Crude oil development and production can include up to three distinct phases: primary, secondary, and tertiary (or enhanced) recovery. During primary recovery, the natural pressure of the reservoir or gravity drives oil into the wellbore, combined with artificial lift techniques (such as pumps) which bring the oil to the surface. But only about 10 percent of a reservoir's original oil in place is typically produced during primary recovery. Secondary recovery techniques extend a field's productive life generally by injecting water or gas to displace oil and drive it to a production wellbore, resulting in the recovery of 20 to 40 percent of the original oil in place.
Enhanced oil recovery, or EOR, is a generic term encompassing techniques for increasing the amount of crude oil that can be extracted from a subterranean formation such as an oil field. EOR techniques offer prospects for ultimately producing 30 to 60 percent, or more, of the reservoir's original oil in place. Three major categories of EOR have been found to be commercially successful to varying degrees:
Thermal recovery is the introduction of heat such as the injection of steam to lower the viscosity of the oil and improve its ability to flow through the reservoir.
Gas injection is the injection of gases such as natural gas, nitrogen, or carbon dioxide that expand in a reservoir to push additional oil to a production wellbore, or gases that dissolve in the oil to lower its viscosity and improve flow rate.
Chemical injection is the injection of polymer dispersions to increase the effectiveness of waterfloods, or the use of detergent-like surfactants to help lower the surface tension that often prevents oil droplets from moving through a reservoir. Chemical injection of a polymer is also referred to as polymer flooding. This method improves the vertical and areal sweep efficiency as a consequence of improving the water/oil mobility ratio. In addition, the polymer reduces the contrasts in permeability by preferentially plugging the high permeability zones flooded. This forces the water to flood the lower permeability zones and increases the sweep efficiency. The art in this area is well-developed for conventional oil recovery applications.
Of these techniques, polymer flooding using water-in-oil (w/o) latex products is particularly favored for use in offshore reservoirs and other relatively isolated operations due to the ease of use and relatively simple equipment requirements. Polymer flooding is generally accomplished by dissolving the selected polymer in water and injecting the polymer solution into the reservoir. However, since the target concentration of polymer in the polymer dispersions is typically about 1 wt % or less, transport at the target concentration is not economically efficient. Transporting the dried polymers, while economically efficient for the supplier, is not favorable for field use due to limited space for dry polymer make-down equipment and difficulties in fully hydrating the polymers in the field. To address these issues, various formulations have been developed to allow economically feasible transportation and storage. Specialized methods have also been developed to convert the formulations to use concentrations of fully hydrated polymers in the field.
Organic polymers traditionally used in EOR include water soluble polymers such as polyacrylamide homopolymers and copolymers with acrylic acid or conjugate base thereof and/or one or more other water soluble monomers, and hydrophobically modified water soluble polymers, also called associative polymers or associative thickeners. Associative thickeners are typically copolymers of acrylamide, acrylic acid, or both with about 1 mole % or less of a hydrophobic monomer such as a C8-C16 linear or branched ester of acrylic acid. Any of these water soluble polymers are deliverable as a dry powder, as a gel-like concentrate in water, or in the water phase of a w/o latex. Of these formats, water-in-oil latices have the advantage of being deliverable in a liquid format that is easily handled in the field because the latex viscosity is lower than that of a water solution of comparable wt % polymer. The liquid products are also easy to make down with little equipment and a small space footprint compared to that of dry polymer products.
