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

Chemical enhanced oil recovery (CEOR) has gained a rapid momentum in the recent past due to depleting reserves of “easy-oil” and soaring oil prices. Hence, CEOR is now being considered for several candidates with varied oils and reservoir conditions, which demands the need for large hydrophobe surfactants. A new class of thermally and chemically stable large hydrophobe surfactant, Guerbet alkoxy carboxylates (GAC) has been tested. Unlike Guerbet alkoxy sulfates, GAC are stable at all pH and can be extremely useful in cases where alkali usage is prohibitive. They also exhibit synergistic behavior with internal olefin sulfonates (IOS) and alkyl benzene sulfonates (ABS), with the mixture showing enhanced calcium tolerance than the individual surfactants. Furthermore, in an attempt to diversify the raw material base, a new class of hydrophobe, viz. tristyrylphenol (TSP) based on petrochemical feed stock has also been developed and evaluated. Given the fact that there are hundreds of surfactants that can be tested for a particular candidate, the difficulty often lies in choosing the right surfactant to begin with. In an attempt to simplify that, a new correlation to predict the optimum surfactant structure has been developed. It relates the optimum surfactant structure to the formulation variables like oil properties, salinity, and temperature, including the parameters like PO and EO for new-generation surfactants. The correlation can serve as a guideline in choosing the optimum surfactant and will help in improving our understanding of the relationship among variables affecting the optimum surfactant structure. Surfactant retention is an important factor affecting the economics of chemical flooding and has to be studied carefully. Using an extensive data obtained from core flood studies a new correlation for predicting surfactant retention including the variables like pH, TAN, salinity, mobility ratio, temperature, co-solvent, and surfactant molecular weight has been developed. All these are new and highly significant advance in the optimization of chemical EOR processes that will greatly reduce the time and cost of the effort required to develop a good formulation as well as to improve its performance. / text

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