Plugging of High Permeability - Fractured Zones Using Emulsions

Abstract

Low crude oil sweep efficiency may be the result of channeling of injected water through high permeability sands in heterogeneous reservoirs. In these cases the efforts have been focused in improving the distribution of injected water in the wellbore through treatments using cements, gelling agents, and other short radius plugging materials. It has been proven that such treatments contribute to a better water distribution in the formation around the wellbore However, they are unlikely to be completely successful because, deeper in the formation, the fluid may divert. Laboratory and field studies have suggested that oil-in-water emulsions can be used to obtain a deeper formation plugging and this results in better sweep efficiency and a greater oil recovery. However, the suitability of this method for fractured formations remains relatively unknown. This paper presents the second phase of a three-phase study. The first phase consisted at the formulation of a heavy oil-in-water emulsion. Alkaline solutions were used as emulsifier agents. Parameters such as alkaline solution type and concentration, oil/water ratio, and shear rate were optimized in order to obtain a stable emulsion with an average drop diameter of 3 m. The second phase comprises the laboratory evaluation of the plugging effectiveness of the emulsion. The third phase will address the development of a field-pilot test. In order to accomplish the second phase objective, coreflood experiments were conducted at 80 C, with a confining pressure of 3000 psi and an injection pressure of 1000 psi. Various types of cores were used, including some with a longitudinal fracture. It was observed that an undesired breakdown of the emulsion generates plugging at the core injection inlet. A flush with an alkaline conditioner is required to minimize the breaking of the emulsion before it enters the cores. This preflush has no effect on the core permeability. Externally produced emulsions injected into the cores after the pre-flush with the alkaline conditioner reduced the permeability up to 80%. No time degradation on the emulsion plug was observed even after 27 PV of water injected. Introduction A number of studies has proved that oil-in-water (o/w) emulsion can cause permeability reduction. McAuliffe postulated and tested in parallel cores experiments that o/w emulsions would enter the most permeable layers of the reservoirs, where it is trapped. The trapped emulsion creates enough blockage for the water injected afterwards, resulting in a diversion process the improves the overall oil recovery. Considering an initial situation where three oil bearing layers (A, B and C) are waterflooded If one of these three layers (A) has higher permeability than the other two, most of the injected water should flow through it sweeping the oil, but leaving the other two layers (B and C) unswept. After the blockage of layer A with an emulsion, layers B and C can be swept, increasing the recovery of oil. The only field pilot test of this process was conducted in the Midway Sunset field, California. P. 611

Effects of compositional variations on CO2foam under miscible conditions

“…From a practical point of view, this high‐apparent viscosity at this low velocity can be unfavorable because it can damage the injectivity. This may result in low injection rates for a certain drawdown pressure . In general, all molar compositional fractions of miscible CO 2 ‐C 10 mixture exhibit shear‐thinning behavior, because the apparent viscosity decreases by increasing the velocity.…”

An experimental investigation on enhancing water flooding performance using oil-in-water emulsions in an Iranian oil reservoir

“…Romero et al studied on the effect of fracture plugging of in situ O/W emulsions by injection of an optimum amount of water/oil ratio in sandpacks and observed a massive reduction of 90% in water relative permeability as well as injectivity. This matter even was more evident in the initial part of their model (Romero et al 1996). According to Starvland et al (2006), the amount of this permeability reduction varies from zone to zones, with regard to the fluids saturations.…”

“…They created an emulsion with a high percentage of water content and introduced it in one of the oil reservoirs in the North Sea to diminish water cut up to 30% in their oilfield study (Bai et al 2000). Furthermore, the other advantages of O/W of emulsion flooding are its accessibility and lower cost of transportation as well as its more in-depth coverage into the formation and so its undemanding injectivity (Hasan et al 2010;Kumar and Mahto 2016;Mcauliffe 1973a, b;Romero et al 1996;Yu et al 2018). Romero et al studied on the effect of fracture plugging of in situ O/W emulsions by injection of an optimum amount of water/oil ratio in sandpacks and observed a massive reduction of 90% in water relative permeability as well as injectivity.…”

“…Typically, using one or several surface active agents play a significant role in the formation of stable emulsions. In Romero et al (1996), experiments emulsions had been formed as a result of alkaline injection. Torrealba and Hoteit observed the in situ generation of thermodynamically stable microemulsions in their reservoir model based on the injection of cyclical surfactant slugs after mixing with existed oil in the reservoir using a chemical flooding simulator (UTCHEM 2000).…”

Investigation of synergy between nanoparticle and surfactant in stabilizing oil-in-water emulsions for improved heavy oil recovery

“…Both the conditions lead to improved sweep efficiency after water flooding. Previous studies have shown that emulsions could be used to increase water viscosity, decreasing mobility ratios resulting in a more efficient oil recovery [10][11][12][13][14][15]. Recent studies on the recovery of heavy oils by emulsion flooding have shown good potential for this recovery process in conjunction with water flooding [16][17][18].…”