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An experimental study of polymer flooding to enhance oil recovery.


Polyacrylamide is a condensation polymer which has very useful properties. The structure of polyacrylamide is similar to polyethylene, but having hydrogen on every other carbon replace by an amide group, -ONH2. The molecule is composed of repeating -CH2-H(CONH2)--units. The amide groups allow for linking between polymer strands. The -ONH2 group from one molecule can react with the same group of another molecule, forming a link between them with the structure -ONHCO [1]. Partially hydrolyzed polyacrylamide is widely used in water treatment as well as in EOR processes to displace more oil and increase the recovery efficiency of water flooding process by modifying the water/oil mobility ratio, as an anionic coagulant [2]. Solution of Partially hydrolyzed polyacrylamide is used to improve sweep efficiency of water flood into oil reservoirs. During the standard water flood operation, the sweep efficiency is not as good as desired, because the mobility of water stream is higher than oil which leads to the bypass of the oil zone in a finger shape and break into the well bore at the early stage of the process [3, 6, 7]. Water mobility enhancement through the viscous behavior of partially hydrolyzed polyacrylamide solutions has an important role in improving oil recovery efficiency [3, 4, 5]. When soluble polymers are added to water, solution viscosity will be increased owning to the high molecular weight of polymer. Hence, during the flooding tests, the mobility ratio of water to oil reduces and as a result more sweep efficiency will be obtained. Polymer solutions injection as one of the EOR processes have been studied by many researchers. Polymer solution which has less mobility compared to fresh water can increase the sweep efficiency around 10%. In 1964 Perry and Sandiford expressed that partially hydrolyzed polyacrylamide (HPAM) could reduce the mobility of displacing water by increasing its viscosity [3]. Fulin and Demin (2006) studied the high concentration of polymer injection to enhance oil recovery and their experiments showed that by using higher concentration of polymer oil recovery is improved by 20 % of original oil in place (OOIP) [8]. In 2007 Zhang and Seright considered the suitable conditions for polymer flooding in oil reservoirs and expressed that polymer flooding stability was subjected to mechanical degradation as well as salinity and temperature. High temperature causes polymers degradation by radical scission and decomposition. Furthermore, the high salt concentration might decrease efficiency of a polymer solution [9]. Kotlar and Selle (2007) investigated the influence of combination of polymer (mobility control agent), surfactant (reducing IFT agent) and a small bi-functional molecule (increasing solubility agent and reducing salinity effect) during flooding to enhance oil recovery factor and deduced that oil recovery can be increased by 20% of OOIP [5]. Polymer flooding into Iranian oil fields has not been addressed in the literature. Here, we used polymers flooding to check the ability of this process to enhance oil recovery of an Iranian oil field. We employed light oil from Bibihakimeh oil field and obtained the optimum conditions for injection of polymer solution.

Experiential Work

To investigate the polymer flooding, a cylindrical sand packed model is utilized in this work. A glass cylinder with 2.5 cm inside diameter and 25 cm height is packed with two sizes of sand (50 & 100 mesh numbers) to visualize the types of oil flow in the model. After packing, both end sides of pipe are covered with fine metallic tissues and the fittings are connected to that. When the model is prepared, CO2 is injected to release the trapped air in the model for the accurate measurement of the porosity and the permeability of the model. Then the dry model was weighed and adequate amount of water is injected and the model is weighed again to calculate the pore volume and the porosity of the sand packed model. Moreover, permeability is calculated by employing Darcy's law under the water injection. This process consists of a water source which is maintained at a sufficient height connected to the horizontally positioned sand packed model through plastic pipes. The water flow rate through the model considering the static head of the water results in the permeability of the model. After characterizing the model, the oil flooding is done using a very precise syringe pump and the connate water is measured (Figure 1). Polymer solutions were prepared using 12 x [10.sup.6] g/mol molecular weight and 30% hydrolysis polyacrylamide. Various slugs of HPAM solutions are injected in secondary stage using different fractions of pore volumes, chased with fresh water till no more oil is produced. Monitoring the amount of the produced oil, accurately predicts the oil recovery efficiency utilizing polymer injection process.

Crude Oil samples from an Iranian oil field at the south-west of Iran (Bibihakimeh oil field) are selected to be used during the flooding tests. HPAM solutions are prepared at different concentrations of 500, 1000 and 1500 ppm to investigate the effect of solution viscosity on recovery factor. The injection rates are set at 0.3, 0.5 and 1 cc/min to evaluate the effect of injection rate on recovery factor. After saturating the model by oil, the slugs of polymers solutions with the sizes of 15%, 25% and 30% of pore volume (PV) are injected followed by water flood until no more oil could be produced. Table 1 summarizes the conditions of each test used in this study.


