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

Chemical flooding has been studied for 50 years. However, never have the conditions encouraging its growth been as good as right now. Those conditions being new, improved technology and oil prices high enough to make implementation economical. The objective of this work was to develop economical, robust chemical formulations and processes that recover oil in field pilots when properly implemented. This experimental study goes through the process of testing surfactants to achieve optimal phase behavior, coreflooding with the best chemical formulations, improving the formulation and testing it in more corefloods, and then finally recommending the formulation to be tested in a field pilot. The target reservoir contains a light (34° API, 10 cP), non-reactive oil at about 22° C. The formation is a moderate permeability (50 - 300 mD) sandstone with a high clay content (up to 13%). Different surfactants and surfactant mixtures were tested with the oil including alkyl benzene sulfonates (ABS), Guerbet alcohol sulfates (GAS), alkyl propoxy sulfates, and internal olefin sulfonates (IOS). The best formulation contained 0.75% TDA -13PO-SO₄, 0.25% C₂₀₋₂₄ IOS, 0.75% isobutanol (IBA), 1% Na₂CO₃, all which are mixed in a softened fresh water from a supply well. Corefloods recovered 93% of residual oil from reservoir cores. Core flood experiments were also done with the alkali sodium carbonate to measure the effluent pH in a Bentheimer sandstone core with a cation exchange capacity (CEC) of 2 meq/100g. Floods at frontal velocities of 100, 10, and 0.33 ft/D were performed with 0.3 pore volume slugs of 0.7% Na₂CO₃ at 86° C. The effluent was analyzed for ions and pH breakthrough. It was found that the pH breakthrough occurred before surfactant breakthrough would be expected as desired although the pH was lower at a frontal velocity of 0.33 ft/D than at the higher velocities. The Na₂CO₃ consumption was 0.244, 0.238, and 0.207 meq/100 g rock at velocities of 100, 10, and 0.33 ft/D, respectively. In addition, a no-alkaline formulation consisting of a new large hydrophobe ether carboxylate surfactant mixed with an internal olefin sulfonate was tested on an active oil and it successfully recovered 99% of the waterflood remaining oil from an Ottawa sand pack with no salinity gradient and no alkali. The final residual oil saturation after the chemical flood (S[subscript orc]) was only 0.005 / text

Highly fractured and vuggy oil reservoirs represent a challenge for enhanced oil recovery (EOR) methods. The fractured networks provide flow paths several orders of magnitude greater than the rock matrix. Common enhanced oil recovery methods, including gases or low viscosity liquids, are used to channel through the high permeability fracture networks causing poor sweep efficiency and early breakthrough. The purpose of this research is to determine the feasibility of using foam in highly fractured reservoirs to produce oil-rich zones. Multiple surfactant formulations specifically tailored for a distinct oil type were analyzed by aqueous stability and foam stability tests. Several core floods were performed and targeted effects such as foam quality, injection rate, injection type, permeability, gas saturation, wettability, capillary pressure, diffusion, foam squeezing, oil flow, microemulsion flow and gravity segregation. Ultimately, foam was successfully propagated under various core geometries, initial conditions and injections methods. Consequently, fluids were able to divert to unswept matrix and improve the ultimate oil recovery. / text

Even in times of renewable energy revolution fossil fuels will play a major role in energy supply, transportation, and chemical industry. Therefore, increasing demand for crude oil will still have to be met in the next decades by developing new oil re-serves. To cope with this challenge, companies and researchers are constantly seeking for new methods to increase the recovery factor of oil fields. For that reason, many enhanced oil recovery (EOR) methods have been developed and applied in the field. EOR methods alter the physico-chemical conditions inside the reservoir. One possibility to achieve this is to inject an aqueous solution containing special chemicals into the oil-bearing zone. Polymers, for example, increase the viscosity of the injected water and hence improve the displacement of the oil to the production well. The injection of surfactant solutions results in reduced capillary forces, which retain the oil in the pores of the reservoir. Some surfactants form viscoelastic solutions under certain conditions. The possibil-ity to apply those solutions for enhanced oil recovery has been investigated by some authors in the last years in low salinity brines. Reservoir brines, however, often contain high salt concentrations, which have detrimental effects on the properties of many chemical solutions applied for EOR operations. The Triphenoxymethane derivatives, which were the subject of study in this thesis, form viscoelastic solutions even in highly saline brines. The aim of this thesis was to investigate the efficiency and the mode-of-action of this new class of chemical EOR molecules with respect to oil mobilization in porous media.

