was increased by adding polymer to the surfactant solution or by changing the salinity of the aqueous surfactant solution, which affects the in-situ microemulsion viscosity. The fractured cores had an extreme permeability contrast between the fracture and the matrix (ranging from 2500 to 90,000) so as to represent typical conditions encountered in most naturally fractured reservoirs. Also, non-fractured corefloods were performed in cores of each rock type for comparison with the results from the fractured corefloods. In all the experiments, the more viscous surfactants solutions achieved the greater oil recovery from the fractured carbonate cores which contradicts conventional wisdom. A new approach for surfactant flooding of naturally fractured reservoirs is presented. The new approach consists of using a surfactant solution that achieves ultralow IFT and that forms a viscous microemulsion. A viscous microemulsion can serve as a mobility control agent analogous to mobility control with foams or polymer but with far less complexity and cost. The oil recovery from the fractured carbonate cores was greater for the surfactant floods with the higher microemulsions, thus, it is expected that using viscous microemulsion can enhance the oil recovery from naturally fractured reservoirs.
Foam assisted low interfacial tension enhanced oil recovery
(2010-05) Srivastava, Mayank; Nguyen, Quoc P.; Pope, Gary A.; Johns, Russel T.; Srinivasan, Sanjay; Bonnecaze, Roger T.
Alkali-Surfactant-Polymer (ASP) or Surfactant-Polymer (SP) flooding are attractive chemical enhanced oil recovery (EOR) methods. However, some reservoir conditions are not favorable for the use of polymers or their use would not be economically attractive due to low permeability, high salinity, or some other unfavorable factors. In such conditions, gas can be an alternative to polymer for improving displacement efficiency in chemical-EOR processes. The co-injection or alternate injection of gas and chemical slug results in the formation of foam. Foam reduces the relative permeability of injected chemical solutions that form microemulsion at ultra-low interfacial tension (IFT) conditions and generates sufficient viscous pressure gradient to drive the foamed chemical slug. We have named this technique of foam assisted enhanced oil recovery as Alkali/Surfactant/Gas (ASG) process. The concept of ASG flooding as an enhanced oil recovery technique is relatively new, with very little experimental and theoretical work available on the subject. This dissertation presents a systematic study of ASG process and its potential as an EOR method. We performed a series of high performance surfactant-gas tertiary recovery corefloods on different core samples, under different rock, fluid, and process conditions. In each coreflood, foamed chemical slug was chased by foamed chemical drive. The level of mobility control in corefloods was evaluated on the basis of pressure, oil recovery, and effluent data. Several promising surfactants, with dual properties of foaming and emulsification, were identified and used in the coreflood experiments. We observed a strong synergic effect of foam and ultra-low IFT conditions on oil recovery in ASG corefloods. Oil recoveries in ASG corefloods compared reasonably well with oil recoveries in ASP corefloods, when both were conducted under similar conditions. We found that the negative salinity gradient concept, generally applied to chemical floods, compliments ASG process by increasing foam strength in displacing fluids (slug and drive). A characteristic increase in foam strength was observed, in nearly all ASG corefloods conducted in this study, as the salinity first changed from Type II(+) to Type III environment and then from Type III to Type II(-) environment. We performed foaming and gas-microemulsion flow experiments to study foam stability in different microemulsion environments encountered in chemical flooding. Results showed that foam in oil/water microemulsion (Type II(-)) is the most stable, followed by foam in Type III microemulsion. Foam stability is extremely poor (or non-existent) in water/oil microemulsion (Type II (+)). We investigated the effects of permeability, gas and liquid injection rates (injection foam quality), chemical slug size, and surfactant type on ASG process. The level of mobility control in ASG process increased with the increase in permeability; high permeability ASG corefloods resulting in higher oil recovery due to stronger foam propagation than low permeability corefloods. The displacement efficiency was found to decrease with the increase in injection foam quality. We studied the effect of pressure on ASG process by conducting corefloods at an elevated pressure of 400 psi. Pressure affects ASG process by influencing factors that control foam stability, surfactant phase behavior, and rock-fluid interactions. High solubility of carbon dioxide (CO₂) in the aqueous phase and accompanying alkali consumption by carbonic acid, which is formed when dissolved CO₂ reacts with water, reduces the displacement efficiency of the process. Due to their low solubility and less reactivity in aqueous phase, Nitrogen (N₂) forms stronger foam than CO₂. Finally, we implemented a simple model for foam flow in low-IFT microemulsion environment. The model takes into account the effect of solubilized oil on gas mobility in the presence of foam in low-IFT microemulsion environment.
