Improving Oil Recovery during Water Injection and WAG Processes in Asphaltenic Oil Reservoirs by using Nonionic Surfactants

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1 302 Improving Oil Recovery during Water Injection and WAG Processes in Asphaltenic Oil Reservoirs by using Nonionic Surfactants Mohammad Abdi 1 ;SiyamakMoradi 1,;BahramHabibniya1;ShahinKord 1 Abadan Faculty of Petroleum Engineering, Petroleum University of Technology, Abadan, Iran moradi.s@put.ac.ir Abstract: Asphaltene deposition is one of the most popular problems, which occur during oil production; it can reduce oil recovery through wettability alteration and pore throat blockage. The Aim of this paper is to represent an experimental investigation of reducing oil recovery in water injection and WAG process during asphaltene deposition and improving the oil recovery by using a nonionic surfactant. The results of unsteady state experiments showed that asphaltene deposition reduced the oil recovery in water injection and WAG process significantly, and also lead to rock wettability alteration from water-wet to oil-wet. Also the results of flooding experiments demonstrated that employing the nonionic surfactant improved the recovery through rebounding wettability to water wet. Keywords Asphaltene Deposition; Nonionic Surfactant;Oil Recovery; WAG Process; Water Injection; Wettability Alteration 1. Introduction Enhanced Oil Recovery (EOR) refers to a variety of processes in which the amount of oil extracted from a reservoir after primary and secondary recoveries increases typically by injecting liquid chemicals(e.g., surfactant) or gas(e.g., nitrogen, carbon dioxide) or by the use of thermal energy. The injected fluids compliment the natural energy of the reservoir or interact with the reservoir rock/oil system to create favorable conditions for oil recovery [1]. The concept of EOR has gained popularity as the global demand for supply of oil has increased [2]. It is generally known that about two-thirds of Original Oil inplace (OOIP) remains unrecovered after primary and secondary recovery (pressure maintenance, water flooding) [2]. International Journal of Science & Emerging Technologies IJSET, E ISSN: Copyright ExcelingTech, Pub, UK ( For this reason, in oil production many methods such as injection of Water Alternating Gas (WAG) and direct gas thickeners are being used to enhance the sweep efficiency and control the mobility of gas injection [3]. Still, by employing these methods,there are some problems which can decreaseoil recovery; one of these problems is asphaltene deposition and precipitation.asphaltenes are arbitrarily defined as a soluble class of petroleum that is insoluble in light alkanes such as n-heptane or n-pentane but soluble in toluene or dichloromethane [4], [5]. Asphaltene precipitation and deposition occurs in the facilities at the surface, in the well tubing, or near wellbore due to different reasons such as compositional changes and pressure variations. These phenomena create a serious technical and economic problem during production and transportation of crude oil and can reduce porosity and permeability, alter rock wettability and reduce well injectivity and productivity [6]-[10]. Asphaltene deposition may occur also in fields in which chemical treatment such as enhanced oil recovery methods or acidizing process was conducted [7], [8], [11], [12].The treatment or removal of asphaltene precipitation especially near wellbore or in the well tubing requires workover operations, in which different methods, such as chemical, thermal, or mechanical methods, can be applied [13].using surfactant is one of these methods. Using surfactant is one of the useful methods for treatment of asphaltene precipitationand also increases recovery factor. In this paper, laboratory investigations were carried out using surfactant in water injection and WAG process to improve oil recovery during asphaltene deposition in rock, alternation of rock wettability due to asphaltene depositionand it s rebounding by use of nonionic surfactant was measured. And oil recovery in water injection and WAG process were compared in different states: without any deposition, during asphaltene deposition and after using a nonionic