Even in times of renewable energy revolution fossil fuels will play a major role in energy supply, transportation, and chemical industry. Therefore, increasing demand for crude oil will still have to be met in the next decades by developing new oil re-serves. To cope with this challenge, companies and researchers are constantly seeking for new methods to increase the recovery factor of oil fields. For that reason, many enhanced oil recovery (EOR) methods have been developed and applied in the field. EOR methods alter the physico-chemical conditions inside the reservoir. One possibility to achieve this is to inject an aqueous solution containing special chemicals into the oil-bearing zone. Polymers, for example, increase the viscosity of the injected water and hence improve the displacement of the oil to the production well. The injection of surfactant solutions results in reduced capillary forces, which retain the oil in the pores of the reservoir. Some surfactants form viscoelastic solutions under certain conditions. The possibil-ity to apply those solutions for enhanced oil recovery has been investigated by some authors in the last years in low salinity brines. Reservoir brines, however, often contain high salt concentrations, which have detrimental effects on the properties of many chemical solutions applied for EOR operations. The Triphenoxymethane derivatives, which were the subject of study in this thesis, form viscoelastic solutions even in highly saline brines. The aim of this thesis was to investigate the efficiency and the mode-of-action of this new class of chemical EOR molecules with respect to oil mobilization in porous media.

