Energy & Fuels 2003, 17, 683-688
683
Water Soluble Acrylamidomethyl Propane Sulfonate (AMPS) Copolymer as an Enhanced Oil Recovery Chemical Anupom Sabhapondit, Arun Borthakur,* and Inamul Haque† Regional Research Laboratory, Jorhat-785006, Assam, India, and Dibrugarh University, Dibrugarh 786004, Assam, India Received October 22, 2001
A high molecular weight (>106) copolymer of N,N-dimethyl acrylamide with Na-2-acrylamido2-methylpropanesulfonate (NNDAM-NaAMPS) was prepared and characterized. The efficacy of the copolymer as an enhanced oil recovery (EOR) chemical was studied. Core flood tests using 72-150 mesh size unconsolidated sand having a porosity of 42% were carried out at different brine concentrations and temperatures. Initially, a crude oil fraction (150-300 °C) and, finally, the crude itself were used as the oils to be recovered. The copolymer was brine compatible. After a water flood, about 5.6% original oil in place (OIP) could be recovered by injecting 2000 ppm polymer solution to the sand pack containing oil fraction and 5000 ppm NaCl brine. The polymer solution was found to be thermally stable at 120 °C at least for a period of 1 month. It was further confirmed that the residual oil recovery increased with the increase of temperature. About 11% of OIP could be recovered as additional oil by injecting a 2000 ppm polymer solution to the unconsolidated sand pack containing one of the Indian crude oils and brine consisting of monoand bivalent metal ions at 90 °C.
Introduction The popularity of water soluble polymers as a mobility control or water shut off agent in the oil recovery process has increased significantly in recent years. Polyacrylamides, the most widely used water soluble polymers, control mobility in the reservoirs by increasing the viscosity of the injected water, and more importantly, by reducing the formation permeability.1,2 It has been reported3,4 that permeability reduction is mainly due to the adsorption and/or mechanical entrapment of the polymer molecules within the void spaces of the porous media. Polymers can reduce the detrimental effect of permeability variations and fractures in the reservoir and thereby improve both vertical as well as areal sweep efficiency.5 After a water flood, the unrecovered oil is left as microscopic droplets of residual oil. Water cannot flush all of the oil from the pore spaces as it moves through the reservoir rock. Moreover, the advancing water front bypasses a significant portion of the reservoir due to difficult well placements or unexpected geological configurations having variable permeability. The recovery efficiency is a function of three factors: (i) areal sweep efficiency, (ii) contact factor, and (iii) displacement efficiency.6 The sweep efficiency is related †
Dibrugarh University. (1) Gogarty, W. B.; Tosch, W. C. J. Pet. Technol. 1968, 20, 1407. (2) Szabo, M. T. J. Pet. Technol. 1979, 31, 553. (3) Szabo, M. T. Soc. Pet. Eng. J. 1975, 15, 323. (4) Dominguez, J. G.; Wilhite, G. P. Soc. Pet. Eng. J. 1977, 17, 111. (5) H. K. Van Poollen and Associates, Inc. Fundamentals of Enhanced oil Recovery; PennWell Books Division, Pennwell Publishing Company: Tulsa, OK, 1981; 83. (6) Herbeck, E. F.; Heintz, R. C.; Hastings, J. R. Pet. Eng. 1976, January, 33.
to the mobility ratio of the injected fluid (water) to the displaced fluid (oil). The mobility ratio is defined as
mobility ratio (M) ) )
mobility of injected fluid mobility of displaced fluid Kw /µw Ko /µo
(1)
Kw and Ko are the permeabilities of water and oil, respectively, while µw and µo are the viscosities of water and oil, respectively. Equation 1 indicates that oil recovery can be increased by increasing the viscosity or decreasing the permeability of aqueous phase in the reservoir. Polymer flooding is most advantageous in reservoirs where the overall conformity of the oil will be poor either because of very high viscosity conditions or because of heterogeneities in reservoir permeability.7 So, the primary necessity of a polymer to be used in EOR is its ability to form highly viscous solution in as low concentration as possible. Ionic polymers are found to be more efficient in producing high viscosity than that of the nonionic ones. While in the solution of a good solvent, ionic polymers exist in the maximum possible expanded state to minimize the repulsive interaction between the ionic groups of the same macroion bearing a similar charge. In other words, they exist like rods while nonionic polymers exist like coils. This makes a polyelectrolyte solution many times more viscous than a nonionic polymer having an identical molecular (7) Schumacher, M. M., Ed. Enhanced Recovery of Residual and Heavy Oils, 2nd ed.; Noyes Data Corporation: Park Ridge, NJ, 1980; pp 22-43.
