Surfactant flooding alkali

To develop improved alkali-surfactant flooding methods, several different injection strategies were tested for recovering heavy oils. Oil recovery was compared for four different injection strategies [641] ... 

Alkali/polymer flooding Alkali/surfactant/polymer flooding Alkaline-assisted thermal oil recovery Alkaline steamflooding Polymer-assisted surfactant flooding Water-alternating gas technology... 

A fundamental chemical process is surfactant flooding in which the key mechanism is to reduce interfacial tension (IFT) between oil and the displacing fluid. The mechanism, because of the reduced IFT, is associated with the increased capillary number, which is a dimensionless ratio of viscous-to-local capillary forces. Experimental data show that as the capillary number increases, the residual oil saturation decreases (Lake, 1989). Therefore, as IFT is reduced through the addition of surfactants, the ultimate oil recovery is increased. In alkaline flooding, the surfactant required to reduce IFT is generated in situ by the chemical reaction between injected alkali and naphthenic acids in the... 

Alkaline flooding is also called caustic flooding. Alkalis used for in situ formation of surfactants include sodium hydroxide, sodium carbonate, sodium orthosilicate, sodium tripolyphosphate, sodium metaborate, ammonium hydroxide, and ammonium carbonate. In the past, the first two were used most often. However, owing to the emulsion and scaling problems observed in Chinese field applications, the tendency now is not to use sodium hydroxide. The dissociation of an alkali results in high pH. For example, NaOH dissociates to yield OH" ... 

For oil displacement purposes, alkali can be co-injected with any displacing agents except an acid or carbon dioxide. For example, aUcaline-polymer (AP), alkaline-surfactant (AS), aUcaline-gas, alkaline-steam, aUcaline-hot water, and more can be used. This chapter discusses alkaline-surfactant flooding. 

Phase behavior tests performed in glass sample tubes (pipettes) for the alkaline-surfactant process include aqueous tests, a salinity scan (alkalinity scan), and an oil scan. The aqueous tests and salinity scan are the same as those for surfactant flooding. For the sahnity scan in AS or alkaline-surfactant-polymer (ASP) cases, alkali also works as salt. There are two ways to change salinity. One is to change the salt content while fixing the alkali content the other is to change the alkali content while fixing the salt content. Therefore, the salinity... 

Bryan, J., Kantzas, A., 2007. Enhanced heavy-oil recovery by alkali-surfactant flooding. Paper SPE 110738 presented at the SPE Annual Technical Conference and Exhibition, Anaheim, 11-14 November. 

If the polymer technology can be successfully applied in the East Bodo Reservoir, then more complex chemical flood variations can be investigated, such as surfactant polymer flooding, alkali polymer flooding and ASP. In any event, the polymer flood response would serve as a baseline by which the effectiveness of the other processes can be measured. 

In buffered surfactant-enhanced alkaline flooding, it was found that the minimum in interfacial tension and the region of spontaneous emulsification correspond to a particular pH range, so by buffering the aqueous pH against changes in alkali concentration, a low interfacial tension can be maintained when the amount of alkali decreases because of acids, rock consumption, and dispersion [1826]. 

The effectiveness of alkaline additives tends to increase with increasing pH. However, for most reservoirs, the reaction of the alkaline additives with minerals is a serious problem for strong alkalis, and a flood needs to be operated at the lowest effective pH, approximately 10. The ideal process by which alkaline agents reduce losses of surfactants and polymers in oil recovery by chemical injection has been detailed in the literature [1126]. 

T. R. French and C. B. Josephson. Surfactant-enhanced alkaline flooding with weak alkalis. US DOE Rep NlPER-507, NIPER, February 1991. 

The purpose of alkali flooding (Jennings et al., 1974) is to introduce alkali into a reservoir where it can react with organic acids in the oil to produce organic salts, which act as surfactants. The surfactants (or petroleum soaps ) generated reduce the surface tension between the oil and water and this in turn reduces the level of capillary trapping of the oil. Thus, more oil is recovered because less of it remains trapped in the formation s pore spaces. 

Micellar-polymer flooding and alkali-surfactant-polymer (ASP) flooding are discussed in terms of emulsion behavior and interfacial properties. Oil entrapment mechanisms are reviewed, followed by the role of capillary number in oil mobilization. Principles of micellar-polymer flooding such as phase behavior, solubilization parameter, salinity requirement diagrams, and process design are used to introduce the ASP process. The improvements in ""classicaV alkaline flooding that have resulted in the ASP process are discussed. The ASP process is then further examined by discussion of surfactant mixing rules, phase behavior, and dynamic interfacial tension. 

Many of the basic concepts of micellar-polymer flooding apply to alkaline flooding. However, alkaline flooding is fundamentally different because a surfactant is created in the reservoir from the reaction of hydroxide with acidic components in crude oil. This reaction means that the amount of petroleum soap will vary locally as the water-to-oil ratio varies. The amount of petroleum soap has a large effect on phase behavior in crude-oil-alkali-surfactant systems. 

