In hydrocarbon reservoirs, we typically encounter a brine phase and at least one hydrocarbon phase. Because of their dissimilarities, the flow of hydrocarbon phases is hindered by the presence of brine. The interfacial tension between brine and oil is typically high (50 mN/m for some systems), which results in unfavorable relative permeabilities and high residual oil saturation.
Background
The oil and gas industry has been fascinated by surfactants since their understanding began to emerge in the early 1950s. Surfactants are compounds that display a dual nature, with affinity to both brine and hydrocarbon phases. In the presence of brine and oil, surfactants will position at the interface to form a molecular bridge between the brine and hydrocarbons, which then lowers the interfacial tension to near zero values (<10-3 mN/m). This is equivalent to saying the phases behave as almost fully miscible. This clearly changes the relative permeability toward a more favorable state, and yields low residual oil saturation. Also, when the surfactant concentration is high enough a third phase (called a microemulsion) forms. This phase contains domains of oil and brine that are separated by surfactant layers of varying shapes. Because the phase is in thermodynamic equilibrium, the oil and water do not separate with time.
In simple terms, field-scale oil recovery from injection processes is typically assumed to be the product of two efficiencies. The first one (arguably, the most important) is sweep efficiency, which accounts for the fraction of oil the injection fluid is able to reach compared to the total oil in place. The second is displacement efficiency, which accounts for the fraction of oil the injection fluid is able to mobilize compared to the total reached oil.
When people hear surfactant research, most likely they think of surfactant flooding, which is generally used to refer to both surfactant-polymer (SP) or alkaline-surfactant-polymer (ASP). The alkaline addition is considered for cases where the oil has acidic components that may react with the injected base to form natural surfactants in the reservoir, which can then lower the surfactant requirements for the process. The S or AS part of the process involves the injection of small slugs of these chemicals in order to lower interfacial tensions, and then improve on the displacement efficiency. The S or AS slug is trailed with a longer polymer slug, which is used to viscosify the injected water and improve the sweep efficiency. In some cases, polymer is also considered for the S or AS slug. The technology has been tested at the pilot scale in many reservoirs worldwide, generally with clear evidence of oil recovery enhancement over conventional means.
What’s Next for Conformance?
Now that we have covered the typical application of surfactants, we can focus on other emerging areas of surfactant applications to the oil and gas industry. Recently, surfactants have been proposed as conformance improvement agents to treat injector-producer pairs with poor sweep efficiency due to the presence of fractures or thief zones (Torrealba and Hoteit 2018). The technology relies on the fact that the rheological response of surfactant solutions and microemulsions can be tuned, for example, by the injection salinity. Therefore, a small surfactant slug is initially injected at a salinity corresponding to low viscosity in order to maintain high injectivity. Once the surfactant has invaded the target zone, a brine slug is injected at a salinity corresponding to high viscosity. This will increase the viscosity of the resulting microemulsion, and will result in flow diversion to the previously unswept regions. This technology has clear benefits compared to alternative treatments where there is risk of plugging, the injection viscosity being high, and the durability short-lived.
Application for Unconventionals
With the boom of unconventionals in the US, there are clear opportunities for surfactant applications to aid in improving the efficiency of the exploitation of these resources. Viscoelastic surfactants have found their way as an alternative for hydraulic fracturing and wellbore stimulation. In many places where water is scarce, finding an alternative fracturing fluid to water has been key. Supercritical CO2 has properties that would make it an ideal candidate, only if its viscosity was not so low. The use of surfactants for foam, or even CO2-based microemulsions can be the solution to increase the viscosity of CO2 and make it a viable alternative to water (Janes et al. 2014). Recently, a lot of work has been devoted to modifying the wettability characteristics of shale rocks by the use of surfactants, which make be the key to pushing oil recovery in the US as production matures.
Regardless of the application, surfactants continue to amaze people in the oil and gas industry. One common denominator for all technologies (both surfactant and non-surfactant based) is that the most important lessons learned come from the field. Therefore, deploying lower-risk surfactant technologies to the field may help us in understanding surfactant behavior, and allow us to gain confidence for more challenging applications in the future. Derisking is the key.
References
James, C., Hatzopoulos, M.H., Yan, C., Smith, G.N., Alexander, S., Rogers, S.E. and Eastoe, J., 2014. Shape Transitions in Supercritical CO2 Microemulsions Induced by Hydrotropes. Langmuir, 30(1), pp.96–102.
Torrealba, V.A., Hoteit, H., 2018. Conformance Improvement in Oil Reservoirs by Use of Microemulsions. SPE Reservoir Evaluation and Engineering, Preprint.
