CHEMICAL ENGINEERING TRANSACTIONS

VOL. 63, 2018 

A publication of

The Italian Association
of Chemical Engineering
Online at www.aidic.it/cet

Guest Editors: Jeng Shiun Lim, Wai Shin Ho, Jiří J. Klemeš 
Copyright © 2018, AIDIC Servizi S.r.l. 
ISBN 978-88-95608-61-7; ISSN 2283-9216 

Enhanced Oil Recovery by Alkaline-Surfactant-Polymer

Alternating with Waterflooding

Norhafizuddin Husein*, Mat H. Yunan, Issham Ismail, Wan Rosli Wan Sulaiman,

Natalie V. Boyou

Faculty of Chemical and Energy Engineering, Universiti Teknologi Malaysia, 81310, Johor, MALAYSIA.

norhafizuddin.husein@gmail.com

Alkaline-Surfactant-Polymer (ASP) flooding is an efficient method but was poorly applied in the industry as it is

costly. The best mixture and injection sequence is also uncertain. The objective of this research work was to

determine the best injection design pattern which could reduce the cost while improving recovery via the

conventional ASP flooding. The effects of different ASP techniques in terms of injection sequence and mixture

on ultimate oil recovery were analysed. In the laboratory work, three types of chemical flooding injection

design were evaluated namely, continuous or conventional ASP flooding, alternating ASP with waterflooding,

and lastly tapering water to ASP ratio. The recovery for each cycle was recorded and the ultimate recovery

was compared. The experimental results showed that ASP alternating with waterflooding gave the best

ultimate recovery (68 %), followed by tapering water to ASP ratio (62 %) and continuous ASP flooding (57 %).

The ratio of recovery per volume of chemical injected showed that ASP alternating with waterflooding is the

best option as it uses the least chemical to yield a higher recovery. The ASP alternating with waterflooding

should be considered for field application as it can give the best performance with higher ultimate recovery.

1. Introduction

The common primary oil recovery factor ranges from 20-40 %, with an average around 34 %, while the

remainder of hydrocarbon is still not producible in the reservoir (Satter et al., 2008). Secondary recovery

involves the introduction of water or gas into an oil reservoir. This process would only recover a further of

10 % to 30 % of the original oil in-place (OOIP) (Romero-Zerón, 2012). On average, the recovery factor after

primary and secondary oil recovery operations is between 30 and 50 % (Green and Willhite, 1998). Hence,

leaving tons of oil yet to be recovered. A tertiary recovery is introduced which is widely known as Enhanced

Oil Recovery (EOR). It is a more complex and costly method to further recover residual oil. Due to the cost of

EOR, the right method should be chosen from a wide range of choices prior to its implementation in the field.

One of the most promising methods available is chemical flooding which includes alkaline, surfactant, and

polymer flooding. These chemicals are effective as results from the synergy formed between them (Kusumah

and Vazques, 2017). Alkaline-surfactant-polymer (ASP) flooding is a combination of chemicals injected to

obtain the best possible recovery by altering both the displacement and sweep efficiencies. As a result, the

recovery factor increases significantly when the displacement and sweep efficiencies are high. There are

numerous ongoing ASP flooding projects worldwide, and the ASP flooding implemented in Daqing field, China

is considered one of the largest projects (Manrique et al., 2010). However, as the costs incurred for chemicals

are high, it may not be feasible for all types of reservoirs. The research work focuses on improving the

technique in applying ASP flooding to a reservoir so that it can be cost and recovery efficient. Today, there is

still uncertainty on the most proficient technique to accomplish ASP flooding in terms of mixture ratios and

sequences of injection ASP and the right formulation can lead to a better recovery.

2. Alkaline-Surfactant-Polymer (ASP) flooding

The ASP flooding is one of the main methods in chemical enhanced recovery. Similar to other chemical EOR,

 

                                    

DOI: 10.3303/CET1863138
 
 

 
 

 
 

 
 
 
 
 
 
 

 
 
 

 
 
 
 
 
 
 
 
 
 
 
 
 
 

 

 

ASP is used to improve the mobility ratio and increase the capillary number, mainly by making the interfacial

Please cite this article as: Norhafizuddin Husein, Mat H. Yunan, Issham Ismail, Wan Rosli Wan Sulaiman, Natalie V. Boyou, 2018, Enhanced oil 
recovery by alkaline-surfactant-polymer alternating with waterflooding, Chemical Engineering Transactions, 63, 823-828  
DOI:10.3303/CET1863138   