10.1021/ef010253t CCC: $25.00 © 2003 American Chemical Society Published on Web 05/01/2003
684
Energy & Fuels, Vol. 17, No. 3, 2003
weight. Though in the presence of brine the viscosity of polyelectrolyte solution reduces manyfold, still it is high enough to compete against a nonionic polymer solution. Partially hydrolyzed polyacrylamide (PHPA), which is an anionic polyelectrolyte, exhibits a higher solution viscosity even after an abrupt reduction in 3% brine than that of nonhydrolyzed one.8 However, polymer solution must be stable under harsh conditions of salinity and temperature prevailed in the reservoir for a long period of time. It is observed that the significance of the polymer flooding may be achieved immediately or after a long period of time.9,10 The most common EOR polymer PHPA suffers excessive thermal hydrolysis at high temperatures and as a result may precipitate in the presence of bivalent cations.11 Because the world’s oil production has been moving toward deeper, and consequently, hotter reservoirs, the syntheses of necessary water soluble polymers are a challenge to the oil field chemists. At present, the most common onshore reservoir temperature lies around 120 °C. Even the synthetic polymers, such as poly(ethylene oxide), poly(vinyl alcohol), and cellulose derivatives, suffer thermal degradation, precipitation, and substantial viscosity losses as a result of aging in seawater at elevated temperatures.12,13 The polysaccharide polymers are thermally unstable even at 90 °C. Substituted polyacrylamides, or those copolymerized with a suitable monomer, can yield a better product which may be thermally stable at least for a period. It is established14,15 that the copolymers of acrylamide with 2-acrylamido-2-methylpropanesulfonic acid (Nasalt) offer hydrogen bonding capability and polyelectrolyte behavior in aqueous solutionscharacteristics of special interest to enhanced oil recovery (EOR). In the present work, the copolymer of N,N-dimethylacrylamide with 2-acrylamido-2-methylpropanesulfonicacid (Nasalt) was prepared, and its efficacy as an enhanced oil recovery chemical was evaluated under various conditions of salinities and temperatures. In the case of NNDAM-NaAMPS, the longer side chain renders the copolymer more stable from precipitation in the presence of divalent ions and more resistant to phase separation in electrolyte solutions.16 As this copolymer does not contain any free amide group (-CONH2), the probability of thermal hydrolysis is remote. Moreover, the presence of the hydrophobic -CH3 groups in NNDAM comonomer may help in bringing some shear stability to the copolymer.17 In a separate communication, the thermal stability of four different copolymers, namely, poly(acrylamide-co-Na acrylate), poly(acrylamide-coNaAMPS), poly (NNDAM-co-Na acrylate), and the (8) Lynch, E. J.; MacWilliams, D. C. J. Pet. Technol. 1969, 21, 1247. (9) Mezzomo, R. F.; Luvizotto, J. M.; Palagi, C. L. Soc. Pet. Eng., Reservoir Eval. Eng. 2001, 4, 4. (10) Moffitt, P. D.; Zornes, D. R.; Araghi, A. M.; McGovern, J. M. Soc. Pet. Eng. Res. Eng. 1993, 8, 128. (11) Moradi-Araghi, A. A.; Doe P. H. Soc. Pet. Eng,. Reservoir Eng. 1987, 2(2), 189. (12) Davison, P.; Mentzer, E. Soc. Pet. Eng. J. 1982, June, 353. (13) Akstinat, M. H. Presentation at the 1980 SPE International Symposium on Oil Field and Geothermal Chemistry, Stanford, May 28-30, Paper SPE 8979. (14) McCormick, C. L.; Park, L. S.; Chen, G. S.; Neidlinger, H. H. Polym. Prepr. 1981, 22(2), XXX. (15) Neidlinger, H. H.; Chen, G. S.; Arai, F.; McCormic, C. L. Polym. Prepr. 1981, 22, 90. (16) McCormick, C. L.; Elliot, D. L. Macromolecules 1986, 19, 542. (17) Ohoya, S.; Hashiya, S.; Tsubakiyama, K.; Matsuo, T. Polym. J. 2000, 32, 133.