Results and Discussions

In order to check the effectiveness of HPAM solution, a comparison between recovery factor of fresh water flooding and polymer flooding is done. This experiment is performed using 25% hydrolyzed polyacrylamide with slug volume of 25% PV and the rate of 1 cc/min. Figure 2 exhibits almost 10% more oil recovery when using HPAM solution. As the oil reservoirs containing billion barrels of oil, therefore the polymer flooding seems to be economically feasible to continue the tests.


Effect of concentration of injecting solution on recovery factor

In order to investigate the effect of HPAM concentration on the recovery factor, the solutions having different concentrations of 500, 1000 and 1500 are utilized here. For each concentration, various slug sizes as a fraction of pore volume (PV) are used at the secondary oil recovery stage, followed by water injection until no more oil produced. Figure 3 indicates that the solution with more polymer concentration results in more oil recovery efficiency. The more concentrate solution with more viscosity can ideally sweep larger area of the model resulted in more oil recovery. Besides, the breakthrough time is delayed and the viscous fingering is mitigated in this case, enhanced the recovery process. However, Figure 3 indicates that by increasing the concentration the recovery factor will not change considerably and therefore the economical aspects of polymer injection to select the proper concentration must be considered.


The effect of injection rate on the recovery factor

Experiments are performed at three rates of injection in order to check the effect of injection rate on the ultimate oil recovery efficiency. It is observed that the injection of polymer solution at high rate will cause the polymer solution to bypass more oil shortly and to reduce the breakthrough time. At low injection rate, larger area of the model is swept because of the piston shape of the injected fluid as it is seen through the transparent glass sand packed models. Figure 4 shows more oil recovery efficiency at lower injection rates.


The effects of slug sizes on the oil recovery factor

Laboratory results show that when the slug volume of the injecting fluid increases, more oil is recovered due to more reduction of mobility ratio of water to the oil. This is mostly regarded as the enhancement of mobility ratio and low viscous fingering effect. Figure 5 illustrates the effects of slug volume on the oil recovery factor. It is evident from Figure 5 that the oil recovery efficiency increases more in the early stage of slug size adjustment. This effect will be decreased dramatically as the slug size increases more. It means that ever increasing the volume of the slugs may not be economical and the rate of change in oil recovery must be considered to select the proper size of the slug.


The effect of salinity on the effectiveness of HPAM solution

It is generally proved that the concentration of cationic ions such as [Na.sup.+], [Ca.sup.2+] and [Mg.sup.2+] have negative effects on the polymer flooding efficiency as it affects the viscosity of the solution. In order to find the effect of salinity concentration of the reservoir water on the polymer solution, synthetic brine solutions was used to prepare HPAM solution. Figure 6 shows that the viscosity of the solution decreases dramatically as the salinity concentration increases. It is concluded that HPAM is not a good candidate for the reservoir with high salinity content.


Temperature effect on the viscosity of HPAM solution

Temperature would affect the stability of the polymer solutions as they are very sensitive to the thermal effect. It is believed that most of the polymers will be decomposed at high temperatures and their applications will be hindered. Previous works in this area showed that the reservoirs with temperature higher than 300[degrees] F should usually be avoided for using HPAM [6]. As most of Iranian oil reservoirs' temperature is lower than 300[degrees] F, the possibility of polymer flooding in these reservoirs could be evaluated through further investigations.


(1) The laboratory study results indicate that polymer flooding in comparison with water flooding can improve the oil recovery up to 10% of OOIP.

(2) HPAM flooding at low rates shows more recovery efficiency as the fingering and bypassing would be mitigated.

(3) When HPAM is flooded at high concentration, more recovery will be obtained because of boosting the viscofying property of solution and as a result the mobility ratio becomes more favorable as close to the unity.

(4) With increasing the slug volume of polymer solutions, the recovery factor increases.

(5) Injection of polymer solution with more concentration will delay breakthrough time and causes further oil recovery.

(6) HPAM will be more effective at low salt concentration as well as low temperature.


EOR: Enhanced Oil Recovery

SOR: Reducible Oil Recovery

SCW: Connate Water Saturation

OOIP: Original Oil in Place

PV: Pore Volume

RF: Recovery Factor


[1] Bassam Z. Shakhashiri: "A Handbook for Teachers of Chemistry" Volume 3, page 368, (1989).

[2] Zeynali M. E., Rabii A and Baharvand H.: "Synthesis of Partially Hydrolyzed Polyacrylamide and Investigation of Solution Properties" Iranian Polymer J, 13(6) 479- 484, 2004.

[3] Perry A. Aryabright R., Phudy, J. S: and Phillips B.: "Partially Hydrolyzed Polyacrylamides with superior flooding," paper SPE 11208, Presented at 1982.