823



tension (IFT) between the displacing and the displaced phases small, usually by about 1,000 folds (Thomas 

and Ali, 2011). This type of flooding is a combination of chemicals that can be considered as a perfect solution 

to improve mobility ratio and capillary number. Thus, this method can enhanced the oil production with the 

improvement of both the sweep and displacement efficiency (Hillary et al., 2016). Alkali is one of the main 

components in ASP flooding and it is used to reduce the adsorption of the surfactant on the reservoir rock. It 

creates an in-situ surfactant due to the alkali reaction with the acidic oil. This in-situ surfactant and the injected 

surfactant can reduce the interfacial tension (IFT) to ultralow values hence reducing the capillary number and 

the trapped oil can be produced (Rieborue et al., 2015). Generally, surfactant is expensive and it is not 

feasible if the adsorption rate was very high. This would result in the mobilization of immobile oil and 

preventing oil trapping (Liu et al., 2008). According to Singh et al. (2017), it is found that ASP flooding is a 

more cost-effective alternative to the conventional micellar-polymer flooding. Due to the similar properties of 

alkali and surfactant that can reduce the IFT, the combination of those two chemical will be in favour to reach 

the goal of ultralow IFT. One of the well-known functions of polymers is to increase the viscosity of displacing 

fluid hence, improve the sweep efficiency. Furthermore, polymer can also ensure a good mobility control for 

the flooding thus ensuring increase in sweep efficiency (Rieborue et al., 2015). It also has a special property 

called polymer viscoelastic behaviour where it can exert a larger pulling force on oil droplets or oil films due to 

the stress at the surface between oil and polymer. Over time, the force increases until it reaches a point where 

the force generated is powerful enough to remove oil from unrecovered pore thus, residual oil saturation is 

decreased. Overall, ASP flooding is expected to recover between 16 to 19 % from the original oil in place 

(Taiwo et al., 2016).  

3. Materials and method 

3.1 ASP Experimental Setup 

Sandstone in a specific size is chosen as the core sample in this study to simulate reservoir rock. For the 

model, the internal diameter and length was 0.25 cm and 120 cm, and due to the length of the model. An 

automated precision metering pump was used to pump the intended fluids inside the test section. The model 

of the pump used was Quizix QL-700 Series which was equipped with two cylindrical pumps that worked 

alternately. This pulse-free pump can pump fluid from either direction at a constant rate, pressure or 

differential pressure based on requirements. The experimental setup is as shown in Figure 1. 

 

Figure 1: Schematic of experimental setup for ASP flooding with three injection design. 

Prior to initiating the experimental work, the injection pattern with the desired PV of injected fluid was 

determined. The waterflooding, pre-slug, main-slug, and post-slug were injected accordingly into the sand 

pack model in order to vary the pore volume. The amount of fluid exited was measured and recorded to obtain 

the recovery per pore volume.  

3.2 Fluid properties 

The fluid used in this study was a high viscous paraffin oil which represented crude oil. This study utilized a 

simulated formation water consist of sodium chloride (NaCl) as brine. The salinity was 15,000 ppm in 

accordance with the salinity of NaCl equivalent at the Central Malay Basin (Heavysege, 2002). Table 1 is the 

summary for the simulated formation water and oil used.  The simulated oil was considered viscous and it 

fitted the characteristics of ASP which was better in displacing heavier oil. According to Brian (2003), heavy oil 

is produced more efficiently from ASP flooding compared to normal chemical flooding alone. 

Table 1:  Details of simulated fluids 

Type of Fluid Chemical Composition Density (g/ml) Remarks 

Brine NaCl 1.03 15,000 ppm (Salinity) 

Oil Paraffin 0.856 30 cp (Viscosity) 

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3.3 Injection rate 

A typical flow rate in normal reservoir is 2 ft/d, which is equal to 7.0556 x10
-6

 m/s. The field application value 

must be converted into a new lab scale value in order to simulate a real operation. From calculation, the 

obtained value for lab scale injection rate was 0.1 cm
3
/min. 