Sabhapondit et al.
present copolymer solution, were studied by aging at 120 °C under a nitrogen atmosphere for a period of 1 month.18 It was observed that NNDAM-NaAMPS copolymer exhibited good thermal stability. Loss of solution viscosity for this polymer was minimal. About 66% of the solution viscosity was retained even after aging at 120 °C for a period of 1 month under nitrogen atmosphere. In this work oil recovery from an unconsolidated sand packed by the injection of the copolymer solution was studied. Permeability reduction due to the injection of the copolymer solution was also evaluated. Experimental Section Synthesis of the Copolymer. Synthesis of N,N-dimethylacrylamide-co-Na-2-acrylamido-2-methyl propanesulfonate is a well-established phenomena.19,20 N,N-Dimethyl acrylamide (NNDAM), purchased from Aldrich Chemicals, was exposed over calcium hydride for about 24 h to remove the stabilizers and then purified by distillation under vacuum. The compound 2-acrylamido-2-methylpropanesulfonicacid(AMPS), purchased from Merck-Schuchardt, was purified by recrystallization. Distilled NNDAM and purified AMPS monomers were dissolved in degassed distilled water. Residual oxygen was removed by bubbling nitrogen to the solution for an hour under constant stirring at 25 °C. To this solution, recrystallized ammonium persulfate and sodium metabisulfite solution, both obtained from CDH, New Delhi, were added slowly. The reaction was then allowed to undergo at 25 °C for 4 h. The final solution was clear and highly viscous. The solution was diluted to 2-3 times its volume. A part of the polymer was then isolated by precipitating with acetone and then dried in a vacuum at 40 °C for 15 h. AMPS content in the copolymer was then determined by potentimetric titration as well as from the 1HNMR data. The remaining part of the reaction mixture was then neutralized with NaOH (2% solution). The final copolymer was isolated by precipitating with acetone and dried in a vacuum oven at 40 °C for 15 h. The molecular diameter, or more correctly, root-mean square end-to-end distance of the copolymer was determined using Flory’s equation:21
(r2)1/2 ) 8(M[η])1/3
(2)
where (r2)1/2 is the root-mean square end-to-end distance in angstroms of the polymer, M is the molecular weight in dalton, and [η] is the intrinsic viscosity in dL/g of the copolymer. M and [η] should be determined in the same solvent and temperature. Though the equation is valid for nonionic polymers, it can be used satisfactorily for the ionic polymer solution in excess of brine since the charge on polymer chain is screened at least partially by oppositely charged ions of the electrolyte.21 In the present work, the molecular diameter is calculated using the intrinsic viscosity of the copolymer in 0.2M NaNO3 solution at 25 °C and the weight average molecular weight was determined by gel permeation chromatography in the same conditions of solvent and temperature. Physical Testings. 1H NMR spectra were taken in a Bruker 300 MHz Instrument using TMS as the reference. 1H NMR of the crude oil fraction was recorded in CDCl3 and the polymer sample in D2O. The relative abundance of the gemdimethyl groups of AMPS and that of the NNDAM was (18) Sabhapondit, A.; Borthakur, A.; Haque, I. J. Appl. Pol. Sci. 2003, 87, 1869. (19) McCormick, C. L.; Chen, G. S.; Park L. S.; Neidlinger, H. H. Polym. Prepr. 1981, 22, 90. (20) Klimchuk, K. A.; Hocking, M. B. and Stephen Lowen, S. J. Polym. Sci., Part A: Polym. Chem. 2001, 39, 2525. (21) Flory, P. J. Principles of Polymer Chemistry; Cornell University Press: Ithaca, NY, 1953.