[4] Wang D. Han P., Shao Z.: "Sweep Improvement Options on Improved Oil Recovery", SPE/DOE Symposium on Improved Oil Recovery, Tulsa, Oklahoma, USA, 22-26 April 2006.

[5] Kotler H. and Helle D.: "Enhanced Oil Recovery by COMB-Flow: Polymer floods Revitalized ",Paper SPE106421,Presented at the 2007 SPE International Symposium on oil field chemistry held in Houston, Texas.

[6] Du Y.: "Field-Scale; "Polymer Flooding: Lessons and Experiences Gained During Past 40 Years", paper 91787 SPE presented at 2004 SPE program committee.

[7] Alban N. and Gubitta J.: "Surfactant Polymer interaction In Enhanced oil recovery.", 7th Annual HBCU Energy Symposium, Miami, Florida, 1999.

[8] Fulin Y., Demin W.: "Study on High Concentration Polymer Flooding to Future Enhanced Oil Recovery ", paper SPE101202, Paper SPE 101202, Presented at the 2006 SPE Annual Technical conference and exhibition, San Antonio, Texas

[9] Zhang, G., Seright R.S.: "Conformance and Mobility Control, Foams VS. Polymers," paper SPE105407, presented at the 2007 SPE Inter national symposium on oil field chemistry held in Houston, Texas.

O. Arjmand * (1) and A.R. Roostaee (2)

(1) Omid Arjmand MSc of Chemical Engineering. Shiraz, Iran Corresponding Author

(2) Alireza Roostaee Bs Student of Petroleum Engineering Department of Marvdasht University. Marvdasht, Iran

Table 1: Characterizations of experiments.

Exp. K Porosity Diameter Length
No. (Darcy) (%) (cm) (cm)

1 6.83 32.05 2.67 26
2 7.74 34.63 2.67 46
3 6.82 33.83 2.67 26
4 5.475 33.91 2.67 46
5 6.47 35.43 2.67 26
6 5.67 32.46 2.67 26
7 8.35 34.27 2.67 30
8 7.87 34.53 2.67 26
9 8.18 32.49 2.67 46
10 8.46 33.6 2.67 26
11 9.33 35.25 2.67 26
12 6.57 33.18 2.67 26
13 5.86 32.41 2.67 26
14 6.78 33.56 2.67 26
15 7.23 34 2.67 26
16 8.26 35.37 2.67 26
17 7.81 34.93 2.67 26
18 6.45 34.72 2.67 30
19 5.64 33.13 2.67 30
20 7.53 34.82 2.67 26
21 8.78 34.55 2.67 30
22 9.12 35.58 2.67 26

Exp. Mesh Inj. HPAM HAPM
No. size Rate Slug Conc.
 of (min) Size (ppm)
 sand (PV)

1 100&50 0.3 0.25 500
2 100&50 0.3 0.15 1000
3 100&50 0.3 0.25 1000
4 100&50 0.3 0.15 1500
5 100&50 0.3 0.25 1500
6 100&50 0.5 0.15 500
7 100&50 0.5 0.25 500
8 100&50 0.5 0.35 500
9 100&50 0.5 0.25 1000
10 100&50 1 0.15 500
11 100&50 1 0.25 500
12 100&50 1 0.35 500
13 100&50 1 0.15 1000
14 100&50 1 0.25 1000
15 100&50 1 0.15 1500
16 100&50 1 0.25 1500
17 100&50 1.5 0.15 500
18 100&50 1.5 0.25 500
19 100&50 1.5 0.35 500
20 100&50 1.5 0.15 1000
21 100&50 1.5 0.25 1000
22 100&50 1.5 0.35 1000

Exp. Connate Residual Recovery
No. Water oil after factor
 (Swc) HPAM (% of
 Flooding OOIP)

1 12.8 10.6 76.44
2 32.6 15 76.19
3 15.9 8.8 78
4 29.6 14 78.125
5 17.4 8.1 80.24
6 16 12.25 72.15
7 15.7 13.45 75.54
8 14 9.9 76.97
9 26.6 14.4 76.77
10 9.7 16.1 66.1
11 10 14.9 66.9
12 11.9 12.9 70
13 12.8 12.3 72.04
14 12.6 11.75 74.5
15 9.7 11.4 74.66
16 13.3 10.4 76.88
17 11.5 11.15 74
18 17.9 10.25 79.5
19 16.2 9.6 82
20 14 9.8 78.22
21 16.2 10.85 80.27
22 14.2 8 82.6
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Author:Arjmand, O.; Roostaee, A.R.
Publication:International Journal of Petroleum Science and Technology
Article Type:Report
Date:Jan 1, 2010
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