Investigation of surfactant-polymer flooding simulation using two-phase and three-phase microemulsion phase behavior models
(2021-08-16) Alhotan, Muhammad Mansour; Sepehrnoori, Kamy, 1951-; Delshad, Mojdeh
The vast global demand for energy coupled with the decreasing oil production capabilities of maturing fields raises the need for Enhanced Oil Recovery (EOR) technologies. Much of the oil in these maturing fields are yet to be extracted and remains in the reservoir as residual oil. Chemical EOR (CEOR) is a widely known and effective method in extracting the remaining oil in the reservoir post-secondary flooding. Surfactant-polymer flooding is a type of CEOR that enhances oil recovery by applying mobility control, forming micelles, and reducing interfacial tension. Simulation of CEOR floods before field application is essential to avoid deployment obstacles and to ensure the good design of the chemical formulations. In this thesis, reservoir simulators that utilize two-phase microemulsion model (CMG-STARS) and three-phase microemulsion model (UTCHEMRS & INTERSECT) are used to simulate surfactant-polymer flooding to determine and compare their results. Different models are used in the simulators to describe the physical behavior of injected chemicals inside the reservoir. Therefore, these models were examined and matched when possible. An extensive study was performed on the relative permeability models of INTERSECT and UTCHEMRS. For simulations, the physical behavior models of polymer and surfactant were constructed and validated on a 1D scale reservoir model. Then, the reservoir model was extended to a 3D model, where the physical models and results were further validated. Finally, simulations were conducted in a field-scale reservoir containing 680,400 grids, where results were compared and analyzed. The results for the relative permeability study demonstrated that the INTERSECT relative permeability model is complex, and more information is required to follow the sequence of equations and their dependencies. For the simulation, the 1D and 3D model results suggest an excellent match between the different simulators in modeling surfactant-polymer floods. In the case of the field-scale model, the simulators matched in terms of oil recovery and produced and injected total fluids while having similar average reservoir pressures.
Measurement of relative permeability and dispersion for micellar fluids in Berea rock
(1981) Delshad, Mojdeh; Pope, G. A.
Two phase steady state relative permeability and dispersion experiments have been conducted in Berea sandstone rock. Experiments have been performed on both high-tension brine-oil and a low tension three phase micellar mixture. The micellar solution contained petroleum solfonate (Witco TRS10-410), isobutyl alcohol, sodium chloride, and n-decane. The static physical property experiments on the micellar solution consisted of phase behavior, viscosity, and interfacial tension measurements. The relative permeabilities and dispersion were measured for both the oil-microemulsion and brine-microemulsion phase pairs at the rate of 6 ft/day. An interesting aspect of these experiments is the amount (≈30 percent) of microemulsion phase trapping even at 10⁻³ dyne/cm interfacial tension. The dispersion was measured for each phase using radioactive tracers (Carbon-14 and Tritium) and a chemical tracer (n-nonane). The dispersivity was found to be a function of phase saturation, porous medium, and interfacial tension at a given velocity in two phase flow. The brine dispersivities increased as the water saturation decreased, but the microemulsion dispersivities stayed almost constant as saturation varied. The classical solution to the convection-diffusion eqution for single phase flow has been generalized to multiphase flow and was used to aid in interpreting the data
Observations of displacement processes of residual oil by aqueous surfactant solutions in extended visual flow cells
(1985) Chamblee, Christopher Jon; Caudle, Ben H. (Ben Hall), 1923-
