CO2 emulsion/foam is a promising method for controlling the mobility and improving the volumetric sweep efficiency in CO2 enhanced oil recovery (CO2-EOR) process. Recently, amine surfactants attract the attention of the researchers as CO2 emulsifiers/foamers, because of their switchable property: the surfactants are nonionic and CO2 soluble at high pH, and are cationic and water soluble at low pH. However, the efficiency of the commercial switchable amine surfactants is usually suppressed at high salinity (> 200 g/L TDS) and temperature (> 100 °C). Thus, novel switchable alkyl-amine surfactants are designed in house based on the hydrophilic and CO2-philic balance for rapidly generating strong and stable CO2 emulsions at high salinity and high temperature. These novel surfactants are evaluated and compared to a commercial one with respect to the solubility in brine and CO2, and emulsifying ability in bulk and in porous media at high temperature, high pressure and high salinity.
The novel surfactants show outstanding performance: soluble in 220 g/L NaCl brine at pH≤8 from room temperature to 120 °C, soluble in CO2 at relatively low pressure (91 bar) and high temperature (110 °C). The surfactants are thermally stable at 110 °C and pH=4 in the absence of O2. Strong CO2 emulsion/foam is observed in both bulk test and in silica sandpack with 0.2 (wt)% of the surfactant in brine. Additionally, the apparent viscosity of the CO2 emulsion/foam at 110 °C is significantly higher than that at lower temperatures. Comparing to the commercial surfactants, the CO2 emulsion/foam is stronger and generated faster by the novel surfactants. These novel surfactants can be synthesized using commercially available feeds and simple industrial processes. Thus, the novel surfactants are promising for generating the CO2 emulsion/foam, especially in the hot and salty carbonate reservoirs.
This article describes the formulation design, optimization, implementation, and lessons learned leading up to a successful 1-spot surfactant-polymer (SP) pilot in the Middle East. The target field is a high-temperature, high-salinity, low-permeability carbonate, and thus presents both great challenges and great potential for the application of chemical EOR technology.
A surfactant-polymer (SP) formulation was optimized for these conditions based upon a novel, hydrophilicity-enhanced molecule for high-temperature, high-salinity reservoirs synthesized by Total R&D labs. Thermal stability tests, over 5000 microemulsion pipette tests, and more than 40 corefloods were performed during the screening and optimization process leading up to the 1-spot SP pilot. Additionally, a novel method was developed to optimize polymer molecular weight distribution, in order to decouple in-situ viscosity from near-wellbore injectivity.
The final formulation consists of a 0.4 pore volume (PV) SP slug of 1.35% active surfactant, plus 1% clarifier, and SAV-225 polymer (SNF Floerger) in a 80 g/l brine corresponding to a hypothetical softened mixture of seawater and local aquifer water. This is followed by a polymer drive of AN-125 polymer (SNF Floerger) in softened seawater, such that a negative salinity gradient is imposed between the 230 g/l formation brine, 80 g/l SP slug, and 42 g/l seawater. The formulation was designed and implemented without need for a preflush.
Residual oil saturation to chemicals (Sorc) in analog limestone cores was measured as 5%±2%, corresponding to a recovery factor (RF) of 90%±4%. Reservoir limestone contains significant heterogeneity on the core-scale, likely preventing the formation of an oil bank, and thus yielded lower recoveries (Sorc: 13%±2%, RF: 84%±4%). One-spot pilot recovery corresponded closely to recovery in analog cores (Sorc: 4%, RF = 90%,
This is the final installment in a series of three papers examining iron mineralogy and its effect on surfactant adsorption in reservoir and outcrop rock samples. The goal of these studies is to establish best practices for obtaining surfactant adsorption values representative of those in a reduced oil reservoir, despite performing experiments in an oxidizing laboratory atmosphere.
This article follows two others examining the abundance and form of iron in the reservoir and in core samples (Part I:
Surfactant retention is a leading uncertainty in economic forecasting of chemical EOR, in large part due to the order-of-magnitude effects of artifacts such as improper core preservation. The industry standard is to (a) limit atmospheric contact of cores to the extent feasible, and (b) when necessary, reduce oxidized cores using strong reducing agents such as sodium dithionite, along with buffering and chelating agents such as sodium bicarbonate and EDTA or sodium citrate. However few studies have been performed to determine whether such invasive treatments are necessary, or what unintended effects the use of such reactive chemicals may have.
The most striking conclusion from these studies is the lack of clear evidence of any advantage of electrochemical reduction versus a simpler treatment with chelators such as sodium citrate or EDTA.
While treatment with a citrate-bicarbonate-dithionite solution does indeed lower adsorption several-fold further, solutions of either sodium bicarbonate or EDTA are at least as effective, and sodium citrate is almost as effective. These non-reductive treatments remove small amounts (~0.1% – ~0.2% of rock mass) of Fe and Al, and fines are invariably apparent in treatment fluids, both of which suggest removal of small amounts of trivalent Fe/Al colloids.
While these results suggest that non-reductive means may be used to remove artifacts introduced by core oxidation, they come with an important caveat: even rinsing with a brine solution can result in significant alteration of mineralogy. The use of chelating agents will invariably result in dissolution of any soluble minerals present such as gypsum or anhydrite, which can be an important contributor to surfactant (in particular ABS) consumption.
In cases where iron removal is necessary due to polymer degradation issues, PIPES buffer is proposed for use as an alternative to bicarbonate, the latter having a greater tendency for ligand formation. The combination of borohydride and bisulfite is suggested as an alternative to dithionite as a reducing agent, resulting in more complete iron removal under some conditions, and anecdotally less tendency for polymer degradation upon subsequent oxidation, though both of these claims should be verified.