Surfactant-Polymer (SP) and Alkaline-Surfactant-Polymer (ASP) floods are tertiary oil recovery processes that mobilize residual oil to waterflood. These Chemical EOR processes are most valuable when the residual oil saturation of a target reservoir to waterflood is high. The first steps of designing a SP or ASP flood are performed in a laboratory by developing a surfactant formulation and by performing core flood experiments to assess the performance of the flood to recovery residual oil to waterflood. The two criteria for a technically successful laboratory SP or ASP core flood are recovering greater than 90% of residual oil to waterflood leaving behind less than 5% of residual oil and accomplishing this at a field scalable pressure gradient across the porous medium of approximately 1 psi per foot. This thesis documents the laboratory development of SP and ASP core floods for a continental Unites States oil reservoir reported to contain the minerals anhydrite and gypsum. The significance of these minerals is that they provide an infinite acting source of calcium within the reservoir that makes using the traditional alkali sodium carbonate unfeasible using conventional Chemical EOR methods. This is because sodium carbonate will precipitate as calcite in the presence of free calcium ions. Secondly, this thesis investigates two novel alkalis that are compatible with free calcium ions, sodium acetate and tetrasodium EDTA, for their viability for use in ASP floods for reservoirs containing anhydrite or gypsum. / text

Reservoir pressure and solution gas can significantly alter the microemulsion phase behavior and the design of a surfactant-polymer flood. This dissertation shows how to predict changes in microemulsion phase behavior from dead oil at atmospheric pressure to live crude at reservoir pressure. Our method requires obtaining only a few glass pipette measurements of microemulsion phase behavior at atmospheric pressure. The key finding is that at reservoir pressure the optimum solubilization ratio and the logarithm of optimal salinity behave linearly with equivalent alkane carbon number (EACN). These trends are predicted from the experimental data at atmospheric pressure based on density calculations of pure components using the Peng-Robinson equation-of-state (PREOS). We show that predictions of the optimum conditions for live oil are in good agreement with the few experimental measurements that are available in the literature. We also present new measurements at atmospheric pressure to verify the established trends. The experiments show that while pressure induces a phase transition from upper microemulsion (Winsor Type II+) to lower microemulsion (Winsor Type II-), solution gas does the opposite. An increase in pressure decreases the optimum solubilization ratio and shifts the optimum salinity to a larger value. Adding methane to dead oil at constant pressure does the reverse. Thus, these effects are coupled and both must be taken into account. We show using a numerical simulator that these changes in the optimum conditions can impact oil recovery if not accounted for in the SP design. / text

Surfactant-polymer (SP) and alkali-surfactant-polymer (ASP) flooding has gained little traction among different tertiary recovery strategies such as thermal and miscible gas flooding; however, many mature onshore reservoirs could be potential candidates. More than four decades of research has detailed technical challenges and successes through laboratory experimentation, chemical flood simulation, and some pilot projects, which have provided technical screening procedures to efficiently filter unfeasible projects. Therefore, technical understanding seems sufficient to advance projects through early development stages; however, a project value identification and realization process ultimately dictates project implementation in the oil and gas industry, with technical feasibility merely supporting overall valuation and project feasibility. A quick early screening methodology integrating important project valuation criteria can efficiently assess large numbers of projects. The relatively few studies detailing chemical flooding valuation from just an economic standpoint reflects the need for an integrated process-oriented framework for quick early screening valuation of chemical flooding opportunities. This study develops an integrated process-oriented framework for early screening and valuation, with an overall objective to quickly filter unfeasible projects based on valuation criteria, rather than technical feasibility alone. A reservoir-to-market model was developed, integrating information from laboratory experiments (phase behavior, core flood), field analogues (well performance and layout), facilities, rigs, costs, scheduling, and economics. Recently published ASP flood data of the central Xing2 area in Daqing, China was used for model inputs. A reservoir-to-market benchmark model for a typical mature onshore field was successfully built and tested, and could value projects using standard economic metrics (net present value, internal rate of return, value investment ratio, unit technical cost, and payback period). Model simplification was achieved through global sensitivity analysis. Using a mean-reversion oil price model, the oil price accounted for 98% of the total sensitivity. . Model efficiency was achieved through discretization of input parameter uncertainties, which sped the screening process. Decision-making between model alternatives given information and different states of nature was performed through decision-tree techniques based on overall project valuation. Overall, this study was novel and provided benefit as a robust, integrated process-oriented framework for chemical EOR project screening, valuation, and decision-making. / text

