Although surfactant generated CO2 foam improves the mobility control for CO2 flooding, it suffers from instability in the presence of crude oil and in high salinity environments. The objective of this work is to improve the stability of the interface by lowering surfactant drainage and improving the stability of lamellae in high salinity produced water using polyelectrolyte complex nanoparticles and generate a more stable foam front in the presence of crude oil. This results in improving the recovery efficiency of foam floods.
In this project, an optimized system of polyelectrolyte complex nanoparticles was used to improve scCO2 foams prepared in high salinity produced water. The effect of nanoparticles on the interfacial properties of the foam was studied. Thereafter, a set of core flooding experiments with and without the crude oil in the system was conducted to measure the apparent viscosity and the incremental oil recovery due to addition of polyelectrolyte and polyelectrolyte complex nanoparticles to the surfactant generated CO2 foam in high salinity produced water.
Studying the interfacial properties of different foam systems shows that addition of polyelectrolytes and polyelectrolyte complex nanoparticles to the surfactant generated CO2 foam improves the elasticity of the interface. Furthermore, adding polyelectrolytes and polyelectrolyte complex nanoparticles to the surfactant generated CO2 foam, improves the efficiency of the oil recovery by improving the apparent viscosity and making the foam more stable in the presence of crude oil. Polyelectrolyte complex nanoparticles produced incremental oil when the surfactant foam system reached its residual oil and produced no more oil.
Generating a very stable system of the foam by adding polyelectrolyte complex nanoparticles to the surfactant generated CO2 foam prepared in high salinity produced water, results in a longer lasting foam and increase the incremental oil recovery up to 10%. The sea water salinity is applicable for all the locations with access to the sea water as well as locations with produced water salinities close to sea water. The higher salinity system covers a wide range of the reservoirs in the United States and worldwide with access to produced water.
Unomah, Michael (Chevron Energy Technology Company) | Thach, Sophany (Chevron Energy Technology Company) | Shong, Robert (Chevron Energy Technology Company) | App, Jeff (Chevron Energy Technology Company) | Zhang, Tiantian (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Permeability reduction provided by conventional polymer gels is affected by harsh reservoir conditions. Harsh conditions are defined by high temperature (> 75°C), high salinity, high divalent ions and the presence of H2S. Polymer gels undergo syneresis when exposed to high salinity and hardness reservoir brines. We evaluated conventional polyacrylamide-based polymer (HPAM)-gels and other modified HPAM-gels with molecular weights between 2-20MM Daltons for gelation time and long-term gel stability under harsh conditions. In addition to polymer degradation, the cross-linkers are also sensitive to harsh reservoir conditions. Specifically, H2S can consume cross-linkers and inhibit gelation. The cross-linkers tested were Chromium (III) Acetate and Chevron Unogel formulation consisting of a combination of hexamethylenetetramine (HMTA) and hydroquinone (HQ). High performing gels were tested for sensitivity to high salinity brines and H2S in a limited number of experiments. The gels were observed for gel strength, and syneresis with time. The goal of our work was to identify a combination of polymer and cross-linker that would provide effective conformance under harsh conditions.
Sulfonated polyacrylamide (ATBS) polymers were found to provide better resistance to high salinity/hardness brines than partially hydrolyzed polyacrylamides in high temperature conditions. The addition of hydrophobic groups to the sulfonated-acrylamide backbone does not increase the hardness tolerance of the polymer. Higher concentration, low molecular weight sulfonated polymers are recommended for use at high temperature and salinity. Polymer gels made with 2MM Dalton polymer show less syneresis with time compared to higher molecular weight polymer at the same polymer concentration. HMTA/HQ ATBS polymer gels are preferable to chromium (III) ATBS polymer gel for high temperature and salinity conditions. Chromium (III) ATBS polymer gels show more susceptibility to syneresis compared to organic crosslinked gels at same polymer concentration. HMTA/HQ crosslinker is ineffective in the presence of hydrogen sulfide. Gelants consisting of HMTA/HQ do not mature into rigid gels after 14 days of exposure to sour gas. Preformed HMTA/HQ gels lose strength upon exposure to sour crude. This is mostly due to HMTA ability as a sour gas/crude sweetener. Chromium (III) gels form weak gels in the presence of sour gas. Chromium competes with sulfide ions to produce insoluble chromium sulfide leading to consumption of crosslinker and poor gelation. Malonate and tartrate are effective gel retardants for chromium (III) polymer gels. Malonate is better at extending onset of gelation for longer periods of time. Tartrate is more effective for shorter gelation time at lower concentrations.
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.