Surfactant-polymer flooding injected

Careful sizing of the treatment and choice of injection rates is required to prevent inadvertent overtreatment i.e., excessive treatment of oil-containing rock. The post-treatment fluid injection rate is usually significantly less than that prior to treatment. While successful applications of this technology in waterfloods and in surfactant polymer floods have been reported, temperature and pH stability limitations of the polymer and the crosslinking chemistry result in few if any applications in steam and CO2 injection wells. 

Micellar-polymer flooding and alkali-surfactant-polymer flooding both rely on the injection into a crude-oil reservoir of surfactants or surfactantforming materials. Emulsions may be injected into the reservoir, or they may be formed in the reservoir, but their properties will change as they travel through the reservoir to eventually flow from a producing well after weeks or months. 

It was observed that the formulations consisting of ethoxylated sulfonates and petroleum sulfonates are relatively insensitive to divalent cations. The results show that a minimum in coalescence rate, interfacial tension, surfactant loss, apparent viscosity and a maximum in oil recovery are observed at the optimal salinity of the system. The flattening rate of an oil drop in a surfactant formulation increases strikingly in the presence of alcohol. It appears that the addition of alcohol promotes the mass transfer of surfactant from the aqueous phase to the interface. The addition of alcohol also promotes the coalescence of oil drops, presumably due to a decrease in the interfacial viscosity. Some novel concepts such as surfactant-polymer incompatibility, injection of an oil bank and demulsification to promote oil recovery have been discussed for surfactant flooding processes. 

Surfactant-polymer flooding involves successive injections into the reservoir of an aqueous surfactant-cosurfactant solution and a dilute aqueous solution of a high molecular weight polymer. The primary purpose of the surfactant slug is to reduce the interfacial... 

Typical EOR surfactant-polymer flooding operations include a sequence of slugs (see Fig. 10.3) that are injected into an oil reservoir [109, 113, 114, 119]. The main idea is to wrap up a process to recover most of the oil still in place (at least much more than what waterflooding does) by preserving at the correct level the main characteristics and functions of the different slugs, particularly the surfactant one, as they pass through the reservoir from the injector to the producer wells. Some of the typical slugs and their main features are described below. 

Figure 2 Two-dimensional view of the surfactant-polymer flooding process. Injection of a surfactant solution to coalesce the oil ganglia is followed by injection of a polymer slug to push the oil to production wells.

Laboratory studies on oil displacement efficiency by surfactant-polymer flooding process have been reported by a number of investigators (1-10). In general, the process is such that after being conditioned by field brine or preflush, a sandstone core or a sandpack is oil-saturated to the irreducible water content. It is then waterflooded to the residual oil level. Finally, a slug of surfactant solution followed by a mobility buffer is injected. 

These different enhanced oil recovery methods become even more involved when the combination of two or more different techniques is used, for example, when CO2 injection is combined with surfactant-polymer flooding. A simple schematic correlation has been found between the EOR method and the depth of the reservoir and oil viscosity (Figure 12.4). Obviously, in such a complex system no simple correlation can be absolutely valid, but it can be a useful guideline. Field operations have provided evidence for a good relation as depicted in Figure 12.4. 

An alternative to this process is low (<10 N/m (10 dynes /cm)) tension polymer flooding where lower concentrations of surfactant are used compared to micellar polymer flooding. Chemical adsorption is reduced compared to micellar polymer flooding. Increases in oil production compared to waterflooding have been observed in laboratory tests. The physical chemistry of this process has been reviewed (247). Among the surfactants used in this process are alcohol propoxyethoxy sulfonates, the stmcture of which can be adjusted to the salinity of the injection water (248). 

Surfactants evaluated in surfactant-enhanced alkaline flooding include internal olefin sulfonates (259,261), linear alkyl xylene sulfonates (262), petroleum sulfonates (262), alcohol ethoxysulfates (258,261,263), and alcohol ethoxylates/anionic surfactants (257). Water-thickening polymers, either xanthan or polyacrylamide, can reduce injected fluid mobiHty in alkaline flooding (264) and surfactant-enhanced alkaline flooding (259,263). The combined use of alkah, surfactant, and water-thickening polymer has been termed the alkaH—surfactant—polymer (ASP) process. Cross-linked polymers have been used to increase volumetric sweep efficiency of surfactant—polymer—alkaline agent formulations (265). 

