Asp flooding
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ASP flooding integrates alkaline chemicals, surfactants, and polymers to enhance oil recovery by improving displacement and sweep efficiency. Experimental results show that ASP flooding achieves a recovery factor of 45.3%, significantly higher than other flooding techniques, highlighting its synergy. However, challenges such as produced emulsions, scaling, and facility problems necessitate further research into alkali-free options and optimization of chemical compositions.
Asp flooding
- 1. ASP Flooding Presented to : Prof Dr/Ahmed ElGebaly Faculty Of Petroleum & Mining Engineering. Suez University. By : 1- Kareem Hassan Ahmed Elfarash sec 3 2- Ahmed Gamal Ahmed Mohamed sec 1 3- Nazeer AlRaas sec 4
- 2. • Alkaline chemicals such as sodium carbonate react with acidic oil components in situ to create petroleum soap, which is one of the surfactants. A synthetic surfactant is injected simultaneously with the alkali. A water-soluble polymer is also injected, both in mixture with the alkali and surfactant and as a slug following the mixture, to increase the viscosity of the injectant. ASP flooding is designed to both improve displacement efficiency and expand sweep efficiency. • Polymer is used for improving mobility ratio which greatly contributes to the expansion of sweep efficiency. The use of the alkali and the surfactant is to reduce interfacial tension between the displacing phase and the oil phase so as to improve the oil displacement efficiency.
- 5. Synergy in ASP • Olson et al. (1990) reported some incremental oil recovery factors over water flooding from alkaline flooding, polymer flooding and ASP flooding from the laboratory. The recovery factor from surfactant flooding was not available. The recovery factors from alkaline-only and polymer-only flooding were 10 percent and 11.6 percent, respectively. The sum of these factors was 21.6 percent. The recovery factor from the ASP flooding was 45.3 percent. Even if the assumed surfactant flooding would be 15 percent, the sum of the three processes would only be 36.6 percent, still lower than 45.3 percent. These data clearly demonstrate the ASP synergy. • Another important mechanism is the synergy between in situ generated soap and synthetic surfactant. Generally, the optimum salinity for the soap is unrealistically low, and the optimum salinity for the surfactant is high. When they function together, the salinity range in which IFT reaches its low values is increased
- 7. Mechanism of ASP • typical ASP injection process has three slugs: pre-slug, main ASP slug, and post-slug. The function of a pre-slug is to inject polymer solution for profile improvement. Sometimes, alkaline slug is injected as a pre- slug. Its objective is to remove high-concentration divalent to avoid association of these divalent with the subsequent surfactants. • The main slug consists of alkali (A), surfactant (S), and polymer (P). The average injection concentrations of these chemicals were 1.25 wt.% A, 0.27 wt.% S, and 0.135 wt.% P, respectively, and 30.8% PV was injected.
- 8. • After the main slug is injected, if only water is injected, the water will finger into the main ASP slug, because water mobility is much high than that of ASP slug. To avoid the fingering, a post-slug of polymer is injected immediately following the main ASP slug. • The total chemical injected can be described by the injection PV multiplied by the chemical concentration. For all the projects, the injected alkali, surfactant, and polymer averaged 43.16, 9.44, and 5.25, respectively, if both the PV and chemical concentrations were in the unit of percentage (%).
- 11. Screening Parameters • 1-Formation Almost all of the chemical EOR applications have been in sandstone reservoirs, except a few stimulation projects that were conducted in carbonate reservoirs. One reason for fewer applications in carbonate reservoirs is that anionic surfactants have high adsorption in carbonates and cationic surfactants are expensive. Another reason is that anhydrite often exists in carbonates, which causes precipitation and high alkaline consumption. Clays in sandstones also cause high surfactant adsorption and high alkaline consumption. Therefore, clay contents must be low for a chemical EOR application.
- 12. 2-Oil composition and viscosity Oil composition is very important to alkalis and surfactants, but it is not critical to polymer. According to Taber et al. oil viscosity should be less than 35 cP for an alkaline–surfactant (AS) project. In most of Chinese ASP projects, the oil viscosity is around 10 cP, with a maximum of 70 cP. If the technology can be advanced in alkaline and polymer injection in heavy oil reservoirs, the viscosity range for an ASP application could become wider.