3.4 Injected chemicals 

Generally, chemical flooding processes involves three phases of slugs which are pre-slug, main slug and post-

slug. The pre-slug was where small portions of low concentrated polymer were used as the front end of 

chemical flooding. This is then followed by a sloppy ASP chemical main slug composing of alkali, surfactant 

and polymer. The chemical for alkali is considered strong where it is much more effective compared to a 

weaker alkali such as sodium carbonate (Na 2CO3) (Guo et al., 2017). Sodium hydroxide is not only used in 

laboratory works, but also in the field where it has strong emulsification ability and can form wider surfactant 

range. This enables it to meet the requirements of ultralow interfacial tension (IFT) (Guo et al., 2017). Table 2 

shows the concentration of chemicals used in this experimental works. The post-slug was the last phase of 

injection where the concentration of polymer was lower than in pre-slug. Post-slug acts as the protector for the 

ASP main slug and prevents fingering effect cause by chase water. 

Table 2: Concentration of utilized chemical 

Category Chemical Composition Concentration (wt.%) 

Pre-Slug Polymer Hydrolysed Polyacrylamide 0.1 

Main-Slug 

Polymer
1
 

Alkali
2
 

Surfactant
3
 

Hydrolysed Polyacrylamide
1
 

Sodium Hydroxide
2
 

Sodium Dodecyl Sulphate
3
 

0.03
1
 

0.5
2
 

0.13
3
 

Post-Slug Polymer Hydrolysed Polyacrylamide 0.05 

3.5 Injection Pattern 

The injection pattern for continuous/conventional ASP flooding starts with the injection of 2.5 PV of 

waterflooding, followed by EOR process with the introduction of another 2.5 PV of ASP flooding. Then, chase 

water of 1 PV was injected before it was terminated, thus the total injection of 6 PV was recorded as shown in 

Figure 2(a). Figure 2(b) shown the injection pattern for alternating ASP with waterflooding, the injection starts 

with 0.5 PV waterflooding. EOR process took place with the injection of another 0.5 PV of ASP flooding. The 

waterflooding alternated with low concentration of ASP was continued until it reached 5 PV, then it will be 

followed by 1 PV of chase water. Lastly shown in Figure 2(c), for tapering water to ASP ratio, the first cycle 

starts with, 0.83 PV of water was injected at a rate of 1 cm
3
/min, followed by ASP of 0.17 PV which totalling 1 

PV for one cycle. The second cycle, 0.67 PV of water was injected at the same rate while ASP was injected at 

a PV of 0.33. For the third cycle, the volume of water injected was the same as ASP flooding, which was 0.5 

PV each. The fourth and fifth cycle were designed using reversed ratio of the first and second cycles. As 

shown in Figure 1, all of the injection patterns was followed with 1 PV of chase water, where it is a standard 

practice used for most of ASP flooding projects (Ghorpade et al., 2016). 

 

Figure 2: Injection patterns schematic for (a) continuous/conventional ASP, (b) Alternating ASP with 
waterflooding and (c) tapering water to ASP ratio. 

(a) (b) 
(c) 

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4. Results and discussion 

4.1 Continuous/Conventional ASP flooding 

This injection design represents the typical ASP flooding. The process started with the injection of 

waterflooding first for 2.5 PV before EOR was initiated. It followed by the injection of 2.5 PV chemical flooding 

and 1 PV of chase water. Figure 3 shows that ASP flooding was used as secondary recovery after 

waterflooding where the blue background represents the waterflooding while green background represents the 

ASP flooding. The waterflooding of 2.5 PV was taken from previous experimental work. It can be observed 

that the waterflooding of 2.5 PV produced a recovery factor of approximately 50 % with the total final 

displacement of 57 % for the whole run. The follow-up ASP flooding produced an additional 7 % recovery after 

a static 50 % recovery recorded by waterflooding. This shows that ASP does gives increase in recovery even 

for this scale experimental work which only utilize sand pack model. This can validate that the sand pack and 

chemical composition used is suitable for this experiment. 

 

Figure 3: Recovery factor vs injected pore volume for continuous/conventional ASP flooding. 

