A limited number of laboratory studies and pilot programs have been reported in chemical Enhanced Oil Recovery (EOR) flooding of carbonate reservoirs (Adams & Schievelbein, 1987). Fewer still have involved surfactants in limestone reservoirs. No surfactant/polymer flood on a field wide basis of a carbonate reservoir has ever been documented in the literature (Manrique, Muci, & Gurfinkel, 2010). This void represents a colossal opportunity given that nearly a third of the 32 billion barrels of oil consumed in the world each year come from carbonate reservoirs (Sheng, 2011, pp. 1, 254). This thesis is based on experiments with a high hardness (~5,000 ppm divalent ions) carbonate field. Phase behavior, aqueous stability, and core flood experiments were performed using polymer and various surfactants and co-solvents. Both commercially available and laboratory synthesized surfactants were tested. The objective was to optimize the chemical injection design in order to lower interfacial tension between water and oil in the reservoir. Research was also done with alkali intended for use with hard brines. The main challenges when working with hard brine were poor solubilization and low aqueous stability limits. However, highly propoxylated and ethoxylated surfactants mixed with internal olefin sulfonates, hydrophilic sulfates, and sec-butanol were observed to have very high solubilization ratios, fast phase behavior equilibration times, negligible viscous macroemulsion effects, and excellent aqueous stability. Spinning drop interfacial tensiometer tests confirmed low IFT values were obtained for a range of acceptable salinities with hard brine. Three core floods were performed using one of the surfactant formulations developed. One flood was done with field core, brine, and crude oil and failed to meet expectations because of high levels of heterogeneity (vugs) within the core that lead to an elongated oil bank and low and slow oil recovery. The other floods were done with Estillades Limestone. The first Estillades flood used hard synthetic field brine and had better mobility but poor oil recovery. The last core flood had good mobility and recovered 90% of the residual oil to water flooding, but only after a total of 1.1 pore volumes of 1.0 wt% surfactant solution were injected. The results provided in this thesis constitute proof of concept that S/P flooding can be done in high salinity and hardness reservoirs. / text

Well stimulation is the treatment remedy when oil/gas productivity decreases to unacceptable economical limits. Well stimulation can be carried out through either "Matrix Acidizing" or fracturing with both "Hydraulic Fracturing" and "Acid Fracturing" techniques. "Matrix Acidizing" and "Acid Fracturing" applications involve injecting an acid to react with the formation and dissolve some of the minerals present and recover or increase the permeability. The permeability enhancement is achieved by creating conductive channels "wormholes" in case of "Matrix Acidizing" or creating uneven etching pattern in case of "Acid Fracturing" treatments. In both cases, and to design a treatment successfully, it is necessary to determine the distance that the live acid will be able to penetrate inside the formation, which in turn, determines the volume of the acid needed to carry out the treatment. This distance can be obtained through lab experiments, if formation cores are available, or estimated by modeling the treatment. The successful model will depend on several chemical and physical processes that take place including: the acid transport to the surface of the rock, the speed of the reaction of the acid with the rock, which is often referred to as "Reaction Rate", and the acid leak-off. The parameters describing these processes such as acid diffusion coefficient and reaction kinetics have to be determined experimentally to ensure accurate and reliable modeling. Hydrochloric acid and simple organic acids such as acetic and citric acids have been used extensively for stimulation treatments. The diffusion and reaction kinetics of these acids, in a straight form, were investigated thoroughly in literature. However, solely these acids are used in a simple form in the field. Acid systems such as gelled, crosslinked gelled, surfactant-based, foam-based, or emulsified acids are used to either retard the reaction rate or to enhance acid diversion. Literature review shows that additional work is needed to understand the reaction and report the diffusion and kinetics of these systems with carbonate. In addition, a new chelating agent (GLDA) was recently introduced as a stand-alone stimulating fluid. The kinetics and the mass transfer properties of this acid were not studied before. Therefore, the objective of this work is to study the reaction of different acid systems with calcite and dolomite and report the mass transport and kinetic data experimentally. Lactic acid, a chelating agent (GLDA), and in-situ gelled HCl-formic acids were investigated in this study. In some cases, rheology measurements and core flood experiments were conducted. The data were combined with the reaction study to understand the behavior of these acids and examine their efficiency if injected in the formation.

