Summary Foam generated in situ by surfactant-alternating-gas (SAG) injection is demonstrated as a substitute for polymer drive in the alkaline/surfactant/polymer (ASP) enhanced-oil-recovery (EOR) process. Foam is also effective in a similar process for a 266-cp crude oil, even though the system did not have enough polymer for favorable mobility control. Foam is shown to enhance sweep efficiency greatly in a layered sandpack with a 19:1 permeability ratio. Foam diverted surfactant solution from the high-permeability layer to the low-permeability layer. Ahead of the foam front, liquid in the low-permeability layer crossflowed into the high-permeability layer. A layered system with a 19:1 permeability contrast could be completely swept in 1.3 total pore volumes (TPV) with foam, while waterflood required 8 pore volumes (PV).

Summary Design of an alkaline/surfactant/polymer (ASP) process requires knowledge of the amount of soap formed under alkaline conditions from naphthenic acids in the crude oil. We show here for several crude oils that, when substantial acid is present, the acid number determined by nonaqueous-phase titration is approximately twice that found by hyamine titration of a highly alkaline aqueous phase used to extract soaps from the crude oil. This acid number by soap extraction should provide a better estimate than nonaqueous-phase titration because the extracted soap interacts with the injected surfactant to form surfactant films and microemulsion droplets during an ASP process. In a previous paper (Liu et al. 2008), an unusually wide range of salinities of ultralow oil/water interfacial tensions (IFTs) was found for one alcohol-free crude-oil/anionic-surfactant system under alkaline conditions where naphthenic soaps were present. Solubilization results indicate that this favorable behavior exists with the same surfactant blend and another crude oil. In the same paper, a 1D simulator for the ASP process was presented. Here, this ASP simulator has been used for various acid contents, injected-surfactant concentrations, slug sizes, and salinities to show that high recoveries of waterflood residual oil (> 90%) can be expected for a wide range of near-optimal (Winsor III) and underoptimum (Winsor I) conditions for a constant-salinity process, even with relatively small slug sizes. A key factor leading to this good performance is development of a gradient in soap/surfactant ratio, which ensures that a displacement front with ultralow IFT forms and propagates through the formation. Similar high recoveries can be attained for certain Winsor II conditions but only for much larger slug sizes, owing to the tendency for surfactant to partition into the oil phase and become retarded. Large dispersion, such as might be expected for field conditions, can reduce recovery significantly for small surfactant slugs even for near-optimal and underoptimum conditions. However, this problem can be overcome by injecting the slug or drive at salinities below reservoir salinity, thereby creating a salinity gradient.

Design of an alkaline-surfactant-polymer (ASP) process requires knowledge of the amount of soap formed under alkaline conditions from naphthenic acids in the crude oil. We show here for several crude oils that the acid number determined by nonaqueous phase titration is approximately twice that found by hyamine titration of a highly alkaline aqueous phase used to extract soaps from the crude oil. This acid number by soap extraction should provide a better estimate than nonaqueous phase titration. This soap interacts with the injected surfactant to form surfactant films and microemulsion droplets during an ASP process. In a previous paper (Liu et al., 2006), an unusually wide range of salinities of ultra-low oil-water interfacial tensions (IFTs) was found for one alcohol-free crude oil/anionic surfactant system under alkaline conditions where naphthenic soaps were present. This surprising and favorable behavior has now been found to exist with the same surfactant blend and another crude oil. In the same paper, a one-dimensional simulator for the ASP process was presented. Here this ASP simulator has been used for various acid contents, injected surfactant concentrations, slug sizes and salinities to show that high recoveries of waterflood residual oil (>90%) can be expected for a wide range of near-optimal (Winsor III) and under-optimum (Winsor I) conditions for a constant salinity process, even with relatively small slug sizes. A key factor leading to this good performance is development of a gradient in soap-to-surfactant ratio, which assures that a displacement front with ultralow IFT forms and propagates through the formation. Similar high recoveries can be attained for certain over-optimum (Winsor II) conditions but only for much larger slug sizes owing to the tendency for surfactant to partition into the oil phase and become retarded. Large dispersion such as might be expected for field conditions can significantly reduce recovery for small surfactant slugs even for near-optimal and under-optimum conditions. However, this problem can be overcome by injecting the slug and/or drive at salinities below reservoir salinity, thereby creating a salinity gradient. Introduction Alkaline-surfactant processes offer considerable promise for enhanced oil recovery (EOR). The alkali converts naphthenic acids in the crude oil to soaps. The combination of the soaps and a suitably chosen injected surfactant reduces interfacial tensions to ultralow values, where residual oil can be mobilized and oil trapping prevented. As discussed more fully in a previous paper (Liu et al, 2006), the alkali reduces surfactant adsorption. Soaps are usually too lipophilic to produce ultralow tensions at reservoir conditions. Effective, hydrophilic, injected surfactants can be injected in an alkaline-surfactant process at salinities below their optimal salinities for oil recovery when used in the absence of alkali (Nelson, et al., 1984). The result is to further reduce adsorption and to facilitate finding surfactant slug compositions where addition of polymer to provide adequate mobility control does not cause undesirable separation into polymer-rich and surfactant-rich phases. The drive is also a polymer solution, so that the process is of the alkaline-surfactant-polymer (ASP) type. Liu et al (2006) presented phase behavior, interfacial tensions (IFTs), adsorption isotherms, and results of ASP experiments in silica and dolomite sand packs for a system with a particular surfactant blend (NI blend) and a West Texas crude oil (Yates). The alkali was sodium carbonate, and all experiments were conducted at ambient temperature. A mixture of a propoxylated sulfate and an internal olefin sulfonate, the NI blend was used with no added alcohol or other cosolvent. It was a single-phase micellar solution for salinities up to approximately its optimal salinity with the crude when minimal soap is present, making it suitable for injection at lower salinities in an ASP process, as mentioned above.

