Retention Behavior of Dilute Polymers in Oil Sands - American

Chapter 12

Retention Behavior of Dilute Polymers in Oil Sands 1

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Downloaded by UNIV LAVAL on July 14, 2016 | http://pubs.acs.org Publication Date: July 10, 1989 | doi: 10.1021/bk-1989-0396.ch012

Jitendra Kikani and W. H. Somerton

1Department of Petroleum Engineering, Stanford University, Stanford, CA 94305 Department of Mechanical Engineering, University of California, Berkeley, CA 94720

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This study investigates the retention behavior of dilute polymer solutions in oil sands. Results indicate that the presence of a large amount of fines and/or a variety of minerals in the sand may result in high adsorption and retention causing excessive loss of polymer and high injection pressures. Injection of a surfactant with the polymer leads to increased oil recoveries because the dilute polymer may selectively adsorb on mineral grain surfaces leaving the surfactant to act at liquid/liquid contacts. For this study flow (dynamic) and static (batch) tests were carried out on Wilmington oil field unconsolidated sands at reservoir temperatures and flow rates with polyacrylamide (Dow Pusher-500) polymers. Effluent concentration, viscosity, and pH were monitored as a function of time. Extensive characterization studies for the sand were also carried out. Adequate mobility control between fluid banks is a pertinent factor in the successful application of secondary and tertiary oil recovery processes. During a waterflood, oil viscosities are normally higher than that of the driving aqueous phase and thus there exists an adverse mobility ratio. This causes fingering and/or channeling of the displacing fluid which reduces pattern conformance and results in low sweep efficiencies. In order to improve this situation the mobility of the displacing fluid needs to be reduced. Reduction in the mobility of the displacing fluid can be obtained by increasing the viscosity of the displacing phase or reducing the permeability to the displacing phase(l,2). Polyacrylamide and bio-polymers have proved to be useful for these purposes. These polymers increase the water viscosity substantially at low polymer concentrations. The resulting reduced mobility of the displacing phase suppresses the fingering phenomenon and improves piston-like displacement. In addition to the mobility control provided by viscosity enhancement of water, there is a selective reduction in the permeability to the aqueous phase due to the selective blocking of pores by the polymers(3). Both, viscosity enhancement and permeability reduction to the aqueous phase, act in the direction of decreasing mobility and even for fairly dilute polymer solutions, hold promise that adequate mobility control of fluid banks could be achieved. As the displacing fluid front advances, the structural complexity of these 0097-6156/89A)396-O241$06.00/0 o 1989 American Chemical Society Borchardt and Yen; Oil-Field Chemistry ACS Symposium Series; American Chemical Society: Washington, DC, 1989.