AMPS Copolymer as an Enhanced Oil Recovery Chemical
Energy & Fuels, Vol. 17, No. 3, 2003 685
Figure 1. Laboratory setup for polymer flooding. determined to evaluate the monomer ratio in the copolymer. Polymer molecular weight was determined by Water’s gel permeation chromatography equipped with a refractive index detector using Shodex OH Pak columns KB 802.5, KB 803, KB 804, and KB 806; polyacrylamide as calibrants; and 0.2 M NaNO3 as eluent at 25 °C. Kinematic viscosity was determined by using an Ubbelohde viscometer while dynamic viscosity was measured by a Brookfield viscometer type LVTDV-II equipped with an UL adapter. Carbon number distribution were collected by gas chromatography technique using the IP/372/85 method. A dual column chromatography technique using an equal amount of alumina at the bottom and silica gel at the top as adsorbent was applied to separate the aromatic and the aliphatic part of the oil. n-Hexane was used to elute the aliphatic compounds, while benzene was used for aromatics. Crude oil is distilled up to 300 °C using the IP 24/84 method. An unknown polymer concentration was determined with a Chemito visible spectrophotometer using hyamine-1622 as a complexing reagent following the method described by Allison et al.22 Core Flood Tests. A schematic diagram of the experimental set up for the study of the oil recovery by the injection of the polymer solution is shown in Figure 1. The core assembly was a stainless steel cylinder of length 30 cm and an internal diameter 4 cm packed with sand. The sand used to prepare the sand pack is loose, fine-grained white silica (72-150 mesh). The sand was obtained by grinding iron free sandstone and further purified for iron impurities by washing with hot hydrochloric acid followed by washing with distilled water for several times. The differential pressure between the inlet and the outlet during the recovery was monitored. In most cases crude oil fraction having boiling range 150-300 °C was taken as the oil to be displaced. One of the North East Indian crude oil was also used for the ultimate recovery studies. After the (22) Allison, J. D.; Wimberley, J. W.; Ely, T. L. Soc. Pet. Eng., Reservoir Eng. 1987, 2, 184.
packed dry core apparatus was assembled, the sand pack was saturated with distilled water. Pore volume, porosity, and absolute permeability were determined. The core was then flooded with oil to a connate water saturation. An initial water flood was conducted until no additional oil was produced by the continuous water injection. Then it was flooded with the polymer solution to recover more and more residual oil. For the studies of the effect of brine on the oil recovery, the sand pack was saturated with brine instead of fresh water. It was then flooded with oil to connate water saturation after which the sand pack was flooded with brine water. Finally, it was flooded with the polymer solution. The polymer retention in the sand pack after recovery was calculated by material balance after determining the polymer concentration in solution before and after injection. Determination of Permeability. The absolute permeability of the unconsolidated sand was determined using Darcy’s law:
k)
µLQ ∆PA
(3)
where µ is the viscosity of the fluid, A is the area of cross section of the column, Q is the flow rate of the fluid, ∆P is differential pressure, and L is the length of the column. If µ is expressed in cp, A in cm2, Q in mL/s, ∆P in atm, and L in cm, k will be in darcy. k was determined from the slop of the plot of Q vs ∆P using freshwater as the fluid phase. In the case of two phase flow, effective permeability of the sand to polymer solution was determined using the same equation. It is given as
k1 )
µ1LQ1 ∆P1A
(4)
where k1 is effective permeability, µ1 is viscosity of the polymer
686
Energy & Fuels, Vol. 17, No. 3, 2003
Sabhapondit et al.
Table 1. Physical Characteristics of the Copolymer numerical value
property monomer wt ratio NNDAM:AMPS from 1HNMR potentiometric titration intrinsic viscosity (in aqueous 0.2 M NaNO3, at 25 °C) average molecular weight Mn Mw Mz root-mean-square end-to-end distance polydispersity
Table 3. Characteristics of Oil Fraction and Crude Used substance
property
numerical value
oil fraction
specific gravity (at 30 °C) I.B.P. (°C) F.B.P. (°C) aliphatic content (%) aromatic content (%) A.P.I. gravity pour point (°C) wax content (%) asphaltene (%) resin (%) I.B.P. (°C) vol % at 300 °C
0.7986 150 300 67% 33% 34 33 14 3-4 12-13 70 48
1.43 1.73 5.03 dL/g crude oil 328250 1488148 2750005 0.16 × 10-6 m 4.53
Table 2. Viscosity of Polymer Solution at 60 °C in Different Concentrations of Polymer and Brine
Table 4.