Commercial w/o latices are formulated for EOR by dissolving monomer(s) in a high-solids aqueous solution to form a water phase (or monomer phase), mixing one or more hydrocarbon solvents and a surfactant or a blend thereof having a hydrophilic-lipophilic balance (HLB) of about 2 to 10 to form an oil phase, mixing the two phases using techniques to result in a water-in-oil emulsion or latex, and polymerizing the monomer via a standard free-radical initiation. The w/o latex may be a macroemulsion, nanoemulsion, microemulsion, or combination thereof. The free radical initiation may be radiation, photo, thermal, or redox initiation, or any combination thereof. After polymerization is complete, a higher HLB surfactant (HLB>10) or a blend thereof having an HLB>10 is often added to facilitate latex inversion when water is added. “Inversion” is a term of art to describe the dilution of w/o latices with a water source, causing destabilization of the latex and subsequent dissolution of the concentrated polymer particles. In some cases, the higher HLB surfactant is added in the field, immediately prior to addition of water to dilute the latex; or is added in-line with the water source used to dilute the latex. In other cases, the higher HLB surfactant is added directly to the w/o latex after polymerization is complete, and the latex is stable or even shelf stable. In such cases, careful control of type and amount of surfactant is required to provide a sufficiently stable latex to facilitate storage and transportation, while providing for improved inversion performance in the field.
Recently, there has arisen the need to address polymer flooding in challenging conditions encountered in reservoirs wherein the ambient or produced water contacted by the polymer includes high total dissolved solids, such as a high saline or hardness content, in some cases involving total dissolved solids of up to about 30 wt %. In some cases the ambient or produced water is tap water, hard water, brackish water, municipal waste water, produced water, or seawater. Field operators strongly prefer to use such water sources to dilute polymer flooding formulations to final use concentrations rather than employ purified water sources. Reasons for the preference include reducing costs by diverting some or all of the water source already being injected into a reservoir to dilute the polymer flooding formulations and reducing the environmental impact associated with employing a purified water source. However, use of such water sources leads to difficulties in dispersing the high molecular weight polymers to use concentrations. Inversion of w/o latices in such water sources can result in slow inversion times and/or the requirement of multistage dilution and mixing procedures; it can also result in coagulation, precipitation, or gross phase separation of polymer upon or after contact of the latex with the diluted water environment. Thus there is a need to address inversion of w/o latices in field conditions where the use water source has high total dissolved solids.
Another need in the industry is to address reservoirs where the water source contacted by a w/o latex is at an extreme temperature, such as 30° C. to 100° C. or −10° C. to 10° C. Extreme temperature water sources lead to difficulties in dispersing high molecular weight, water soluble polymers delivered in w/o latices, similarly to the difficulties encountered in the use of high total dissolved solids water sources. In some cases, conditions of both extreme temperature and high total dissolved solids are encountered in the ambient or produced water source employed to dilute polymer flooding formulations to use concentrations. Such conditions cause instability of w/o latices during inversion, evidenced by formation of gel particles, coagulum, polymer coated out on contact surfaces, and gross coalescence of phases (conventionally referred to as “separation”) and the like. The products of this instability cause plugged equipment in the field, reduced reservoir permeability, plugged formation, and ultimately failure to accomplish mobility control within the reservoir. These problems remain largely unaddressed by conventional formulations, methods, and equipment developed for inversion of w/o latices in the field. For example, formulations described in US Patent Application Publication No. 2014/0051620 A1, which comprise an inversion agent such as glycerol, do not provide satisfactory performance under conditions using water sources having high total dissolved solids, extreme temperature, or both.
As a result, there is a substantial need in the industry to develop technologies suitable for carrying out enhanced oil recovery in reservoirs where high temperature water sources, high total dissolved solids water sources, or both are used in conjunction with EOR. There is a substantial need in the industry for w/o polymer latices that invert rapidly to form stable, fully hydrated or dissolved polymer solutions at water temperatures of 30° C. to 100° C. There is a substantial need in the industry for w/o polymer latices that invert rapidly to form stable, fully hydrated or dissolved polymer solutions using water sources having up to 30 wt % total dissolved solids. There is a substantial need in the industry for w/o polymer latices that invert rapidly to form stable, fully hydrated or dissolved polymer solutions at polymer concentrations of 1 wt % or less using water sources having high total dissolved solids, high temperature, or both.
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