4.2 Alternating ASP with waterflooding 

This injection design was the first to utilize the injection of ASP flooding in a sequential base while alternating 

with waterflooding. The process started with the injection of waterflooding of 0.5 PV followed by 0.5 PV of ASP 

flooding thus completing a ratio of 1:1 for waterflooding and ASP flooding of 1 PV. The sequence was 

continued in an alternating fashion until it reached the 5
th

 cycle before 1 PV of chase water was injected as a 

final displacement to push the oil and chemical out. The results are shown in Figure 4 with blue background 

represents the waterflooding while the green background represents the ASP flooding. ASP flooding was run 

immediately after a minor waterflooding process of 0.5 PV. Results showed that the flooding of chemicals 

started to show signs of recovery right after they were injected. This proves that ASP flooding acted as the 

recovery enhancer. On the last run, after the 6th and last PV, the recovery recorded was 68 %. The recovery 

increment was small after 1.7 PV after realizing a quick and high recovery of oil in the early stages of EOR. 

The decreasing rate later was due to the rapid recovery in the first 1.5 PV which then resulted in a high IFT 

between the oils that are not recovered in the sand pack model. 

4.3 Tapering water to ASP ratio 

This tapering injection design refers to the increment of ASP slug size rather than increment of ASP 

concentration. The process started with a 1:6 ratio of ASP flooding to waterflooding. Progressively, the ratio 

between ASP and waterflooding increased until the 5th PV where the ratio of 5:6 of ASP to waterflooding was 

obtained. This can be seen in Figure 5 with the blue background representing the waterflooding while the 

green background represents the ASP flooding. It can be seen that the recovery factor curve is similar to the 

alternating injection design where the ASP flooding was run immediately after a minor waterflooding of 0.83 

PV. It is observed that after 1 PV, the recovery was 46 % with the ultimate recovery of 62 %. The recovery 

was better when EOR was implemented in the early process. The introduction of such ASP technique has 

successfully reduced the interfacial tension thus reducing the amount of immobile oil in the sand pack model. 

When compared with alternating, tapering gave a slower start in recovery factor especially in the first half of 

the total 6 PV injected but picked up quickly in the last 3 PV due to smaller amount of ASP injected at start.  

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Figure 4: Recovery factor vs injected pore volume for alternating ASP with waterflooding 

 

Figure 5: Recovery factor vs injected pore volume for tapering water to ASP ratio. 

4.4 Chemicals’ Usage 

The feasibility study in any EOR project is significant in order to gain the best return of investment. Table 3 

lists the amounts of chemicals used in each injection design.  

Table 3:  Comparison of recoveries per chemical injected. 

Injection 

Design 

PV 

injected 

(%) 

ASP Slug (wt. %) Total Chemical Injected 
Recovery 

(%) 

Recovery per 

Chemical 

Injected 
A* S* P* A* S* P* Total 

Alternating 250 
 

0.5 

 

 

0.13 

 

 

0.03 

 

125 32.5 7.5 165 68 0.41 

Tapering 250 125 32.5 7.5 165 62 0.37 

Continuou

s 
350 175 45.5 10.5 231 57 0.25 

*A=Alkali, S=Surfactant, P=Polymer 

 

The results show the ratio of recovery per chemical used which described the efficiency of the chemical in 

every injection. Based on the results, the injection design that produced the highest recovery was alternating 

with 68 % followed by tapering with 62 %, and lastly continuous with 57 %. This showed that alternating 

827



injection design was better than tapering and continuous injection design. The ratio of recovery per chemical 

injected for alternating was also the highest with 0.41 compared to tapering and continuous with 0.37 and 0.25 

respectively. This means that alternating injection design was able to recover more oil with lower chemical 

usage. From technical feasibility views, alternating injection design gives the best option not only in term of 

recovery but also in term of the minimum chemical usage.  

5. Conclusions 

The chemical mixtures of alkaline, surfactant and polymer proved to be efficient because they cancel out each 

other’s disadvantages hence creating a mixture of chemicals that were able to recover more oil. The study 

revealed that the best injection design which gave the highest ultimate recovery was alternating ASP with 

waterflooding compared to conventional and tapering injection technique. The improvement in recovery 

percentage was due to the early implementation of EOR process instead of being a secondary or tertiary 

recovery. Furthermore, with early implementation of EOR, the sand pack model was conditioned much earlier 

which subsequently improved the recovery. Other than that, the ASP successfully reduced the interfacial 

tension much earlier in tapering and alternating compared to continuous which may have been full with 

immobile oil. The sloppy slug implemented in this study was efficient and easy to be implemented compared 

to other simultaneous injection of ASP thus can be considered as a good slug mixture in the field. 

Acknowledgments  

The authors would like to extend their gratitude to Universiti Teknologi Malaysia for making this research 

possible via Research University Grant (RUG), Vote Number 14H83. 

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