1HNMR
polymer solution at 60 °C
Data and Analysis of the Aromatic Part of the Oil Used
viscosity polymer viscosity brine composition (ppm) of oil at concn (cp) at -2 + 2+ 2+ 60 °C (cp) (ppm) Na Mg 7.344 s-1 Ca Cl SO4 1.05
0.08 0.15 0.15 0.15 0.15 0.15 0.20 0.20
983 1966 3932 5898 1966 3081
292
189
1517 3034 6068 9102 3034 6281
169
20.4 32.1 9.6 8.0 6.7 6.0 8.6 7.0
δ shift 0.746-0.779 1.031-1.154 2.058-2.865 6.739-7.682
interpretation Hγ Hβ HR Har
relative abundance 3.1 4.7 1.4 1.0
average aliphatic side chain length relative abundance (HR + Hβ + Hγ)/ relative abundance (HR)
6.4
solution when attains steady state, Q1 is the steady-state flow rate, and ∆P1 is the differential pressure at steady state. The permeability reduction due to polymer flooding is determined as
permeability reduction ) effective permeability before polymer flooding effective permeability after polymer flooding × 100 effective permeability before polymer flooding
Results and Discussions Physical characteristics of the copolymer NNDAMNaAMPS was presented in Table 1. The data in the table indicate that the root-mean-square end-to-end distance of the copolymer is 0.16 × 10-6 m. The weight ratio of AMPS to that of NNDAM in the copolymer was calculated from its 1HNMR spectra and found to be 41% AMPS and 59% NNDAM. Details of the 1HNMR spectra was discussed elsewhere.18 The effect of brine on the solution viscosity of the polymer at various concentrations are presented in Table 2. The data indicate that the viscosity of oil is much lower than that of the polymer solution used. Sand Pack Studies. The physical characteristics of the oil fraction and the crude used for the sand pack studies are presented in Table 3. The data in Table 3 indicate that the oil contains 67% paraffinic and 33% aromatic hydrocarbons. 1HNMR data of the aromatic fraction is given in Table 4, whereas the carbon number distribution of the paraffinic fraction is represented in Figure 2. Effect of Polymer Concentration. The increase in the recovery of residual oil by the injection of copolymer solutions of different concentrations to an unconsolidated sand pack is presented in Table 5. Polymer solution is injected after the breakthrough of the water flood. The additional oil recovery by injecting polymer
Figure 2. Carbon number distribution of the parrafinic portion of the oil.
Figure 3. Oil recovery by water and polymer (2000 ppm) flooding at 60 °C in absence of brine.
solution to the sand pack is represented in Figure 3. At a 2000 ppm solution of the copolymer, there is an increase of 8.62% OIP additional oil amounting to total oil recovery of 81% of OIP. The data in the Table 5 indicate that there is an increase in residual oil recovery with the increase in the concentrations of the copolymer in the injected fluid. But there seems to be an optimal concentration of the copolymer beyond which the increase of oil recovery is not observed. For this system,
AMPS Copolymer as an Enhanced Oil Recovery Chemical
Energy & Fuels, Vol. 17, No. 3, 2003 687
Table 5. Effect of Polymer Concentration on Oil Recoverya injection of 1.06 PV polymer solution
polymer concn (ppm)
irr oil saturationb (PV)
oil recovered by injecting 1.09 PV water (% OIP)
residual oil recovered (%)
permeability reduction (%)
polymer retention (10-4 g/g)
total recovery (% OIP)
500 1000 2000 3000 4000 5000
0.51 0.56 0.35 0.50 0.51 0.43
74.12 73.91 72.41 79.52 73.39 75.63
6.38 10.42 31.25 35.29 17.24 18.47
5.71 11.23 26.27 52.80 60.67 61.23
1.332 2.453 5.343 11.216 5.626 5.714
75.77 76.62 81.03 86.75 77.97 77.57
a
Sand size: 72-150 mesh. Effective porosity: 42.3%. Temperature: 60 °C. b Irreversible. Table 6. Effect of NaCl Concentration on Oil Recoverya injection of 1.06 PV polymer solution
NaCl concn (ppm)
effective porosity (%)
irr oil saturationb (PV)
oil recovered by injecting 1.09 PV water (% OIP)
residual oil recovered (%)
permeability reduction (%)
polymer retention (10-4 g/g)
total recovery (% OIP)
0 2500 5000 10000 15000
42.3 42.3 41.8 43.6 43.6
0.35 0.68 0.33 0.64 0.57
72.41 72.32 73.58 73.39 75.26
31.25 27.42 21.43 18.97 16.70
26.27 69.44 75.18 66.5 36.64
5.343 4.120 5.105 5.124 5.220
81.03 79.91 79.24 78.44 79.38
a
Sand size: 72-150 mesh. Polymer concentration: 2000 ppm. Temperature: 60 °C. b Irreversible.