- 13. 3-Formation water salinity and divalent Most of ASP projects were carried out in low-salinity reservoirs of about 10 000 ppm. 4-Reservoir Temperature According to Taber et al. the reservoir temperature should be lower than 93 ºC for ASP projects, but the average temperature for actual AS field projects was 27 ºC, and the average temperature for polymer projects was 60 ºC. Daqing reservoir temperature is about 45 ºC. The maximum temperature for few Chinese projects was in the order of 80 ºC.
- 14. •5-Formation Permeability • High permeability is favorable to ASP flooding, and it is critical to polymer injection. Simply, polymer may not be able to flow through low permeability formations. Interestingly, Taber et al. showed that although the criteria for chemical projects is >10 md, the average permeabilities in actual projects were 450 md for A/S, and 800 md for polymer flooding.
- 15. Summary of screening criteria for ASP from successful projects Desired valueProperty 12.9Oil Viscosity(cp) .3Oil Saturation(fraction) 473Permeability(md) 52Reservoir Temperature© 7993Formation Water Salinity(PPM) SandStoneLithology lowClay Content
- 16. Summary of ASP projects • About 32 ASP field pilots and large-scale applications have been reported with performance data so far worldwide. Among these 32 ASP projects, 21 projects were carried out in China, seven in USA, one in Canada, two in India, and one in Venezuela. All the projects were carried out in onshore reservoirs except the Lagomar project in Venezuela, which is in offshore. It was also reported that ASP flooding was conducted recently in the Elk Hills field in California and the Mooney field in Canada, but the detailed results are not available. Zargon Oil & Gas Ltd. has initiated an ASP project in the Little Bow field.
- 20. Field performance • The incremental oil recovery factors over waterflooding available for the projects are shown. The average incremental recovery factor was 21.8% original oil in place (OOIP). The decreases in water cut after ASP injection available for the projects are shown. The average decrease was 18%.
- 21. • Incremental oil recovery factors available for the projects and their average
- 22. Water cut reduction available from the projects and their average
- 23. PROJECT ECONOMICS • Figure shows the available chemical cost per barrel of incremental oil from the surveyed ASP projects. The average was about $6/bbl. The polymer cost is $1.5/lb. The prices of alkalis and surfactants are assumed to be 0.1 and two times the polymer price, respectively. The results are shown in Table . It shows that the average chemical cost is $8.44/bbl. of incremental oil, which is higher than the actual average cost. This is only the chemical cost. The facility cost and operation cost are not included. In some ASP projects, it is difficult to break produced emulsions. Then the costs of facilities and demulsifiers will be significant. Sometimes, more wells need to be drilled to complete injection patterns. Thus more drilling cost will have to be added
- 24. Chemical costs in actual alkaline–surfactant–polymer projects
- 25. Table Estimation of chemical costs based on the average chemical concentrations and slug volumes of surveyed projects
- 26. PROBLEMS ASSOCIATED WITH ASP FLOODING • 1- Produced Emulsions Stable emulsions can be formed in surfactant, alkaline, and even in water injection. In water injection, stable emulsions can be formed because crude oil has natural emulsifiers such as asphaltene. In surfactant injection, surfactant reduces the water/oil IFT so that stable emulsions can be formed. In alkaline flooding, stable emulsions can be formed because alkali reacts with crude oil to generate in situ surfactant (soap). Although polymer helps to stabilize emulsions, it cannot form emulsions with oils. According to their structures, there are four types of emulsions: W/O, O/W, W/O/W, and O/W/O. Sometimes, W/O/W and/or O/W/O are called multiple types. Generally, W/O emulsion was much more stable than O/W emulsion.