Chemical enhanced oil recovery (cEOR) aims to increase the oil recovery of mature oil fields, using aqueous solutions of surfactants and polymers, to mobilize trapped oil and maintain production. The interfacial tensions (IFTs) between the injected aqueous solution, the oil droplets in reservoirs, and other possible phases formed (e.g., a “middle phase” microemulsion) are important for designing and assessing a chemical formulation. Ultralow IFTs, less than 10^-2 mN·m^-1, are needed to increase the capillary number and help mobilize trapped oil droplets. Despite this fact, phase behavior tests have received more attention than IFTs for designing and evaluating surfactant formulations that result in high oil recovery efficiencies, because incorporating reliable IFTs into such evaluation process is avoided due to difficulties in obtaining reliable values. Hence, the main thrusts of this dissertation are to: (a) develop robust IFT measurement protocols for obtaining reliable IFTs regardless of the complexity of water and oil phase constituents and (b) improve the existing surfactant polymer formulation evaluation and screening processes by successfully incorporating the IFT as one of the critical parameters.<br>First, two robust tensiometry protocols using the known emerging bubble method (EBM) and the spinning bubble method (SBM) were demonstrated, for determining accurately equilibrium surface tensions (ESTs) and equilibrium IFTs (EIFTs). The protocols are used for measuring the dynamic surface tensions (DSTs), determining the steady state values, and establishing the stability of the steady state values by applying small surface area perturbations by monitoring the ST or IFT relaxation behavior. The perturbations were applied by abruptly expanding or compressing surface areas by changing the bubble sizes with an automated dispenser for the EBM, and by altering the rotation frequency of the spinning tube for the SBM. Such robust tension measurement protocols were applied for Triton X-100 aqueous solutions at a fixed concentration above its critical micelle concentration (CMC). The EST value of the model solution was 31.5 ± 0.1 mN·m^-1 with the EBM and 30.8 ± 0.2 mN·m^-1 with the SBM. These protocols provide robust criteria for establishing the EST values.<br>Second, the EIFTs of a commercial single chain anionic surfactant solution in a synthetic brine against a crude oil from an active reservoir were determined with the new protocol described earlier. The commercial surfactant used here has an oligopropoxy group between a hydrophobic chain and a sulfate head group. The synthetic brine has 9,700 ppm of total dissolved salts, which are a mixture of sodium chloride (NaCl), potassium chloride (KCl), manganese (II) chloride tetrahydrate (MnCl₂·4H₂O), magnesium (II) chloride hexahydrate (MgCl₂·6H₂O), barium chloride dihydrate (BaCl₂·2H₂O), sodium sulfate decahydrate (Na₂SO₄·10H₂O), sodium bicarbonate (NaHCO₃), and calcium chloride dihydrate (CaCl₂·2H₂O). The DSTs curves of the surfactant concentrations from 0.1 ppm to 10,000 ppm by weight had a simple adsorption/desorption equilibrium at air/water surface with surfactant diffusion from bulk aqueous phase. Such a mechanism was also observed from the tension relaxation behavior after area perturbations for the oil/water interfaces while DIFT measurements. The CMC of the commercial surfactant was determined to be 12 ppm in water and 1 ppm in the synthetic brine used. From the initial tension reduction curves from DST and DIFT measurements, the equilibrium timescales were shorter with brine than with water, because the adsorbed surfactant on the oil/water interfaces were partitioned into oil phases. For both DST and DIFT results suggest that the adsorbed surfactant layer at interfaces were typical adsorbed soluble monolayers.<br>Third, the phase and rheological behavior of a commercial anionic surfactant in water and in brine are important for large scale applications. A phase map of the surfactant at 25 °C at full range of surfactant concentration was obtained. The supramolecular structures of the various phases were characterized by dynamic light scattering (DLS), cryogenic transmission electron microscopy (cryo-TEM), conductimetry, densitometry, and x-ray scattering. The identified phases evolved as the surfactant concentration was increased; they were a micellar solution phase, a hexagonal liquid crystalline phase, and a lamellar liquid crystalline phase. In addition, the characterization results provided detailed information about supramolecular structure parameters such as micellar sizes and their aggregation numbers, and liquid crystal spacings. The phase and rheological behavior trends identified here were of great importance because the trend was similar to that of single chain monoisomeric surfactant. Thus, this study provides a potential universality of phase behavior trends of surfactant-water systems despite of the multicomponent nature of surfactants.<br>Fourth, the EIFTs of the pre-equilibrated mixtures of surfactant, brine, and oil were determined and compared to the EIFTs prior to pre-equilibration, in order to systematically identify the most relevant IFT for oil recovery. The EIFT between surfactant solutions and oil without any pre-equilibration prior to tension measurements is defined as the un-pre-equilibrated EIFT (EIFT_up). The EIFT between oil and water phases after the pre-equilibration of surfactant, brine, and oil is defined as pre-equilibrated EIFT (EIFT_p). The EIFT_p’s were generally higher than EIFT_up’s. In addition, the effects of three mixing methods and the water-to-oil volume ratio (WOR) on the EIFT_p were evaluated. Out of three mixing methods, (A) mild mixing, (B) magnetic stirring, and (C) shaking vigorously by hand, method C produced mixtures which are the closest to the equilibrium state. The mixtures produced by method C had the largest decrease of the surfactant concentration during pre-equilibration due to the surfactant partitioning into oil phases. Moreover, the WOR affects the EIFT_p significantly due to the preferential partitioning of surfactant components into oil phases. More specifically, the WOR and the EIFT_p were found to be inversely correlated, because the amount of partitioned surfactant increased as the oil volume fraction increased. The EIFT_p’s were different from the EIFT_up’s at the same total surfactant concentrations in the aqueous layer evidently because of preferential partitioning of the various surfactant components.<br>Finally, the effect of surfactant losses due to adsorption into the rock surface on the pre-equilibrated EIFT (EIFT_p) were evaluated to improve surfactant formulation protocols. Here, five types of EIFTs were identified, along with robust protocols for determining them. These are: (I) the un-pre-equilibrated equilibrium IFT (EIFT_up); (II) the un-pre-equilibrated EIFTs in the presence of rock (EIFT_up,rock); (III) the pre-equilibrated EIFTs (EIFT_p) in the presence of oil; (IV) the pre-equilibrated EIFT in the presence of rock and oil (EIFT_p,rock); and (V) the effluent EIFT (EIFT_eff). The EIFT_up is the EIFT of the aqueous surfactant/brine solution against an oil drop without any pre-equilibration. The EIFT_up,rock is the EIFT between an oil drop and the surfactant solution after pre-equilibration with a rock sample to account for adsorption losses. The EIFT_p is the EIFT between the pre-equilibrated water and the oil phases from surfactant/brine/oil mixtures. The EIFT_p,rock is the EIFT between the pre-equilibrated water and the oil phases from surfactant/brine/oil/rock mixtures. The EIFT_eff is the EIFT from an effluent sample mixture of a laboratory-scale core flood test. Among the five types of EIFTs, the EIFT_p,rock was found to be the most important for the highest oil recovery performance in core flood tests, because it captures the most important surfactant partition processes, the partitioning to the oil phase and the partitioning by adsorption on the rock surface. Among three surfactant formulations tested with core flood experiments, the one with the lowest EIFT_p,rock (~0.01 mN·m^-1) had the highest oil recovery ratio (78%), and the one with the highest EIFT_p,rock (~0.2 mN·m^-1) had the lowest oil recovery ratio (55%). The other EIFTs correlated less with the oil recovery performance. Identifying surfactant formulations that have low or ultralow EIFTs, especially ultralow EIFT_p,rock’s, are critical for screening formulations appropriate for core flood tests and target field applications, and for predicting oil recovery performance. These works are a significant contribution for improving (a) the surfactant formulation evaluation protocols, and (b) the utilization of reliable IFTs and phase behavior test protocols for oil recovery and many other surfactant and colloid sciences applications.<br>