a 3000 ppm solution of the copolymer is found to be the optimal concentration where maximum oil recovery is observed. The concentration of the copolymer in the solution before injection and that after injection gives the loss of the copolymer in the sand pack. This loss is not only due to the adsorption of the copolymer in the sand pack but also due to the physical trapping within the pores. In the absence of the electrolyte, the adsorption of polymer in the sand pack is minimal, since the repulsion between the charged groups on the polyion and the sand surface inhibits its accumulation near the interface. Therefore, the physical trapping within the pores should also be taken into considerations for the loss of polymer in the sand pack. This value increases with the increase in the concentration of the copolymer up to a certain point beyond which it becomes insensitive to polymer concentrations.23 Effect of Brine. The fluids present in the petroleum reservoirs may contain a large number of inorganic metal ions. An attempt is taken to study the efficacy of the copolymer on the recovery of residual oil in the presence of brine water. When the sand pack is saturated with NaCl solutions, interactions with the solid matrix will take place. The negatively charged silicate ions will be compensated by the positively charged Na+. When NaCl is injected with water to the sand pack, more and more silicate ions will be compensated and also a portion of Na+ will be trapped within the pores. So, when the polymer solution is injected to the sand pack there will be electrostatic interaction between the positively charged Na+ and negatively charged macroions increasing the adsorption at the sand surfaces. The electrostatic interaction between the charged groups plays an important role in adsorption as well as permeability reduction phenomena (Table 6). Szabo attributed the increased adsorption to the reduction in the hydrodynamic size of the polymer molecule with increased (23) Willhite, G. P.; Dominguez, J. G. Mechanisms of Polymer Retention in Porous Media. In Improved Oil Recovery by Surfactant and pOlymer Flooding; Shah, D. O., Schechter, R. S., Eds.; Academic Press: New York, 1977.
Figure 4. Oil recovery by water and polymer (2000 ppm) flooding at 60 °C in absence of brine.
Figure 5. Oil recovery by using water and polymer (2000 ppm) flooding in presence of 5000 ppm NaCl at 60 °C.
electrolyte concentration.24 Residual oil recovery decreases with the increase of brine concentration but with a minor change. As presented in Table 5, in the absence of electrolytes, 31.25% residual oil can be recovered, which decreases to 18.97% in the presence of a 10000 ppm concentration of NaCl. In one of the core flooding experiments, a solution of 2000 ppm of partially hydrolyzed polyacrylamide (PHPA) having a viscosity average of 1.6 × 106mol wt and 30% hydrolyzed was injected to the sand pack containing the oil and 5000 ppm NaCl. As presented in Figure 4, it (24) Szabo, M. T. Presentation at the Soc. Pet. Engs.-AIME, 47th Annual Fall Meeting, San Antonio, TX, Oct 8-11, 1972, Paper SPE 4028.
688
Energy & Fuels, Vol. 17, No. 3, 2003
Sabhapondit et al.
Table 7. Effect of Temperature on Oil Recovery in Synthetic Brinea,b injection of 1.06 PV polymer solution
temp (°C)
effective porosity (%)
irr oil saturation (PV)
oil recovered by injecting 1.09 PV water (% OIP)
residual oil recovered (%)
permeability reduction (%)
polymer retention (10-4 g/g)
total recovery (% OIP)
40 60 75 90
43.0 43.5 44.0 42.3
0.68 0.43 0.32 0.57
79.46 79.73 78.18 78.95
16.3 18.33 25.00 26.50
67.87 17.00 37.10 51.52
6.756 6.129 6.782 5.979
82.81 83.45 83.63 84.53
a Composition: [Na+], 3081 ppm; [Mg2+], 292 ppm; [Ca2+], 189 ppm; [Cl-], 6281 ppm; [SO4-], 169 ppm. b Sand size: 72-150 mesh. Polymer concentration: 2000 ppm.