The displacement of residual heptane by solutions of aqueous surfactant exhibiting lower, middle and upper microemulsion phase behavior were recorded on videotape. The solutions consisted of Witco TRS 10-80 and secondary butyl alcohol mixed with brines of different salinities to control and adjust phase behavior. The displacement was observed using thin section glass flow cells up to 2 feet in length filled with a consolidated cryolite grain matrix in conjunction with a color video camera and monitor. The systems were designed to address the maintenance of the structural integrity of tertiary oil banks in long visual porous models. The initial development of the oil bank varied with phase behavior. As expected, the surfactants exhibiting middle and upper phase microemulsion resulted in very efficient displacement of the residual oil. The existence of a water bank trailing the oil bank was observed in many of the displacements. The formation of the water bank is due in part, if not entirely, to resident brine which is bypassed at the oil bank's leading edge and which remains stationary until water bank encroachment. Some two phase flow in the oil bank was also observed. The sharp leading edge of the oil bank degenerated in every case, indicating an interfacial tension gradient in the bank. Evidence of slug flow is presented along with some proposed explanations for the phenomena
Prediction of microemulsion phase behavior from surfactant and co-solvent structures
(2018-12-07) Chang, Leonard Yujya; Pope, G. A.; Weerasooriya, Upali P; Mohanty, Kishore K; DiCarlo, David D; Johnston, Keith P
Structure-property models were developed to predict the optimum salinity, optimum solubilization ratio, and the aqueous stability limit from the molecular structures of surfactants and co-solvents used for enhanced oil recovery. The models are sufficiently accurate to provide a useful guide to experimental testing programs for the development of chemical formulations for enhanced oil recovery and other similar applications requiring low interfacial tension. This is the first time a structure-property model has been developed to predict the optimum solubilization ratio. The solubilization ratio can be used in the Huh equation to predict the interfacial tension, which is the most important property in enhanced oil recovery applications. The UTCEOR Database was constructed and used to develop the models. The database is a collection of highest-quality experimental chemical EOR data conducted at The University of Texas at Austin from 2005 to 2018. It contains several thousand phase behavior experiments using 34 unique crude oils, 294 unique surfactants, and 70 unique co-solvents. The structures of the surfactants and co-solvents were characterized and include variations in the type of hydrophobe (carbon number, degree of branching, polydispersity, and aromaticity), number of alkoxylate groups (propylene oxide and ethylene oxide), and the type of head group. The model focuses on blends of anionic surfactants and nonionic co-solvents. Both the optimum salinity and the optimum solubilization ratio were modeled as a function of monovalent and divalent cations in the brines. The oils were characterized using their equivalent alkane carbon number. The models include the effect of soaps generated from the neutralization of acidic crude oils. Previous models for optimum salinity have not included the effects of divalent cations, soap, and co-solvents among other limitations. Most importantly, the new model can be used to predict interfacial tension as well as optimum salinity whereas previous models were used to predict only optimum salinity. In this research, the structure-concentration and structure-property effect of co-solvents were modeled separately, whereas previous models convoluted both effects and were not predictive. New measurements were made and combined with literature data to develop improved correlations for the oil-water partition coefficient and the interface-water partition coefficient of co-solvents. These correlations were used with pseudophase theory to more accurately model the structure-concentration effect. A structure-property model was developed for the aqueous stability that predicts the coacervation of chemical formulations. The interactions between surfactant hydrophobes and the PO groups were modeled because they influence the stability of micelles. The effects of co-solvent, polymer, and divalent cations were included for the first time. The structure-property models can be used to predict formulations for a given oil, brine and temperature that are likely to achieve ultra-low IFT with aqueous stability at optimum salinity and thus greatly accelerate the process of finding the best formulations to test for chemical EOR.
A Rheological Study of Polymer and Microemulsion in Porous Media
(1981-05) Yuan, Mei-Kou; Pope, Gary A.