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polymers coupled with the complexity of the flow channels in the porous medium cause part of these polymers to be retained in the reservoir. This causes a reduction in the concentration of the polymer solution at the front and consequently a loss of mobility control. In addition to the mechanical filtering of the polymer molecules, adsorption on the grain surfaces reduces the polymer concentration in the displacing fluid. Various retention mechanisms of polymer in porous media are discussed in detail by Willhite and Dominguez(4). The nature of the polymer controls, to a large extent, the retention behavior in porous media. Partially hydrolyzed polyacrylamide polymer molecules have the capacity of assuming a variety of three dimensional configurations. Also because of competing mechanisms in the polymer formation, there is a wide range of chain lengths. The weight average molecular weight of the polymer used for the present work was 5.89 million (Dow Chemical Co., Personal Communication, 1985). Polyacrylamide polymers used in this study have been studied extensively by a number of researchers(5,6). Susceptibility of these polymers to salinity, pH, shear, temperature, etc. is well documented(7,8). Mechanical entrapment, retention, degradation and adsorption behavior on a number of porous media including fired Berea sandstone(2), bead packs(9) and Ottawa sands(lO) have been reported. It is interesting to note here that although numerous studies have been carried out with polyacrylamide polymers, not many studies have been performed on partially oil-saturated reservoir sands. Also, noticeably conflicting results, for polymer retention and adsorption, have been reported in the literature. The present study investigates the adsorption and trapping of polymer molecules in flow experiments through unconsolidated oil field sands. Static tests on both oil sand and Ottawa sand indicates that mineralogy plays a major role in the observed behavior. Effect of a surfactant slug on polymer-rock interaction is also reported. Corroborative studies have also been conducted to study the anomalous pressure behavior and high tertiary oil recovery in surfactant dilutepolymer systems(ll,12). Experimental Static(batch) and dynamic(flow) tests were carried out on toluene - extracted and peroxide - treated Wilmington oil field unconsolidated sands with dilute solutions of polyacrylamide (Dow Pusher-500) polymer in 1 wt% NaCl at 50° C and 1.5 ft./day, simulating reservoir temperature and flow rates. In the static tests, Ottawa sand, with particle size distributions similar to the Wilmington sand, were also used for comparison purposes. The core - flood apparatus is illustrated in Figure 1. The system consists of two positive displacement pumps with their respective metering controls which are connected through 1/8 inch stainless steel tubing to a cross joint and subsequently to the inlet end of a coreholder 35 cm. long and 4 cm. in diameter. Online filters of 7 |im size were used to filter the polymer and brine solutions. A bypass line was used to inject a slug of surfactant solution. Two Validyne pressure transducers with appropriate capacity diaphragms are connected to the system. One of these measured differential pressure between the two pressure taps located about one centimeter from either end of the coreholder, and the other recorded the total pressure drop across the core and was directly connected to the inlet line. A two - channel linear strip chart recorder provided a continuous trace of the pressures. A n automatic fraction collector was used to collect the effluent fluids. Sand and polymer characterization . The oil sands were extracted in a Soxhlet extraction apparatus with toluene as the refluxing liquid. After the extr-

Borchardt and Yen; Oil-Field Chemistry ACS Symposium Series; American Chemical Society: Washington, DC, 1989.

KIKANI AND SOMERTON

Retention Behavior ofDilute Polymers

Table I. Mineralogy of Wilmington Oil Sand Count

Property


Grain Size > 210 |im

39.4 %

210 - 74 nm

35.8 %

74 - 43 nm

13.3 %

43 - 2 |im

11.2 %

< 2 |im

0.3 % Mineral Content

Quartz

43.0 %

K-Feldspar

21.0 %

Plagioclase

15.0 %

Biotite Mica

10.0 %

Others

11.0 % Clay Minerals

Montmorillonite

major

Kaolinite

minor

Elite

trace


OIL-FIELD CHEMISTRY


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-action was complete, the thimbles were dried and the sand poured into a beaker to which distilled water was added just to cover the surface of the sand. The water was brought to a slow boil and a small amount of hydrogen peroxide was added. This was continued at intervals until no more effervescence was observed. This was done because peroxide treatment oxidizes the remaining organics coating the surface of the sand. Mineralogy of the unconsolidated Wilmington oil sand was obtained by grain size analysis, thin-section study of an impregnated color-stained sample, scanning electron-microscope(SEM), and X-ray diffraction studies. A summary of the results of the study is given in Table I. Surface area of the whole sand sample, the < 2 micron fraction, and the Ottawa sand (quartz) was determined by nitrogen adsorption using helium as the carrier gas in a BET apparatus. The samples were prepared by the freeze - drying technique in a vacuum freeze dryer. In this technique, a suspension of sand sample in deionized water is instantaneously frozen in a liquid nitrogen atmosphere. The sample holder is then attached to the vacuum freeze dryer kept at a temperature of -50° C. This procedure is used to minimize agglomeration of the mineral grains and expose the greatest surface area. The surface areas are reported in Table II. This table also shows the particle size distribution of Ottawa sand used in the static tests. Table II. Surface Area Measurements Wilmington Oil Sand, whole rock