Foam generated in situ by surfactant alternated with gas injection is demonstrated as a substitute for polymer drive in the alkaline-surfactant-polymer (ASP) EOR process. Foam is also effective in a similar process for a 266 cp crude oil, even though the system did not have enough polymer for favorable mobility control. Foam is shown to greatly enhance sweep efficiency in a layered sandpack with a 19:1 permeability ratio. Foam diverted surfactant solution from the high-permeability layer to the low-permeability layer. Ahead of the foam front, liquid in the low-permeability layer crossflowed into the high-permeability layer. A layered system with a 19:1 permeability contrast could be completely swept in 1.3 TPV (total pore volume) with foam while waterflooding required 8 PV (pore volume). Introduction Foam as a means for mobility control of surfactant flooding was introduced 28 years ago by Lawson and Reisberg (1980). This concept was not immediately adopted because of the lack of understanding of the mechanism of mobility control with foam. Since that time there have been many advances in the understanding of foam mobility control. There have been many field tests of steam foam (Hirasaki 1989; Patzek 1996) and CO2 foam. One of the most successful field demonstrations of foam mobility control was in the Snorre field (Blaker 2002). Foam was used as mobility control for surfactant aquifer remediation at Hill AFB in Utah (Hirasaki 1997, 2000). Foam was used as mobility control for alkaline surfactant flooding in China (Zhang 2000; Wang 2001). The most important advance in understanding that has made foam mobility control practical is the understanding of the condition necessary to generate "strong" foam. There is a critical pressure gradient that must be exceeded to generate strong foam during the flow of surfactant solution and gas through homogeneous porous media (Falls 1988; Gauglitz 2002; Kam 2003; Rossen 1996, 2007; Tanzil 2002a). Below this pressure gradient gas may flow as a continuous phase with only modest mobility reduction. Above this pressure gradient, stationary bubbles are mobilized such that bubble-trains have multiple branch points. A flowing bubble divides into two bubbles at each branch point and thus regenerates bubbles that are lost to coalescence. Foam bubbles can also be regenerated (independent of pressure gradient) when gas and surfactant solution flow across a step increase in permeability with a ratio greater than 4 (Falls 1988; Tanzil 2002a). If one recognizes the critical pressure gradient necessary for strong foam, experiments can be conducted at high enough flow rate or pressure-drop such that the critical pressure gradient is exceeded. The other important advance in understanding is the observation that when the foam is flowing with conditions where it is regenerated in situ, the gas mobility is determined by a "limiting capillary pressure" above which the lamellae become unstable and bubbles coalesce (Khatib 1988). This understanding explains why in this regime, the pressure gradient is a function of the liquid flow rate but independent of the gas flow rate. Also, foam mobility can be modeled by "fractional flow theory" in this flow regime (Gauglitz 2002; Rossen 1996). In this regime, gas mobility increases with increasing gas fractional flow and decreasing permeability. This permeability dependence makes foam especially useful for improving sweep in layered systems (Heller 1994; Bertin 1998; Kovscek 2002). The dependence of foam mobility on fracture aperture has been demonstrated to be beneficial in the sweep of fracture systems (Yan 2006).

In a layered 2-D heterogeneous sandpack with 19:1 permeability contrast that was preferentially oil-wet, the recovery by waterflood was only 49.1% of original oil-in-place (OOIP) due to injected water flowing through high-permeability zone leaving low-permeability zone unswept. In order to enhance oil recovery, an anionic surfactant blend (NI) was injected that altered the wettability and lowered the interfacial tension (IFT) and consequently enabled gravity and capillary pressure driven vertical counter-current flow to occur and exchange fluids between high- and low-permeability zones during a 42-day system shut-in. Cumulative recovery after a subsequent foamflood was 94.6% OOIP even though foam strength was weak. Recovery with chemical flood (incremental-recovered-oil/waterflood-remaining-oil) was 89.4%. An alternative method is to apply foam mobility control as a robust viscous force dominant process with no initial surfactant injection and shut-in. The light crude oil studied in this paper was extremely detrimental for foam generation. However, the addition of lauryl betaine to NI at a weight ratio of 1:2 (NI: lauryl betaine), made the new NIB blend a good foaming agent with and without the presence of the crude oil. NIB by itself as an IFT reducing and foaming agent is shown to be effective in various secondary and tertiary alkaline/surfactant/foam (ASF) processes in water-wet 1-D homogeneous sandpacks, and in an oil-wet, heterogeneous layered system with 34:1 permeability ratio.