Design of an ASP flood in a High-Temperature, High-Salinity, Low-Permeability Carbonate

Abstract

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).

Novel fluorinated surfactants for enhanced oil recovery in carbonate reservoirs

“…Alkalis generate in situ surfactant by reacting with certain components of crude oil. Sodium hydroxide, sodium carbonate, and ammonium hydroxide are the most widely used compounds in alkaline injection . Surfactants are surface‐active agents that decrease the oil/water interfacial tension (IFT), which decreases residual oil saturation .…”

“…Sodium hydroxide, sodium carbonate, and ammonium hydroxide are the most widely used compounds in alkaline injection. [9][10][11][12] Surfactants are surface-active agents that decrease the oil/water interfacial tension (IFT), which decreases residual oil saturation. [13] High molecular mass water-soluble polymers are used to improve the mobility ratio by increasing the viscosity of the water and the volumetric sweep efficiency.…”

Novel Large-Hydrophobe Alkoxy Carboxylate Surfactants for Enhanced Oil Recovery

“…Levitt et al (2012) report an ASP core flood in a high temperature, high salinity carbonate. However, alkali cannot be used in many instances where anhydrite is present or soft injection water is not an option.…”

Design Challenges of Chemical EOR in High-Temperature, High Salinity Carbonates

“…A previous publication (Levitt et al, 2012) describes the geochemistry of the carbonate reservoir under investigation. Due to the probable presence of anhydrite, it is posited that dissolution will likely introduce several hundred ppm of calcium into any injected solution, greatly retarding the propagation of sodium carbonate.…”

“…The design of an ASP formulation for this reservoir has previously been presented (Levitt et al, 2012). However due to the high temperature and probable presence of anhydrite, it was decided that the use of sulfate surfactants, which require high pH and thus the successful propagation of alkali for stability at elevated temperatures (Adkins et al, 2010), presents an unnecessary risk in this case.…”