0.95 m /g

Wilmington Oil Sand, < 2 |im size

14.9 m /g

Ottawa Sand

0.12 m /g

2

2

2

composition : > 48 - 65 mesh

40 %

100 - 150 mesh

15 %

150 - 200 mesh

20 %

200 - 325 mesh

15 %

325 - 400 mesh

10 %

Polymer solutions were prepared by standard techniques(13). Viscosities were measured by a Brookfield L V T viscometer with U V adapter. Shear rates of 30 rpm were found to be the most suitable for viscosity measurements up to 400 ppm above which the pseudo-plastic behavior caused significant shear rate dependency on the apparent viscosity. pH of the effluent solutions were measured by a digital pH/ionmeter with combination electrodes. Polymer concentration measurements were performed on a double-beam ratio recording UV-visible spectrophotometer with micro-computer electronics by the use of turbidimetric method presented by Foshee et. al.(13). Wavelength, slit sizes, pH and mixing time were all properly calibrated before use. The calibration curve is shown in figure 2. A detailed description of the procedures and results can be found in reference 14. Figure 2 shows the effect of mixing time on the calibration curve.


12. KIKANI AND SOMERTON


-Brine f l a s k

245

Pressure T r a n s d u c e r ^ Transducer Indicator

Polyner f l a s k


Chart Recorder

-Filter •Pump metering control

Fraction Collector •electric circuit hydraulic c i r c u i t

Figure 1. : Schematic of the core flood apparatus

5 MINUTE VALUES

MAXM

100 200 CONCENTRATION

300

Figure 2. : Effect of pH and time on turbidity measurements for polymer concentration


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We note that there is a constant shift in the curve for different mixing times. Experiments were run for various mixing times, and the maximum concentration was observed after about 25 minutes after which concentration started decreasing owing to settling of particles. If we are consistent in the use of either one of the curves the final results are not affected. The inset figure shows the effect of p H on the calibration curve. It is worthwhile noting that, for the range of hydration pH we are interested in, the concentration measurements are independent of the hydration pH.


Flow Tests . One foot long sand packs using Wilmington oil field unconsolidated sand were prepared for each of the flow tests. Porosity and permeability of all the sand packs were within 30-35% and 100-300 md, respectively. A l l core packs were evacuated to about 1 mm of mercury (Hg) before saturating them under gravity to assure complete water saturation. Table III gives the core and fluid properties for the flow tests. The properties of the cores were chosen so that they are close to the field conditions reported by Krebs(15). Table H I . Core and Fluid Properties Run

Polymer Pore Volume

Porosity( 9.0 and the polymer was stored for a few days before being injected into the core. In the next run, a core pack was saturated with 8.6 cp (at 50° C) Rangerzone crude oil and water flooded to residual oil saturation. Polymer flood was then initiated and about 1.2% of the original oil in place (OOIP) was recovered. The results are shown in Figure 4. The pressure profiles show behavior essentially similar to the previous run except that the pressure drop across the core increased to 100 psi within 4 P V of injection of polymer. The steady state values of p H and viscosity were 7.0 and 0.7 cp. respectively. The oil ganglia retained in larger pores resisting displacement probably reduced the amount of polymer adsorbed and reduced the number of pores that the polymer molecules needed to seal off in order to block the core. This could explain the more rapid plugging of the core. Effluent p H and viscosities remained much lower than influent values. Figure 5 shows the results of the run performed using a surfactant slug. For this purpose, a 0.02 P V slug of 40%(v/w) detergent alkylate sulfonate surfactant(DAS), synthesized by the Morgantown Energy Technology Center of the U.S. DOE and from the waste products of the detergent industry, was injected into a water-flooded core stabilized at an effluent p H of 7.0 and viscosity of 0.7 cp, and the slug was displaced by a 300 ppm polymer solution. Tertiary oil recovery of 4.6% OOIP was obtained which is much higher than the run without the surfactant. This confirms the observations of Williams(ll) who obtained higher oil recoveries with dilute polymer solutions in the presence of surfactant but with anomalous pressure behavior. Pressure drop across the core

