The physical structure of microemulsions and the degree to which ultra-low IFT is achieved is dependent on a number of parameters including the types and concentrations of surfactants, co-solvents and alkali, crude oil composition, brine composition, temperature and to a lesser extent, pressure. Modifying any one of these variables creates a microemulsion with different properties. The rheological properties of the microemulsion must be adjusted appropriately to achieve good performance under practical reservoir conditions. Two microemulsion properties of primary concern are undesirably high viscosity relative to oil viscosity and non-Newtonian behavior. The broader implications of injecting microemulsions with high viscosities or non-Newtonian behavior in the field include high surfactant retention, unsustainably high pressure gradients, reduced sweep efficiency and microemulsions that stagnate in the field due to high viscosity at low shear rates. The most common ways to reduce microemulsion viscosity are to optimize the surfactant formulation with a good co-solvent and/or by adding more branching to the surfactant hydrophobe. Adding co-solvent in appropriate concentrations makes a microemulsion much less viscous. However, co-solvents increase the cost and complexity and also tend to increase the IFT. A less conventional solution involves increasing the temperature of the injection water thereby lowering both the oil and microemulsion viscosity. This approach has been tested successfully in core floods using both surrogate and reservoir cores.
This paper examines some of the challenges related to the application of alkali-surfactant-polymer (ASP) flooding in high-temperature carbonate oil reservoirs. In particular, the calcium sulfate minerals gypsum (CaSO4.2H2O) and anhydrite (CaSO4) often present in small quantities in carbonate formations, have long been recognized as obstacles to chemical flooding. We illustrate these challenges for an 83 ºC carbonate field, initially containing evaporitic water, flooded with an ASP slug mixed in seawater, and followed with a polymer drive in diluted seawater. Introduction Carbonates, and in particular high-salinity, high-temperature carbonates, represent a significant fraction of remaining oil reserves, but have long been considered a challenging target for chemical enhanced oil recovery (EOR). Individual concerns relating to temperature, calcium, and salinity tolerance of EOR polymers (Zaitoun and Potie, 1983; Moradi et al., 1983; Levitt et al., 2011(A&B)) and surfactants (Adkins et al, 2010; Bourrel and Schechter, 1988; Akstinat, 1985) have been extensively studied. Concerns relating to the carbonate milieu, on the other hand, are diverse and may require specific knowledge of the target reservoir, however, examined individually, can often be mitigated. This paper focuses primarily on frequently encountered challenges related to the geochemical interactions between carbonates and EOR chemicals. We illustrate these challenges for an 83 ºC carbonate field, initially containing evaporitic water, flooded with an ASP slug mixed in seawater, and followed with a polymer drive in diluted seawater. Geochemical equilibria of carbonate reservoirs The transport of EOR surfactants, polymers, and alkalis, almost all of which contain anionic moieties that are highly sensitive to divalent cations, through carbonate formations in which massive amounts of calcium and magnesium are present as calcite (CaCO3) or dolomite (CaMgCO3) is, at first glance, alarming. However the solubility of calcite is low enough (no more than around 10 ppm of calcium will dissolve under non-acidic conditions) that effects on surfactant and polymer are almost negligible. Palandri and Reed (2001) posit that all reservoirs are likely in equilibrium with calcite, indicating that calcium uptake due to equilibrium with calcite would be equally relevant for sandstone reservoirs. In the presence of significant quantities of sodium carbonate (Na2CO3), the equilibrium will be shifted such that calcium uptake from calcite dissolution will be essentially nil. Disordered dolomite may also be in equilibrium with formation waters, however its solubility is equally insignificant with respect to EOR chemicals. The calcium sulfate minerals, gypsum (CaSO4.2H2O) and anhydrite (CaSO4), often present in small quantities in carbonate formations, have however long been recognized as obstacles to chemical flooding. The predominance of each mineral as well as calcium and sulfate concentrations of desulfated seawater in equilibrium with the relevant mineral is presented in Figure 1. Gypsum is the equilibrium mineral present below around 45 ºC, at which point anhydrite becomes the equilibrium mineral form. Solubility of calcium sulfate minerals decreases monotonically with temperature, but increases with salinity. Calcium uptake from calcium sulfate mineral dissolution may thus range from as low as a couple of hundred parts-per-million (ppm) for fresh water injected into high-temperature formations, to around 2,000 ppm for a high-salinity brine injected into a low-temperature reservoir. This may have a significant effect on surfactant phase behavior as well as polymer viscosity, although this can be explicitly determined and mitigated (Levitt et al. 2009).
The presence of gypsum or anhydrite in oil reservoirs limits the application of alkali-surfactant-polymer (ASP) flooding using conventional alkalis such as sodium carbonate (Na2CO3) because these alkalis precipitate in the presence of gypsum leading to high alkalinity loss and permeability damage. Sodium metaborate (NaBO2) and ammonium hydroxide (NH4OH) were investigated as possible alternatives to Na2CO3. Batch mixing experiments were performed with these alkalis in the presence of excess gypsum, single phase brine-alkali transport experiments were perfomed in sandstone and carbonate cores containing gypsum, and ASP corefloods were performed in outcrop and reservoirs cores (containing gypsum). Effluent pH and ion concentrations including boron, calcium and sulfate were measured using an ion chromatograph (IC) and inductively coupled plasma (ICP). The residence times in injection experiments were increased up to 15 days to study the effect of reaction kinetics. NaBO2 and NH4OH were found to maintain and propagate a high pH of more than 10 in the batch and transport experiments without significant permeability changes. High oil recoveries were obtained in the ASP corefloods along with low surfactant retention due to the high pH propagation.
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