This presentation will provide you with all the information you need to know about ASP flooding technology including some case studies.

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)