The rheological properties of polymer used in mobility control and the micellar solutions used in chemical flooding have been studied under both static and dynamic flow conditions. The polymer solutions under investigation include Xanflood (a xanthan gum polysaccharide sold by Kelco) and Pusher 700( a hydrolyzed polyacrylamide sold by Dow) polymer solutions with different polymer concentrations and salinities. The micellar solutions studied consist of TRS 10-80 (a petroleum sulfonate sold by Witco), isobutanol, isooctane and sodium chloride. The effects of inertia, shear thinning viscosity and viscoelasticity are demonstrated. An effort was made fo correlate the apparent viscosity of the polymer and micellar solutions while flowing in a porous medium. Similar studies were also extended to Water Cut 110 and Water. Cut 160 polymers (a hydrolyzed polyacrylamide sold by Tiorco Inc.), with special attention to the studies of shear degradation. Packed beds with spherical, uniform glass beads of different sizes were used and packed in either glass or stainless steel columns. In order to eliminate entrance and exit end effects, one of the stain-less steel columns was especially designed at the inlet and outlet ends, and three pressure taps were drilled on the packed section to allow accurate measurements of the fully developed, steady state pressure gradient. A Newtonian fluid, water, was used to study the effect of inertia. The Ergun equation was used to correlate these results. The correlation was excellent. Inertia contributes 1% to the pressure drop at a Reynolds number of 1.0, and increases to 12% at NRe = 10. For polymer solution, three types of rheological measure-ments were conducted. An ultra-sensitive couette viscometer which can be used under exceptional low shear stress conditions was employed to measure the steady state viscosity as a function of shear rate. The second type of measurement is pressure drop-flow rate data on the same fluids. The third, which was done by Professor Thurston, involves an unsteady-state complex viscosity measurement as a function of shear rate and frequency. For micellar solution, only the first and second type of measurements were conducted. The viscosities of Xanflood polymer solutions, which are relatively insensitive to the effects of salt concentration, show flow resistance in porous media that can be correlated with their shear-thinning bulk viscosities. The apparent viscosities agree with those measured with the viscometer up to the highest shear rate -1 measured by both techniques (1000 sec ). The dynamic measurement in the beadpacks extended up to 63,009 sec-l No shear degradation has been observed. A second Newtonian region was approached at the highest shear rates for all Xanflood polymer solutions. Pusher 700 polymer solutions are much more sensitive to the effects of salt concentration. The higher the salt concentration, the lower the viscosity. Addition of salt shields the repulsive forces among the negatively charged functional groups in the polymer chain and therefore decreases the viscosity. The apparent viscosity of Pusher 700 polymer solution in the beadpacks was the same as that measured with the viscometer before the onset of the elastic response. As observed by others4-7,lZ-lS, the latter becomes significant at high shear rate and increases the flow resistance. Pack permeability, polymer concentration, and salt concentration all affect the visco-elastic response of the polymer solution. Under the conditions studied, this polymer shear degraded at flowing shear rates above 0 -1 1 ,000 sec , and lost about 5% of its original viscosity at 20,000 -1 sec v The Water Cut 110 polymer and Water Cut 160 polymer, with both viscous and elastic characteristics, showed a similar behavior to those of Pusher 700 polymer under dynamic flow conditions. Efforts have been made to study the thermal and shear stabilities of these polymers. Results indicate that Water Cut 110 polymer, after heating in oven at 80°c for 24 hours, lost about 50% of its viscosity, and the resulting solution showed a smalled viscoelastic response. Both Water 110 and Water Cut 160 showed a 4% viscosity loss due to shear degradation at flowing shear rates up to 30,000 sec-l A single experiment was done using a microemulsion. This microemulsion consists of Witco TRS 10-80, iso-octane, isobutanol and salt. The steady and apparent viscosities showed excellent agreement up~to the maximum shear rate reached. No viscoelastic response was evident for this microemulsion. Further study on the behavior of microemulsion in porous medium is currently being conducted. Permeability reduction was also observed. It was smaller for the more permeable packs. The polymer solutions flowed through packs already flushed with polymer solution experienced a further reduction in permeability, even though the previous polymer solution had been flushed out extensively with brine. The brine permeability following each polymer solution ( or microemulsion ) was used to correlate the apparent viscosity of the same polymer solution (or microemulsion ). This worked very well for all the solutions. The method and all the results are discussed later.
Simulation study of surfactant transport mechanisms in naturally fractured reservoirs
(2010-08) Abbasi Asl, Yousef; Pope, Gary A.; Mohanty, Kishore K.