Chemical Enhanced Oil Recovery methods have been growing in popularity as a result of the depletion of conventional oil reservoirs and high oil prices. These processes are significantly more complex when compared to waterflooding and require detailed engineering design before field-scale implementation. Coreflood experiments that have been performed on reservoir rock are invaluable for obtaining parameters that can be used for field-scale flooding simulations. However, the design used in these floods may not always scale to the field due to heterogeneities, chemical retention, mixing and dispersion effects. Reservoir simulators can be used to identify an optimum design that accounts for these effects but uncertainties in reservoir properties can still cause poor project results if it not properly accounted for. Different reservoirs will be investigated in this study, including more unconventional applications of chemical flooding such as a 3md high-temperature, carbonate reservoir and a heterogeneous sandstone reservoir with very high initial oil saturation. The goal of the research presented here is to investigate the impact that select reservoir uncertainties can have on the success of the pilot and to propose methods to reduce the sensitivity to these parameters. This research highlights the importance of good mobility control in all the case studies, which is shown to have a significant impact on the economics of the project. It was also demonstrated that a slug design with good mobility control is less sensitive to uncertainties in the relative permeability parameters. The research also demonstrates that for a low-permeability reservoir, surfactant propagation can have a significant impact on the economics of a Surfactant-Polymer Flood. In addition to mobilizing residual oil and increasing oil recovery, the surfactant enhances the relative permeability and this has a significant impact on increasing the injectivity and reducing the project life. Injecting a high concentration of surfactant also makes the design less sensitive to uncertainties in adsorption. Finally, it was demonstrated that for a heterogeneous reservoir with high initial oil saturation, optimizing the salinity gradient will significantly increase the oil recovery and will also make the process less sensitive to uncertainties in the cation exchange capacity. / text

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. / text

This study explores alternative alkaline agents other than sodium carbonate for ASP process on reactive and non-reactive crude oil recovery at 55oC and 100oC. The alkalis studied were sodium metaborate, pH of 10-10.5, and a sodium silicate/borax mixture, pH of 11. Sodium metaborate showed very optimistic results similar to sodium carbonate studies. Sodium metaborate ASP floods recovered 97-99% of residual oil after waterflood in Berea sandstone at 55oC. The oil saturation in the core after the chemical flood was between 0.5-2%. Sodium metaborate ASP floods recovered 96% of the tertiary oil with a residual oil saturation of 2.6% in Bentheimer sandstone at 100oC. More importantly, the retention of surfactant was very low with the use of metaborate in Berea, Bentheimer and high clay content reservoir cores. 0.18 mg/g rock (68%) and 0.07 mg/g rock (30%) of surfactant was retained in Berea and Bentheimer respectively with the use of sodium metaborate. Sodium metaborate ASP floods recovered 96% and 98% of residual oil with a final oil saturation of 4.8% and 0.56% at 100oC and 55oC respectively in reservoir rock. The retention in reservoir core was 0.13 mg/g (48%) and 0.29 mg/g (80%) at 100oC and 55oC respectively. Sodium borax/metasilicate had a lower tertiary oil recovery due to higher surfactant retention in Berea sandstone. The ASP flood recovered 81% and 86% of tertiary oil at 100oC and 55oC respectively. The retention was 0.326 mg/g (97%) and 0.267 mg/g (98%). The last section involves treatment and reduction of reservoir cores containing clays and iron minerals. Reservoirs exist as anaerobic and reduced environments and these conditions must be emulated in laboratory experiments. Exposure of reservoir cores to aerobic conditions causes an oxidizing environment in the core leading to higher surfactant retention in the laboratory than the field. Dithionite was used to reduce reservoir cores and produce lower surfactant retention closer to field tests. Proper reduced conditions also improved oil recovery. Dithionite must be buffered with sodium bicarbonate to maintain the reducing power of dithionite. Dithionite oxidation by ferric iron and water causes hydroxyl ion consumption and pH decrease. The EH and iron concentration of the effluents must be monitored to determine the success of the core reduction. Effluent EH matching injected values and iron concentration close to the mineral solubility in brine should be used as benchmark for the success of core reduction / text