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OIL-FIELD CHEMISTRY

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100

T 10

INFLUENT POLYMER p H « 8 26

80

"BRINE INJECTION


PH

, INFLUENT POLYMER VISCOSITY* 113cp ^ ^ VISCOSITY^

2i v

DIFF- PRESSURE

0

4 PORE VOLUME

6

II

Figure 3. : Effluent Profiles for brine saturated Wilmington sand 100 _ INFLUENT POLYMER pH- 8 8 80

• 60 AP(ptl) 40 -15 T INFLUENT POLYMER / i - H 2 c p 1

VISCOSITY

20-10 -05

PJFF PRESSURE. I 2 PORE VOLUME

0

Figure 4. : Effluent Profiles in residual oil-brine saturated Wilmington sand



12. KIKANI AND SOMERTON


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increased to 148 psi before 2 P V were injected indicating plugging. The pressure behavior in this run is slightly counter-intuitive because one would expect that the breaking up of the oil ganglia by the surfactant should have delayed the pressure increase until plugging by the polymer occurred. This could be explained by rock-polymer-surfactant interactions. The polymer probably acts as a sacrificial agent adsorbing on the grain surfaces and thus, reducing the loss of surfactant. Somasundaran(17,18) has observed such behavior for studies with kaolinites where the surfactant adsorption is considerably reduced in the presence of polymer solution. This would cause the low tension flood to be more effective, yielding higher recoveries. In fact, it is the Capillary number which controls the residual oil saturation. A n increase in capillary number reduces the residual oil saturation. The capillary number is directly proportional to the flow velocity and is inversely related to the interfacial tension. Since preferential adsorption of polymer is suspected, the surfactant acts more effectively to reduce the interfacial tension which increases the capillary number. Another way of getting higher capillary numbers is by increasing the flow velocity. Note that, although the pressure drop in the above run was high the velocity was fairly low and was kept constant thoroughout the run. Thus, the velocity did not contribute to the increase in the capillary number. In-situ emulsion formation, as proposed by Kamath et al(19), with DAS surfactants may cause higher pressure drops across the core. This is because of the blocking tendency of the emulsion which has lower mobility. This could explain the earlier plugging of the core compared to other runs. Effluent pH and viscosity showed behavior similar to the previous runs. It is worthwhile noting here that such pressure drops were not manifested by face plugging of the core near the entrance. This was confirmed by simultaneously monitoring the pressure at the inlet end of the core as well as the differential pressure across the two pressure taps located about 1 cm. from each end of the core. The inlet end pressure transducer showed reasonably low pressures throughout the run for each experiment. Low effluent pH, seen consistently in all the flow tests, may be due to Na /H exchange which could release hydrogen ions to the flowing fluid and subsequently reduce its pH. This effect has been observed earlier by Somerton, et al(20) in their study of San Joaquin Valley(Kern Front and Midway-Sunset) cores. A reduction in pH may have increased polymer adsorption on clay minerals and may partly account for the high adsorption values observed. This is consistent with the observations of Michaels and Morelos(6) who postulated that the adsorption of polyacrylamide on kaolinite occurs via hydrogen bonding between the un-ionized carboxyl or amide groups on the polymer chains and oxygen atoms on the solid surface. Adsorption is hindered by electrostatic repulsion between the negatively charged clay surfaces and the ionized carboxyl group on the polymer. The adsorption of polymer is thus favored by the reduction in the degree of carboxylate ionization which occurs on reduction of pH. Expecting a major role particle size distribution and of clay minerals in the anomalous pressure behavior and high adsorption of polymer in the earlier tests, another run (Fig. 6) was carried out without the clay size sand particles (

Retention Behavior of Dilute Polymers in Oil Sands - American

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