Surfactants both change the wettability and lower the interfacial tension by various degrees depending on the type of surfactant and how it interacts with the specific oil. Ultra low IFT means almost zero capillary pressure, which in turn indicates little oil should be produced from capillary imbibition when the surfactant reduces the IFT in naturally fractured oil reservoirs that are mixed-wet or oil-wet. What is the transport mechanism for the surfactant to get far into the matrix and how does it scale? Molecular diffusion and capillary pressure are much too slow to explain the experimental data. Recent dynamic laboratory data suggest that the process is faster when a pressure gradient is applied compared to static tests. A mechanistic chemical compositional simulator was used to study the effect of pressure gradient on chemical oil recovery from naturally fractured oil reservoirs for several different chemical processes (polymer, surfactant, surfactant-polymer, alkali-surfactant-polymer flooding). The fractures were simulated explicitly by using small gridblocks with fracture properties. Both homogeneous and heterogeneous matrix blocks were simulated. Microemulsion phase behavior and related chemistry and physics were modeled in a manner similar to single porosity reservoirs. The simulations indicate that even very small pressure gradients (transverse to the flow in the fractures) are highly significant in terms of the chemical transport into the matrix and that increasing the injected fluid viscosity greatly improves the oil recovery. Field scale simulations show that the transverse pressure gradients promote transport of the surfactant into the matrix at a feasible rate even when there is a high contrast between the permeability of the fractures and the matrix. These simulations indicate that injecting a chemical solution that is viscous (because of polymer or foam or microemulsion) and lowers the IFT as well as alters the wettability from mixed-wet to water-wet, produces more oil and produces it faster than static chemical processes. These findings have significant implications for enhanced oil recovery from naturally fractured oil reservoirs and how these processes should be optimized and scaled up from the laboratory to the field.
A study of microemulsion viscosity with consideration of polymer and co-solvent additives
(2014-05) Dashti, Ghazal; Delshad, Mojdeh
With the dramatic increase in the worldwide demand for the crude oil and with the fact that the oil and gas resources are depleting, the enhanced oil recovery process plays an important role to increase the production from the existing hydrocarbon reservoirs. Chemical enhanced oil recovery is one of the most important techniques to unlock significant amount of trapped oil from oil reservoirs. Surface agent materials (Surfactants) are used to lower the interfacial tension (IFT) between water and oil phases to ultralow values and mobilize the trapped oil. When surfactant, water, and oil are mixed together they form a thermodynamically stable phase called microemulsion which can be characterized by ultralow interfacial tension and the ability to solubilize both aqueous and oil compounds. Another characteristic of microemulsion solution is its viscosity which plays an important role in the creation and movement of the oil bank. The microemulsion micro-structure is complex and its viscosity is difficult to predict. Various viscosity models and correlations are presented in the literature to describe microemulsion viscosity behavior, but they fail to represent the rheological behavior of many microemulsion mixtures. Most of these models are valid in the lower and higher ranges of solute where one of the domains is discontinuous. The majority of the models fail to calculate the rheology of microemulsion phase in bicontinuous domains. In this work, we present a systematic study of the rheological behavior of microemulsion systems and the effect of additives such as polymer and co-solvent on rheological properties of microemulsions. Several laboratory experiments were conducted to determine the rheological behavior of surfactant solutions. A new empirical model for the viscosity of microemulsion phase as a function of salinity is introduced. The model consists of three different correlations one for each phase type of Windsor phase behaviors. The proposed model is validated using a number of experimental results presented in this document. The proposed viscosity model is implemented in the UTCHEM simulator and the simulator results are compared with the coreflood experiments. Excellent matches were obtained for the pressure. We further improved the proposed viscosity model to incorporate the effect of polymer and co-solvent on the microemulsion viscosity.
Treatment of Phase Behavior and Associated Properties Used in a Micellar-Polymer Flood Simulator
(1984-08) Satoh, Tohru; Pope, Gary A.; Sepehrnoori, Kamy
A microemulsion phase behavior model has been improved from the standpoints of alcohol partitioning and salinity requirement diagrams. A thermodynamic model for the alcohol partitioning has been incorporated into both 1-D and 2-D micellar-polymer simulators to treat up to three amphiphilic species. This model has made it possible to match experimental salinity requirement diagrams in conjunction with a calcium effect by its ion exchange with surfactant. One of the most important design features for micellar-polymer flooding is the salinity gradient. Salinity requirement diagrams aid in this design process. Other factors include surfactant adsorptio~ slug size, cation exchange, clay stability, and polymer effects. Any chromatographic separation of surfactant and cosurfactants as they transport through the reservoir is also important. So a chromatographic study should be useful in selecting surfactants and cosurfactants for optimum behavior. Then out of a very large number of possible chemical mixtures the best behaved could then be selectively studied in cores. Simultaneous solution techniques and a capacitance model have also been implemented in the 1-D simulator.