Polymer flooding alkali-surfactant

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

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. 

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. 

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. 

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. 

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. 

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... 

Krumrine, P.H., Falcone, J.S., 1983. Surfactant, polymer, and alkali interactions in chemical flooding processes. Paper SPE 11778 presented at the SPE Oilfield and Geothermal Chemistry Symposium, Denver, 1-3 June. 

Several micellar-polymer flooding models as applied to the EOR are discussed in [237]. It is noted that the co-solvent ordinarily used in this process considerably influences not only the microemulsion stabilisation, but also the removal of impurities in the pores of the medium. The idea of using an alkali in micellar-polymer flooding is discussed in [238] in detail. The alkali effect on the main oil components was studied aromatic hydrocarbons, saturated and unsaturated compounds, light and heavy resin compounds and asphaltenes. It is demonstrated that at pH 12 surfactants formed from resins allow to achieve an interfacial tension value close to zero. For asphaltenes, such results are achieved at pH 14. In the system alkali solution (concentration between 1300 to 9000 ppm)/crude oil at 1 1 volume ratio a zone of spontaneous emulsification appears, which is only possible at ultra-low interfacial tensions. 

Krumrine, P. H. and J. S. Falcone, Jr., Surfactant, Polymer and Alkali Interactions in Chemical Flooding Processes, SPE 11778, presented at the International Symposium on Oilfield and Geothermal Chemistry held in Denver, CO, June 1-3 (1983). 

Cmc values are important in virtually all of the petroleum industry surfactant applications. For example, a number of improved or enhanced oil recovery processes involve the use of surfactants including micellar, alkali/surfactant/polymer (A/S/P) and gas (hydrocarbon, N2, CO2 or steam) flooding. In these processes, surfactant must usually be present at a concentration higher than the cmc because the greatest effect of the surfactant, whether in interfacial tension lowering [30] or in promoting foam stability [3J], is achieved when a significant concentration of micelles is present. The cmc is also of interest because at concentrations... 

Although producing a more efficient ofl displacement than alkali/ surfactant/polymer flooding, microemulsion flooding has developed... 

Recent laboratory studies have demonstrated the potential utility of borates as alkaline agents in chemical enhanced oil recovery. Compared with existing alkalis, sodium metaborate has an unusually high tolerance toward the hardness ions, Ca + and Mg +, paving the way for the implementation of alkali-surfactant-polymer floods for the large number of high-hardness saline carbonate reservoirs. In the absence of surfactants, borate solutions exhibit a strong tendency for spontaneous imbibition, or uptake into oil-wet or mixed-wet carbonate cores, with consequently improved recovery of oil compared with solutions of other salts and alkalis. 

Weatherill, A. 2009. Surface Development Aspects of Alkali-Surfactant-Polymer (ASP) Flooding. Paper IPTC 13397 presented at the International Petroleum Technology Conference, Doha, Qatar, 7-9 December. DPI 10.2523/13397-MS. 

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]. 

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... 

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. 

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