- 27. 2-Chromatographic separation of alkali, surfactant, and polymer • Figure shows the effluent concentration histories of an ASP slug injection. The vertical axis shows the normalized concentrations of polymer, alkali, and surfactant. The horizontal axis is the injection PV. First, we can see that polymer broke through first, then alkali followed by surfactant. Second, each maximum relative concentration depended on its retention or consumption in the pore medium. The maximum polymer concentration was 1, the maximum alkali concentration was 0.9, and the maximum surfactant concentration was 0.09 in this case. Third, their concentration ratios in the system were constantly changing. In other words, the chemical injection concentrations will not be proportionally decreased. In general, actual effluent concentrations and breakthrough times depend on their individual balance between the injection concentration and the retention or consumption
- 28. Effluent concentration histories of polymer, alkali, and surfactant (Huang and Yu, 2002)
- 29. 3-Precipitation and scale problems • When an alkaline solution is injected into a formation, OH− concentration is raised. The raised OH−converts HCO3 − into CO3 2. Alkaline reaction with formation minerals may produce SiO3 2−. Seawater has a high concentration of SO4 2−. When divalent such as Ca2+, Mg2+, and Al3+ exist in the formation, the divalent react with OH−, CO3 2−, and SiO3 2−. Several inorganic scales and precipitates can be formed. Frequent operation failures of production wells due to these problems were observed in Daqing. The scaling and precipitates may cause formation damage.
- 30. • Chinese operators have experienced severe scaling and emulsion problems in their surface facilities caused by strong alkalis such as NaOH. In addition, high-concentration alkalis reduce SP solution viscosity and viscoelasticity. To avoid the preceding problems, Chinese companies are proposing the following: (1) alkali-free SP flooding and (2) dynamic IFT of 10−2 mN/m, not 10−3 mN/m. IFT of 10−2 mN/m may be low enough to reach a high incremental oil recovery factor. The main reason is that it is quite difficult to reach 10−3 mN/m IFT. To achieve such low IFT, sometimes high surfactant and alkaline concentrations need to be used. Thus, the chemical cost will go up. A high alkaline concentration will cause more problems, such as emulsion, scaling, precipitation, formation damage, and so on. A high alkaline concentration will also reduce polymer viscosity. As a result, more polymer will be needed to reach a required viscosity.
- 31. • Although ASP outperformed any other combinations of alkaline, surfactant, and polymer flooding, the problems with produced emulsions (difficult to demulsify or increased cost), scaling, and corrosion have led the industry to seek alkaline-free options like SP process. Or a week alkali is preferred to a strong alkali.
- 32. 4-Problems associated with facility • Because of scaling problem of ASP solution, the average work life of screw pumps in Daqing ASP flooding was shortened to 97 days, compared with 375 days in polymer flooding and 618 days in waterflooding. • Other facility problems associated with ASP are related to polymer viscoelastic behavior. Because of polymer solution viscoelastic behavior, when polymer solution flows into a branch line (at a tee section), a ‘pulling force’ tries to pull the solution back into the main supply line. This pulling force increases with the increase in velocities of the branch and main supply lines. The velocity in the branch line oscillates, when the triplex pump pumps. The oscillation of the velocity changes normal stress and extension viscosity, thus causing the pump vibration. The solution was to increase pipe size. • The polymer solution causes a larger blind area in the bottom of a maturation tank, which makes mixing more difficult and consumes more energy to mix polymer solution. Re-design of the mixing blades mitigated the problem. For beam pumps, polymer solution enhances the sucker-rod eccentric wear. The centralizers were used to solve the problem
- 33. Future developments • Based on this comprehensive review study, the following are our recommendations on future developments. 1- High temperature and high salinity (and high-divalents) limit ASP applications. Surfactants and polymers that can be used in such reservoirs need to be developed. 2- The ASP problems are related to alkaline injection. Therefore, we want to see whether alkalis have to be used. In other words, we need to answer the following: can SP be a better option than ASP? 3- Alkali can react with the crude oil to generate soap. This function is attractive. However, most of the field projects conducted until 1983 offered the incremental oil recovery factors of only 1–2% (Sheng, 2013c). The question is, is the generated soap important in improving oil recovery? More broadly, we also need to answer the following: are the advantages of alkaline addition more than disadvantages? 4- The potential benefit of ASP over the individual A, S, or P process relies on the synergistic effect. To have this synergistic effect, the components of A, S, and P must be in the same slug (no chromatographic separation). Few papers have been published to address this issue. Future research effort should be placed on it.
- 34. References • A Comprehensive review of ASP flooding ( SPE ) • ASP Flooding Shell • ASP Flooding Theory and Practice Progress in China • International Journal of Biology and Chemistry 8, №1, 30 (2015)