oil left after the water flood. On increasing the volume of the injected polymer solution, oil recovery increases up to a point of breakthrough after which no additional oil can be produced. Summary and Conclusions
Figure 6. Oil recovery by water and polymer (2000 ppm) flooding at 90 °C in synthetic brine using crude oil.
indicates that additional 6.85% OIP amounting to total recovery of 78.63% OIP can be obtained. The corresponding additional oil recovery is 5.66% OIP amounting to total recovery of 79.24% by injecting the NNDAMNaAMPS copolymer solution (Figure 5). It may be mentioned that the irreversible oil saturations were 0.39 and 0.33, respectively. Effect of Temperature. Residual oil recovery at different temperatures by injecting NNDAM-NaAMPS copolymer into the sand pack system containing brine was studied. The results are tabulated in Table 7. The data presented in Table 7 indicate that there is an increase in oil recovery on the increase of temperature of the system. The reduction of permeability and polymer retention studies are also given in the Table 7. Since there is a variation of oil saturation, the permeability reduction as well as polymer retention cannot be correlated with the residual oil recovery. It is interesting to note that temperature did not play any role in oil recovery during the water flood. The increase of residual oil recovery by injecting the polymer solution at 90 °C to the sand pack containing crude oil and synthetic brine is presented in Figure 6. It indicates that a substantial portion of residual oil, i.e., 11% of OIP left after the water flood can be recovered by using polymer injection techniques. It can be mentioned that synthetic brine contains Na+(3081 ppm), Mg+ (292 ppm), Ca+ (189 ppm), Cl- (6281 ppm), and SO4-2 (169 ppm). Effect of Solution Volume. On increasing the volume of the polymer solution injected there seems to be an increase in oil recovery up to a point beyond which no additional oil is recovered resulting in the breakthrough (Figures 3-6). Before the application of polymer solution, the water/brine flood was conducted until no additional oil was recovered. As presented in the figures, the polymer solution is injected to recover the residual
Studies on the efficacy of NNDAM-NaAMPS copolymer revealed that it is a good candidate as an EOR chemical for high-temperature reservoirs with highdensity brine fluid. Core flood test using 72-150 mesh size unconsolidated sand having a porosity of 42% using different brine concentrations and temperatures also shows satisfactory results. Initially crude oil distillate (150-300 °C) and finally the crude itself were used as oil. The copolymer exhibits brine compatibility. It is reported25,26 that enhanced oil recovery by polymer flooding increases the ultimate recovery by 7-10% over that which has been recovered by primary and secondary alone. Meehan et al. could recover 2-4% OIP by using an agar solution in an unconsolidated sand pack study.27 After a water flood caused by the injection of a 2000 ppm solution of the present polymer solution to the sand pack column at 60 °C and 5000 ppm NaCl concentration, 5.6% OIP was recovered additionally. In the same conditions, PHPA, the most common EOR polymer, could recover 6.8% OIP. These two results are comparable considering the difference in oil-water ratio at the starting of polymer injection in the two experiments. The polymer solution is found to be thermally stable at 120 °C at least for a period of 1 month. The residual oil recovery increases with the increase of temperature. About 11% of OIP can be recovered as additional oil by injecting 2000 ppm of the polymer solution to the unconsolidated sand pack containing one of the Indian crude oil and brine consisting mono and bivalent metal ions at 90 °C. It can be concluded that the present polymer is expected to perform a better recovery at a higher temperature. Acknowledgment. We acknowledge Dr. J. S. Sandhu, Director, Regional Research Laboratory, Jorhat, India, for providing facilities and permission to publish these results. EF010253T (25) Schumacher, M. M. M., Ed. Enhanced Recovery of Residual and Heavy Oils, 2nd ed.; Noyes Data Corporation: Park Ridge, NJ, 1980; p 46. (26) Smith, R. V. Pet. Eng. Int. 1988, 60, 29. (27) Meehan, D. N.; Menzie, D. E.; Crichlow, H. B. J. Pet. Technol. 1978, 30, 205.