Chemical EOR methods are based on the injection of chemicals to develop fluid or interfacial properties that favor oil production. The three most common of these methods are polymer flooding, alkaline flooding, and surfactant flooding. 

Both nonionic and anionic surfactants have been evaluated in this application (488,489) including internal olefin sulfonates (487, 490), linear alkylxylene sulfonates (490), petroleum sulfonates (491), alcohol ethoxysulfates (487,489,492). Ethoxylated alcohols have been added to some anionic surfactant formulations to improve interfacial properties (486). The use of water thickening polymers, either xanthan or polyacrylamide to reduce injected fluid mobility mobility has been proposed for both alkaline flooding (493) and surfactant enhanced alkaline flooding (492). Crosslinked polymers have been used to increase volumetric sweep efficiency of surfactant - polymer - alkaline agent formulations (493). 

Micellar-polymer flooding relies on the injection of a surfactant solution to lower interfacial tension to ultralow levels, on the order of 10 mN/m. The resulting increase in capillary number allows the recovery of residual oil from porous media. The term micellar is used because the concentrations of injected surfactant solutions are always above their critical micelle concentration. That is, they are always above the concentration at which micelles form. 

Theories of surfactant flooding and polymer flooding are discussed in Chapters 5 to 7. This chapter focuses on surfactant-polymer (SP) interactions and compatibility. Optimization of surfactant-polymer injection schemes is also discussed. The methodology and even some conclusions in the presented optimization may be applied to other processes as well. Finally, this chapter presents a field example. 

During a polymer flood, because of polymer adsorption, a polymer denuded zone forms at the front of polymer slug. If a surfactant slug is injected ahead of a polymer slug, however, adsorption sites are occupied by surfactant. In some cases, polymer loss is reduced to an insignificant level owing to the so-called competitive adsorption, discussed earlier. Thus, a polymer denuded zone may... 

In this section, simulation results are compared with the information from the literature for different polymer and surfactant-polymer injection schemes. We expect that UTCHEM simulation of a core-scale chemical process is the best simulation approach to study mechanisms. In this study, we use a ID core flood model with 100 blocks to represent a 1-foot-long core. The permeability is 2000 md, and the water and oil viscosities are 1 and 2 mPa s, respectively. To optimize injection schemes, we compare the incremental oil recovery factors over waterflooding and chemical costs. Chemical costs are evaluated using the amounts of chemicals injected per barrel of incremental oil (Ib/bbl oil). 

Core flood tests were conducted to compare the performance from the surfactant-polymer option and polymer injection option at different injection schemes. The formula selected for use in the core flood was 0.3 wt.% SLPS -F 0.1 wt.% cosurfactant + 1500 mg/L HPAM. For this formula, the chemical cost was about 2.6/bbl incremental oil. The final selected injection scheme in the pilot is presented in Table 9.4. According to this scheme, the... 

Although alkaline flooding only is not conducted as often as polymer flooding or surfactant flooding, alkaline injection is conducted together with surfactant and polymer injection. Simulation of alkaline flooding is very difficult because of complex chemical reactions. These complex reactions include at least the following ... 

When alkaline flooding is combined with other methods, such as polymer flooding, surfactant flooding, hydrocarbon gas injection, or thermal recovery, much better effects will be obtained. 

Synergy is discussed in previous chapters. Here, we provide extra evidence to demonstrate the synergy in ASP. Core samples were waterflooded to residual oil saturation and then injected with polymer, alkaline-polymer (AP), or ASP. The results, in Table 13.1 (Ball and Surkalo, 1988), show that adding alkali further reduced residual oil saturation by 0.137, compared with polymer flooding. Through the further addition of only 0.1 wt.% surfactant, an additional 0.136 residual oil saturation was reduced. In these samples, ASP was the most efficient approach, demonstrating the synergy of alkali, surfactant, and polymer floods. 

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