2 303 surfactant during asphaltene deposition in both methods. 2. Experimental Setup and Procedures 2.1. Rock Properties Cemented fine grained well sorted sandstone core was used in this study. The absolute permeability of the sample was 806 md. Due to the sandy nature of the core, special cores were needed to be cut as small plugs from the main core. After cutting, the sample was completely washed, with toluene and methanol and dried in an oven at a temperature upper than for more than 24 hours to remove all possible oil and salt from rock. The core plug diameter and length were 3.8 and 15 cm at all experiments, respectively. Table 1 shows the measured porosity and absolute permeability of the sample. Table 1. Best results Preferred Lithology Sandstone Porosity,% 23 Absolute Permeability, md 806 Figure 1.Chemical structure of Triton X Experimental Procedure The first step of this experimental work is core preparation. Porosity and absolute permeability are measured and water saturation is reached to interstitial water saturation in any coreflood experiment. The experiments include three parts, water injection, WAG process and contact angle measuring. At the beginning of each part of coreflooding; oil recovery was measured, then oil recovery was measured after asphaltene deposition and at the end, oil recovery was measured after using Triton X100 as surfactant during asphaltene deposition. The flowchart of tests is shown in figure 2. The applied back pressure was 900 Psi and injection rate was 1ml/min in all of the tests. A solution of 0.5 percent Triton X100 in brine was used in Tests 5, 6 and Fluid Properties A. Water properties The brine used for this experiment was prepared in the laboratory and has a salinity of 10,000 ppm. In order to prepare the brine, 10 gr NaCl was solved in one liter of distilled water. This brine was used for core saturation in all of the experiments. B. Oil properties Crude oil from an Iranian field was used in this study. Density, dead oil viscosity at 25 C and the mole C fraction of 7 fraction of this sample is given in Table 2.The asphaltene content in oil was 8.5 percent that was measured by IP-143 method. C. Surfactant properties The nonionic surfactant used in this study was Triton ( C H O( C H O) ) X with molecular weight of gr/mol and Viscosity of 240 cp at 25 C.The structure of the Triton X-100 is shown in figure 1 Figure 2.Flowchart of Experiments A. Water Injection As it is shown,in figure 2, three water injections were employed, Tests 1, 3 and 5. In each test, core was saturated with 1% brine at the beginning and then dead oil was injected to the core till the water saturation reaches the irreducible water saturation and no more water be produced. In Test 1, when the core is saturated with oil and irreducible water, brine solution was injected at a rate of 1ml/min, and produced liquid is collected in burette and the oil and water are separated. Moreover, the oil recovery and differential pressure across the core were continuously monitored throughout the

3 304 experiment until the pressure stabilized, indicating no further recovery of oil. Table. 2: Properties of the used oil in the experiments. Components Residual Oil Associated Gas Reservoir Oil (mol%) (mol%) (mol%) H 2 S N CO C C C ic nc ic nc C C C C C C C Total Molecular weight of residual oil 243 Molecular weight of C 12 + fraction 325 Molecular weight of Reservoir oil 149 Sp.Gr. of C /60 o F Test 3 is like Test 1 except using solution of oil and n-heptane instead of oil for deposition and precipitation of asphaltene content in the core. Oil recovery and differential pressure across the core were continuously monitored throughout the experiment until the pressure stabilized, indicating no further recovery of oil like Test 1. In Test 5, in addition to asphaltene deposition and precipitation, a 0.5% nonionic surfactant/brine solution was used in order to displace the oil. Like previous tests oil recovery and differential pressure were recorded. B. WAG Process The WAG process was initially proposed as a method to increase the sweep efficiency during gas injection. In practice the WAG process, consist of the injection of water and gas as alternate slugs by cycles or simultaneously (SWAG) [14]. WAG processes can be grouped in many ways. The most common is to distinguish between miscible and immiscible displacements as a first classification [15]. The optimum WAG ratio is influenced by the wetting state of the rock [16]. WAG ratio of 1:1 is the most popular for field applications and has more oil recovery [15-17]. As shown in figure 2 there are three WAG processes in this work, all immiscible, with 4 CO cycles of water and 3 cycles of 2.A total of 1.6 pore volume was injected with 1:1 WAG ratio. In Test 2, when the rock is saturated with oil and irreducible water, WAG process is started, by CO alternate injecting of brine solution and 2.Oil recovery and differential pressure across the core were continuously monitored throughout the experiment until the pressure stabilized, indicating no further recovery of oil. In Test 4 and 6, WAG process is done during Asphaltene deposition except in Test 6, a 0.5% nonionic surfactant/brine solution is used instead of brine solution. Like previous tests oil recovery and differential pressure recorded. C. Contact Angle measurement The wettability alteration was also verified by measuring and comparing the contact angle between the oil drop and the rock after aging the rock at a specified temperature and concentration of the surfactant. The contact angle was measured by an