After a fracturing job in a shale reservoir, only a fraction of injected water is recovered. Water is trapped inside the reservoir and reduces the relative permeability of gas. By reducing the interfacial tension between water and hydrocarbon, more water can be recovered thus increasing overall gas production. By adding surfactants into the fracturing fluid, the IFT can be reduced and will help mobilize trapped water. From previous research, two types of surfactant have been identified to be CO₂ soluble. These are the ethoxylated tallow amine and ethoxylated coco amine with varying ethoxylate length. Experiments were performed to test the solubility of these surfactants in water, observe how they change the interaction between HC and water, and measure the IFT reduction between HC and water. Surfactants with more than 10 EO groups were soluble at all salinities, temperature and pH. They also form a non-typical water-in-oil emulsion at all salinities. The surfactants, Ethomeen T/25, T/30, C/15, and C/25 were used in the IFT measurements. They showed interesting trends that exhibit their hydrophilic/hydrophobic nature. These surfactants reduce the IFT between pentane and water to approximately 5 mN/m. The results show that these surfactants do reduce the IFT between water and hydrocarbon, but not as well as conventional EOR surfactants. They do have other added benefits such as being CO₂ soluble, form water in oil emulsions, and tolerant to high temperature and salinity. / text

The focus of this study was the development of an improved correlation that more accurately quantifies the relationships between optimum salinity, optimum solubilization ratios, chemical formulation variables such as surfactant and co-solvent structures, and the EACN. Entrained in this study are improved correlations for co-solvent partition coefficients and correlations for the optimum salinity and solubilization ratio with EACN. Several trends in the oil-water partition coefficient were observed with the alcohol type (IBA and phenol), the number of ethylene oxide groups in the co-solvent, the EACN of the oil, temperature, and salinity. New EACN measurements were made using optimized formulations containing various combinations of primary surfactants, co-surfactants, co-solvents and alkali. The new EACN measurements ranged from 11.3 to 21.1. These new data significantly expand the total number of reliable EACN values available to understand and correlate chemical EOR formulation results. An improved correlation that more accurately quantifies the relationship between surfactant structure, co-solvents, oil, temperature, and optimum salinity was developed using a new and much larger high quality formulation dataset now available from studies done in recent years in the Center for Petroleum and Geosystems Engineering at the University of Texas at Austin. The correlation is useful for understanding the now very large number of microemulsion phase behavior experiments as well as the uncertainties associated with these data, and for suggesting new chemical structures to develop and test. / text

