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.
Research has discovered systems that can selectively flocculate mineral solids from a high molecular weight polymer flood matrix while leaving the polymer intact or alternatively achieving a viable total flocculation of the polymer in the produced fluids. Modified alkaline surfactant polymer (ASP) and standard polymer (P) flood systems were studied with findings obtained by controlled variations of both well-proven and non-prevalent chemical approaches. Results concluded that selectively removing the mineral solids from polymer-laden water produces reusable enhanced oil recovery (EOR) fluid.
EOR is a proven method to increase hydrocarbon yield from post-natural, stimulated, or standard flood driven reservoirs. Fluid produced from the reservoir contains the desired hydrocarbon and an aqueous phase. Previously considered a liability, properly treated, the aqueous phase can become an asset. Polymer floods have a proven history in EOR and, though complex in application, ASP also demonstrated EOR effectiveness in the laboratory. Most ASP approaches are currently in field trial stages. The produced fluid is subjected to hydrocarbon separation with the resulting aqueous system either treated for disposal or recycled into the system. The aqueous phase matrix is mainly composed of high molecular weight polymer, mineral solids, residual base, residual oil, and possibly surfactant. If the producer chooses disposal, the solids must be flocculated by a method balancing density, dewaterability, processability, process variability, and cost. However, if the producer opts to recycle the fluid for reinjection, steps must be taken to minimize polymer deviations requiring selective flocculation of all components with exception of the polymer. This undertaking is challenging as EOR polymers are also effective flocculants, therefore sensitive to standard coagulant and flocculant approaches. Utilizing controlled, standard methods and multivariable design of experiments, results were obtained for both total and selective flocculation.
Total flocculation systematically studies the influence of pH, inorganic, and organic coagulants in maximizing the treatment effectiveness. The same approach was successful for selective flocculation, however unique coagulants were applied. The selective flocculation process coagulated and separated the mineral solids, and left the high molecular weight polymer intact and the fluid matrix as viscous as prior to treatment. Effectiveness of treatments were determined using standard gravimetric and viscometric methods.
These discoveries will assist decision makers in determining whether total or selective flocculation is the most viable treatment for polymer based EOR, balancing environmental and economic aspects to pursue a desired treatment route. These methods, though targeting EOR, have practical applications for treatment of flowback and water produced from stimulation and potentially drilling operations as well.
Fracturing fluids are commonly formulated with fresh water to ensure reliable rheology. However, fresh water is becoming more costly, and in some areas, it is difficult to obtain. Therefore, using produced water in hydraulic fracturing has received increased attention in the last few years. A major challenge, however, is its high total dissolved solids (TDS) content, which could cause formation damage and negatively affect fracturing fluid rheology. The objective of this study is to investigate the feasibility of using produced water to formulate crosslinked-gel-based fracturing fluid. This paper focuses on the compatibility of water with the fracturing fluid system and the effect of salts on the fluid rheology.
Produced water samples were analyzed to determine different ion concentrations. Solutions of synthetic water with different amounts of salts were prepared. The fracturing fluid system consisted of natural guar polymer, borate-based crosslinker, biocide, surfactant, clay controller, scale inhibitor, and pH buffer. Compatibility tests of the fluid system were conducted at different cation concentrations. Apparent viscosity of the fracturing fluid was measured using a high-pressure high-temperature rotational rheometer. All rheology tests were conducted at a temperature of 180°F and were conducted according to API 13m procedure with a three-hour test duration. Fluid breaking test was also performed to ensure high fracture and proppant pack conductivity.
Produced water analysis showed a TDS content of 125,000 ppm, including Na, Ca, K, and Mg ion concentrations of 36,000, 10,500, 1,700, and 700 ppm, respectively. Results indicated the potential of produced water to cause formation damage. Therefore, produced water was diluted with fresh water and directly used to formulate the fracturing fluid. Divalent cations were found to be the main source of precipitation, and the reduced amounts of each ion were determined to prevent precipitation. The separate and combined effects of Na, K, Ca, and Mg ions on the viscosity of the fracturing fluid were also studied. Fluid viscosity was found to be significantly affected by the concentrations of divalent cations regardless of the concentrations of monovalent cations. Monovalent cations reduced the viscosity of fracturing fluid only in the absence of divalent cations, and showed no effect in the presence of Ca and Mg ions. Water with reduced concentrations of monovalent and divalent cations showed the most suitable environment for polymer hydration and crosslinking.
This paper contributes to the understanding of the main factors that enable the use of produced water for hydraulic fracturing operations. Maximizing the use of produced water could reduce its disposal costs, mitigate environmental impacts, and solve fresh water acquisition challenges.