Surfactant Mixing Rules. The petroleum soaps produced in alkaline flooding have an extremely low optimal salinity. For instance, most acidic crude oils will have optimal phase behavior at a sodium hydroxide concentration of approximately 0.05 wt% in distilled water. At that concentration (about pH 12) essentially all of the acidic components in the oil have reacted, and type HI phase behavior occurs. An increase in sodium hydroxide concentration increases the ionic strength and is equivalent to an increase in salinity because more petroleum soap is not produced. As salinity increases, the petroleum soaps become much less soluble in the aqueous phase than in the oil phase, and a shift to over-optimum or type H(+) behavior occurs. The water in most oil reservoirs contains significant quantities of dissolved solids, resulting in increased IFT. Interfacial tension is also increased because high concentrations of alkali are required to counter the effect of losses due to alkali-rock interactions. 

A number of laboratory studies of the application of the alkali-surfactant-polymer flooding to various reservoir systems have been reported (63-67), but field application of this technology has been limited. Several field pilots are in progress or have been completed, but only one has been evaluated to date in the technical literature (68). This project is in the West Kiehl field in Wyoming operated by Terra Resources Inc. 

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. 

The primary reaction of alkali with reservoir water is to reduce the activity of multivalent cations such as calcium and magnesium in oilfield brines. Upon contact of the alkali with these ions, precipitates of calcium and magnesium hydroxide, carbonate, or silicate may form, depending on pH, ion concentrations, temperature, and so on. If properly located, these precipitates can cause diversion of flow within the reservoir, leading to better contact of the injected fluid with the less-permeable and/or less-flooded flow channels. This then may contribute to improved recovery. Also, this reduction of reservoir brine cation activity will lead to more surfactant activity, resulting in lower IFT values (Mayer et al., 1983). 

Alkalis react with naphthenic acid in crude oil to generate soap. The soap, an in situ generated surfactant, reduces the interfacial tension between the alkaline solution and oil. It is intuitive to infer that the main mechanism in alkaline flooding is low IFT. 

The purpose of an activity map is to show at what range of concentrations in a system and how a chemical flood will work. For a given reservoir where the temperature, composition of crude oil, and residual oil saturation are fixed, five kinds of variables are under our control types of alkalis, concentrations of alkalis, types of surfactants, concentrations of surfactants, and salinity. Another important variable that is not under our direct control is the type and amount of petroleum acid that will convert to soap when contacted by the alkalis. As discussed earlier, the amount of soap will determine the concentrations of alkali and surfactant injected. In other words, to generate an activity map, we have to know the amount of soap that can be generated. Because the alkali concen-ttation typically is much greater than that required to convert all the petroleum acids in the oil to soap, the petroleum soap concentration (meq/L) is calculated... 

At the concentrations of alkali above that required for minimum interfacial tension, the systems become overoptimum. The excess alkali plays the same role as excess salt. When synthetic surfactants are added, the salinity requirement of alkaline flooding system is increased. NEODOL 25-3S is such a synthetic surfactant used by Nelson et al. (1984). Figure 12.4, shown earlier, is a composite of three activity maps for 0, 0.1, and 0.2% of NEODOL 25-3S as a synthetic surfactant for 1.55% sodium metasilicate with Oil G at 30.2°C. We can see in the figure that without the synthetic surfactant, the active region of this system is below the sodium ion concentration supplied by the alkali. However, with 0.1 and 0.2% of NEODOL 25-3S (60% active) present, the active region is above the sodium ion concentration supplied by the alkali, so additional sodium ions must be added to reach optimum salinity. 

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. 

The water cut at which a W/O emulsion is transferred to an 0/W emulsion is called the type transferring point or critical water cut. Table 13.4 lists the critical water cuts for several emulsions at which the emulsions were transferred from W/O to 0/W. From Table 13.4, we can see that adding surfactant and polymer reduced their critical water cuts below 50%, whereas adding 1.2% alkali did not reduce the water/oil critical water cut. Table 13.4 indicates that under ASP flood conditions (high water saturation), most likely, 0/W emulsion will be formed. 

For all these cases, the total amount of each chemical was the same. The core flood results are shown in Figure 13.21. We can see that the incremental oil recovery factors over waterflooding in Schemes 2 and 4 were obviously higher than that in Scheme 1. The alkali and surfactant concentration gradients from high to low can overcome the negative effects at the displacement front caused by dilution, alkali consumption, and surfactant adsorption. 

Waterflooding was started in October 1998 and ended in March 2000 with 0.2002 PV injection. Then preflush polymer flood was started in April 2000 and ended in April 2001 (0.128 PV injection). Throughout the testing, the average polymer concentration was 1538 mg/L with viscosity of 40.9 mPa-s. An injection of the main ASP slug was started on May 1, 2001. By November 2004, 0.354 PV was injected. The average injection concentrations of alkali, surfactant, and polymer were 1.02%, 0.201%, and 1407 mg/L, respectively. The wellhead sample viscosity was 30.2 mPa s, and the IFT between the ASP... 

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