4 305 imaging system (figure 3).The contact angle is measured through the denser fluid, so in a water/oil/rock system, the contact angle is measured through water. When θ is between 0 and in such a system it is defined as water-wet, when θ is between and 180, the system is defined as oil-wet. In the range of 75 to 105, contact angle the system is neutrally-wet [18]. Figure 3. Experimental cell and imaging system for contact angle measurement. Tests 7, 8 and 9 are wettability measurements by contact angle method in sessile pendant drop. In Test 7, θ was measured between rock surface and oil drop in the presence of water. In Test 8, after deposition of asphaltene content in rock, θ was measured between rock surface and oil drop in the presence of water. In Test 9, after using nonionic surfactant during asphaltene deposition, θ was measured between rock surface and oil drop in the presence of water. All experiments were carried out in room temperature. 3. Results and Discussion The absolute permeability was measured by steady state method. For this purpose after preparation of the rock, specific fluid (fresh Water) with known viscosity wasinjected to the rock by constant rate untilthe differential pressure across the core was stabilized. This process was repeated 4 times and rates and differential pressures were recorded. Rate was plotted versus differential pressure and theslope of the curve was measured,then the absolute permeability, that is md, was calculated. As mentioned in the experimental section, there are 3 water injection tests in this work, number 1, 3 and 5. The amount of oil recovery in Test 1 was percent, In Test 3 oil recovery was percent and in Test 5 oil recovery was percent this results was plotted in figure 4 versus amount of pore volume injected. Figure 4.Comparing Oil Recovery in water injection, Tests 1, 3 and 5. In addition, there are 3 water alternating gas injections.tests number 2, 4 and 6. By employing WAG process oil recovery was increased and reached to 90 percent in Test 2,after deposition of asphaltene in Test 4 the oil recovery decreased to percent but by using nonionic surfactant in Test 6, effect of asphaltene deposition on oil recovery was almost compensated and oil recovery reached to percent. The oil recovery of Tests2, 4 and 6 was shown in figure 5. Figure 5.Comparing Oil Recovery in WAG process, Tests 2, 4 and 6. Differential pressure across the core in tests 1, 3 and 5 and tests 2, 4 and 6 are shown in figure 6 and figure 7. The results show that asphaltene deposition in rock causes a risein differential pressure and nonionic surfactant cause a fall in differential pressure during asphaltene deposition, but it does not reach to the original point.

5 306 rock surface change to 112 degree as shown in figure 9. Figure 6.Differential pressure across core in water injection, Tests 1, 3 and 5. Figure 9. Contact Angle in Test 8, 112. This wettability alteration can be compensated by employing nonionic surfactant during asphaltene deposition,which what happens in Test 9, and the angle between rock surface and oil drop in presence of water reached 34 degree as shown in figure 10. Figure 7.Differential pressure across core in WAG process, Tests 2, 4 and 6. As described in previous section contact angle method was used for measuring rock wettability;tests number 7, 8 and 9. Test 7 shows that the rock was water-wet at first and the angle between oil drop and rock surface in presence of water was 21 degree as shown in figure 8. Figure 8. Contact Angle in Test 7, 21. But after asphaltene deposition and precipitation in Test 8;causing alteration in wettability and turning the rock tooil-wet, the angle between oil drop and Figure 10. Contact Angle in Test 9, Conclusion The main objective of this study was to evaluate the effect of a nonionic surfactant on oil recovery during asphaltene deposition in water injection and WAG process; and measuring rock wettability alteration. Based on the results of the experiments, the following findings can be concluded: 1. Asphaltene deposition causes a significant reduction in oil recovery; 13.6 percent in water injection and percent in WAG process. By employing nonionic surfactant the oil recovery almost compensated; 8.97 percent in water injection and percent in WAG process. 2. Asphaltene deposition caused a noticeable increase in differential pressure across the core, so the differential pressure in water breakthrough was increased 1.45 times in water injection and 1.92 times