The primary objectives of this research were to understand the potential for gravity-stable surfactant floods for enhanced oil recovery without the need for mobility control agents and to optimize the performance of such floods. Surfactants are added to injected water to mobilize the residual oil and increase the oil production. Surfactants reduce the interfacial tension (IFT) between oil and water. This reduction in IFT reduces the capillary pressure and thus the residual oil saturation, which then results in an increase in the water relative permeability. The mobility of the surfactant solution is then greater than the mobility of the oil bank it is displacing. This unfavorable mobility ratio can lead to hydrodynamic instabilities (fingering). The presence of these instabilities results in low reservoir sweep efficiency. Fingering can be prevented by increasing the viscosity of the surfactant solution or by using gravity to stabilize the displacement below a critical velocity. The former can be accomplished by using mobility control agents such as polymer or foam. The latter is called gravity-stable surfactant flooding, which is the subject of this study. Gravity-stable surfactant flooding is an attractive alternative to surfactant polymer flooding under certain favorable reservoir conditions. However, a gravity-stable flood requires a low velocity less than the critical velocity. Classical stability theory predicts the critical velocity needed to stabilize a miscible flood by gravity forces. This theory was tested for surfactant floods with ultralow interfacial tension and found to over-estimate the critical velocity compared to both laboratory displacement experiments and fine-grid simulations. Predictions using classical stability theory for miscible floods were not accurate because this theory did not take into account the specific physics of surfactant flooding. Stability criteria for gravity-stable surfactant flooding were developed and validated by comparison with both experiments and fine-grid numerical simulations. The effects of vertical permeability, oil viscosity and heterogeneity were investigated. Reasonable values of critical velocity require a high vertical permeability without any continuous barriers to vertical flow in the reservoir. This capability to predict when and under what reservoir conditions a gravity-stable surfactant flood can be performed at a reasonable velocity is highly significant. Numerical simulations were also used to show how gravity-stable surfactant flooding can be optimized to increase critical velocity, which shortens the project life and improves the economics of the process. The critical velocity for a stable surfactant flood is a function of the microemulsion viscosity and it turns out there is an optimum value that can be used to significantly increase the velocity and maintain stability. For example, the salinity gradient can be optimized to gradually decrease the microemulsion viscosity. Another alternative is to inject a polymer drive following the surfactant solution, but using polymer complicates the process and adds to its cost without significant benefit in most gravity-stable surfactant floods. A systematic approach was introduced to make decisions on using polymer in applications based on stability criteria and cost. Also, the effect of an aquifer on gravity-stable surfactant floods was investigated as part of a field-scale study and strategies were developed to minimize its effect on the process. This study has provided new insights into the design of an optimized gravity-stable surfactant flood. The results of the numerical simulations show the potential for high oil recovery from gravity-stable surfactant floods using horizontal wells. Application of gravity-stable surfactant floods reduces the cost and complexity of the process. The widespread use of horizontal wells has greatly increased the attractiveness and potential for conducting surfactant floods in a gravity-stable mode. This research has provided the necessary criteria and tools needed to determine when gravity-stable surfactant flooding is an attractive alternative to conventional surfactant-polymer flooding. / text

For the first time the interfacial properties of nonionic hydrocarbon surfactants at both the air-water and CO₂-water interfaces are investigated in terms of surfactant structure to determine the changes in surfactant efficiency (negative of the logarithm of the surfactant concentration to create a surface pressure of 20 mN/m). At the air-water interface, linear surfactant tails are more efficient due to the higher packing ability of the straight chains in the dense surfactant monolayer. However, at the CO₂-water interface, surfactant adsorption is small and tails can be solvated. Thus, branching which increases both tail solvation and tail hydrophobicity also enlarges the hard disk area of the surfactant to ultimately increase the efficiency of the surfactant at the CO₂-water interface. CO₂-in-water concentrated emulsions (foams) are studied over short and long times to evaluate the foam stability as a function of both surfactant structure and foam conditions using in-situ optical microscopy. The surface pressure measured at the CO₂- water interface is correlated with the short time stability of coalescing foams with very small cell sizes (under 0.4 [mu]m in diameter). Long time stability of bubbles to coalescence is shown under a variety of conditions. The rheology of these bulk CO₂-in-water foams under high-pressure conditions are also evaluated through measurements of the pressure drop over a capillary tube. Viscosities in excess of 200 cP are measured, an increase of over 1000 time that of pure CO₂ (0.09 cP at 24 °C and 2000 psia). The viscosity of the C/W foams are found to correlate with bubble size, continuous phase viscosity, shear rate, and interfacial tension. Hydrophobic silica particles adsorbed at the interface are also used to stabilize water-in-CO₂ emulsions as an alternative to surfactant stabilizers. The difficulties of tail solvation associated with many hydrocarbon surfactants in CO₂ can be removed by using particles instead of surfactant. A porous cross-linked shell is formed about the hydrophilic (colloidal and fumed) silica to render the particles CO₂-philic and the crosslinking removes ligand tails from the particle surface. / text