[pt] O presente trabalho busca discutir mecanismos em pauta na literatura em relação à injeção de água de salinidade otimizada com os resultados de 10 (dez) testes de escoamento bifásico óleo/água para 2 (dois) cenários carbonatos e 1 (um) arenito. O principal objetivo foi estudar o efeito de íons potencialmente determinantes (Ca, Mg, SO4, NaCl), além da temperatura, no fator de recuperação e curvas de permeabilidade relativa óleo-água. Em relação a carbonatos, avaliou-se se Ca/Mg e SO4 tinham algum papel na alteração da molhabilidade da formação e, em caso positivo, se esse efeito era exacerbado em ambiente de baixa salinidade. Em relação a reservatórios areníticos, comparou-se a injeção de água dessulfatada com água do mar diluída. Dos testes de deslocamento realizados em amostras de arenito, observou-se que água do mar diluída, injetada após água do mar dessulfatada foi capaz de, em média, acrescer o FR em 2,8 por cento e em reduzir o Sor de 2,1 por cento. Quanto ao cenário carbonato A de alta temperatura avaliado (95 graus Celsius), observou-se que água otimizada, quando injetada após água dessulfatada, foi capaz de aumentar o FR em 15,3 por cento e diminuir o Sor em 12,1 por cento. Ainda, quando se introduziu água otimizada de forma secundária, observou-se redução no Sor em 4,6 por cento e aumento do FR em 5,9 por cento quando comparado com a injeção usual de água. No carbonato B, injeção da água otimizada após água dessulfatada levou a um acréscimo de 10,1 por cento no FR e diminuição de 7,1 por cento no Sor. Tanto no cenário arenito quanto nos carbonatos, não houve produção adicional de óleo quando injetado água do mar após a injeção de água otimizada. Isso corrobora a ideia de que o fluido customizado permitiria atingir o máximo de eficiência de deslocamento. / [en] The present work seeks to discuss possible mechanisms in the literature based in the results of 10 (ten) oil / water core flooding experiments in 2 (two) carbonate scenarios and 1 (one) sandstone scenario Rock and oil samples from real reservoirs were used in experimental conditions of temperature and pressure close to the field reality. The main objective was to study the effect of Ca, Mg, SO4, NaCl and temperature on the recovery factor and oil-water relative permeability curves.Regarding the carbonate scenario, it was evaluated whether Ca / Mg and SO4 had any role in altering the wettability of the formation and, if so, whether this effect was exacerbated in a low salinity environment. For the sandstone reservoirs, the injection of desulfated water and seawater diluted were compared. From the displacement tests carried out in the sandstone samples, it was observed that the diluted sea water, injected after the desulfated sea water, was able to average increase the RF by 2.8 percent and to reduce the Sor by 2.1 percent. Regarding the hightemperature carbonate scenario evaluated (95 degrees Celsius) it was observed that the optimized water, when injected tertiarily, was able to increase the RF by 15.3 percent and decrease the Sor by 12.1 percent, in comparison to the desulfated seawater. In carbonate B, optimized water injection after desulfated water led to a 10.1 percent increase in the recovery factor and a 7.1 percent decrease in the residual oil saturation. Mainly, in both sandstone and carbonate scenarios, there was no additional oil production when sea water was injected after the optimized water injection. This corroborates the idea that the taylor-designed fluid achieves maximum displacement efficiency.

This Ph.D. research project targets Cooper Basin oil reservoirs of very low permeability (approximately 1mD) where injectivities required for water flooding are not achievable. However, the use of injection gases such as CO₂ would not have injectivity problems. CO₂ is abundant in the region and available for EOR use. CO₂ was compared to other CO₂-rich injection gases with a hydrocarbon content including pentane plus components. While the effect of hydrocarbon components up to butane have been investigated in the past, the effect of n-pentane has on impure CO₂ gas streams has not. One particular field of the Cooper Basin was investigated in detail (Field A). However, since similar reservoir and fluid characteristics of Field A are common to the region it is expected that the data measured and developed has applications to many other oil reservoirs of the region and similar reservoirs elsewhere. The aim of this Ph.D. project is to determine the applicability of CO₂ as an injection gas for Enhanced Oil Recovery (EOR) in the Cooper Basin oil reservoirs and to compare CO₂ with other possible CO₂-rich injection gases. The summarised goals of this research are to: • Determine the compatibility of Field A reservoir fluid with CO₂ as an injection gas. • Compare CO₂ to other injection gas options for Field A. • Development of a correlation to predict the effect of nC₅ on MMP for a CO₂- rich injection gas stream. These goals were achieved through the following work: • Extensive experimental studies of the reservoir properties and the effects of interaction between CO₂-rich injection gas streams and Field A reservoir fluid measuring properties related to: • Miscibility of the injection gas with Field A reservoir fluid • Solubility and swelling properties of the injection gas with Field A reservoir fluid • Change in viscosity-pressure relationship of Field A reservoir fluid due to addition of injection gas • A reservoir condition core flood experiment • Compositional simulation of the reservoir condition core flood to compare expected recoveries from different injection gases • Development of a set of Minimum Miscibility Pressure (MMP) measurements targeted at correlating the effect of nC₅ on CO₂ MMP. The key findings of this research are as follows: • Miscibility is achievable at practical pressures for Field A and similar reservoir fluids with pure CO₂ or CO₂-rich injection gases. • For Field A reservoir fluid, viscosity of the remaining flashed liquid will increase at pressures below ~2500psi due to mixing the reservoir fluid with a CO₂-rich injection gas stream. • Comparison of injection gases showed that methane rich gases are miscible with Field A so long as a significant quantity of C₃+ components is also present in the gas stream. • There is a defined trend for effect of nC₅ on MMP of impure CO₂. This trend was correlated with an error of less than 4%. • Even though oil composition is taken into account with the base gas MMP, it still affects the trend for effect of nC₅ on MMP of a CO₂-rich gas stream. • An oil characterisation factor was developed to account for this effect, significantly improving the results, reducing the error of the correlation to only 1.6%. The significance of these findings is as follows: • An injection pressure above ~3000psi should be targeted. At these pressures miscibility is achieved and the viscosity of the reservoir fluid injection gas mix is reduced. • CO₂ should be compared to gases such as Tim Gas should after considering the cost of compression, pipeline costs and distance from source to destination will need to be considered. • The addition of nC₅ will reduce the MMP and increase the recovery factor, however the cost of the nC₅ used would be more than the value of increased oil recovered. • The developed correlation for the effect of nC₅ on impure CO₂ MMP can be used broadly within the limits of the correlation. • Further research using more oils is necessary to validate the developed oil characterisation factor and if successful, using the same or similar method used to improve other correlations. / http://proxy.library.adelaide.edu.au/login?url= http://library.adelaide.edu.au/cgi-bin/Pwebrecon.cgi?BBID=1369016 / Thesis (Ph.D.) -- University of Adelaide, Australian School of Petroleum, 2009.

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>

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. / text