6 307 in WAG process. Use ofnonionic surfactant almost prevented the increasein differential pressure in both methods (Figures 6&7). 3. In comparison to WAG process, water break through point happens sooner in water injection.asphaltene deposition causes earlier occurrenceof water break through in each method;but use ofnonionic surfactantpostponed the point occurrence. 4. After injection of 0.77 pore volume in water injection and 1.46 in WAG process,no oil wasproduced. These amounts reduced to 0.66 and 1.21 respectively, due to asphaltene deposition.after using nonionic surfactant these amounts increased to 0.84 and 1.36 in water injection and WAG process and it was a good parameter for increasing oil recovery. 5. Asphaltene deposition altered rock wettability from water-wet to oil-wet (Tests 7 & 8, Figures 8 & 9).However, by employing nonionic surfactant rock wettability rebounded to water-wet (Test 9, Figure 10);it does not reach its original point. In the coreflooding system, differential pressure across the core increases and recovery of displaced phase decreases when non-wet phase displacing wet phase.andwettability alteration is one of the main causesfor increasing differential pressure and decreasing oil recovery during asphaltene deposition (Tests 3& 4, Figures 4, 5,6&7). For rebounding rock wettability to water-wet nonionic surfactant wasemployed during asphaltene deposition, differential pressure decreased and oil recovery increased (Tests5 &6, Figures 4, 5, 6&7). References [1] Green, D.W. and Willhite, G.P. Enhanced Oil Recovery Richardson, Texas: Textbook Series, SPE, 1998 [2] Majidaie, S. Khanifar, A.Onur, M. and Tan, I.M. A Simulation Study of Chemically Enhanced Water Alternating Gas (CWAG) Injection SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman, April16,2012 [3] Salehi, M.M. Safarzadeh, M.A. Sahraei, E.and TabatabaeiNejad, S.A.. Experimental study of surfactant alternating gas injection versus water alternating gas and water flooding enhanced oil recovery methods Journal of Petroleum and Gas Engineering.Vol4(6), pp ,2013 [4] Shedid, S.A. and Abbas, E.A.A. An Experimental Approach of the Reversibility of Asphaltene Deposition under Dynamic Flow Conditions SPE Middle East Oil and Gas Show and Conference, Kingdom of Bahrain, March 12,2005 [5] Mullins, O.C.Sheu, E.Y.Hammami, A. and Marshall, A.G. Asphaltene, Heavy Oils, and Petroleomics Springer.2007 [6] Kocabas, I. Characterization of asphaltene precipitation effect on reducing carbonate rock permeability Middle East Oil Show, Bahrain, April 5,2003 [7] Sarma, H.K. Can we ignore asphaltene in a gas injection project for light-oils? SPE International Improved Oil Recovery Conference in Asia Pacific, Kuala Lumpur, Malaysia, October 20,2003. [8] Zekri, A.Y. and El-Mehaideb, R. Steam/bacteria to treatment of asphaltene deposition in carbonate rocks Journal of Petroleum Science and Engineering, Vol 37. pp ,2003. [9] Kokal, S.L. and Sayegh, S.G. Asphaltenes: the cholesterol of petroleum SPE Middle East Oil Show, Bahrain, March 11,1995. [10] Shedid, S.A. Influences of asphaltene deposition on rock/ fluid properties of low permeability carbonate reservoirs SPE Middle East Oil Show, Bahrain, March 17, [11] Yangming, Z. Huanxin, W. Zulin, C. and Qi, C. Compositional modification of crude oil during oil recovery Journal of Petroleum Science and Engineering, Vol 38. pp. 1-11, 2003 [12] Yin, Y.R., Yen, A.T. and Asomaning, S. Asphaltene inhibitor evaluation in CO2 floods: laboratory study and field testing SPE Permian Basin Oil and Gas Recovery Conference, Midland, Texas, March 21, 2000 [13] Amro, M.M. Effect of scale and corrosion inhibitors on well productivity in reservoirs containing asphaltenes Journal of Petroleum Science and Engineering, Vol 46. pp , 2005 [14] Néstor, L.S. Management of Water Alternating Gas (WAG) Injection Projects Latin American and Caribbean Petroleum Engineering Conference, Caracas. Venezuela, April 21, 1999 [15] Christensen, J. R.Stenby, E. H. Skauge, A. Review of the WAG field experience SPE International petroleum conference and exhibition of Mexico, Villhermosa, March 3-5, 1998 [16] Jackson, D.D. Andrews, G. L. Claridge, E.L. Optimum WAG ratio Vs Rock wettability in CO2 flooding SPE Annual technical conference and exhibition, Las Vegas, Nevada, September 22, 1985

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