Improving the Foam Performance for Mobility Control and Improved

The liquid drainage rate was used in this study as a measure of the foam ..... at the 2001 SPE Annual Technical Conference and Exhibition, New Orleans...
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Ind. Eng. Chem. Res. 2004, 43, 4413-4421

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Improving the Foam Performance for Mobility Control and Improved Sweep Efficiency in Gas Flooding T. Zhu,* D. O. Ogbe, and S. Khataniar Department of Petroleum Engineering, University of Alaska Fairbanks, 425 Duckering Building, P.O. Box 755880, Fairbanks, Alaska 99775-5880

Foams are used for mobility control in enhanced oil recovery operations. However, a typical oil-field application of foam suffers from such problems as early CO2 breakthrough, poor sweep efficiency, and inefficient oil recovery due to viscous fingering resulting from a low gas-phase viscosity and an unfavorable mobility ratio. The objective of this experimental investigation was to study the use of additives to enhance foam properties and to improve the in situ generation of foams for enhancing the gas-flood sweep efficiency. Foam generation was achieved by flowing nitrogen, surfactant, and various foam-enhancing additives through a sandpack. Some of the parameters affecting the foam performance were the polymer concentration, type of surfactants and their concentrations, aqueous-phase salinity and pH, and effect of flow rate (or shear rate). The performance of polymer-enhanced foams (PEFs) was much better than that of conventional foams. Poly(acrylamide) polymers were used as an additive. Higher foam resistance and longer foam persistence were achieved by using relatively low concentrations of polymers. The studies also showed that the foam performance was significantly improved over a broad range of polymer concentrations. A number of other investigators have shown that foams are severely affected in the presence of oil. This is especially true of lighter or less viscous oils, and the destabilizing effect is magnified with a higher salinity aqueous phase. PEFs with a low-salinity aqueous phase showed improvement in foam stability. The effective viscosities of PEFs were higher than those of conventional foams with a high-salinity aqueous phase and the presence of lighter oils. Further, PEFs reduced the negative impact of oils on foam mobility. Of the surfactants studied, R-olefin sulfonates were found to be stable with high-salinity brines as well as compatible with polymer additives. Other surfactants, including amine oxide surfactants, were also studied and showed unusually high foam resistance and stable properties. 1. Introduction Carbon dioxide (CO2) flooding has been used as a commercial process for enhanced oil recovery (EOR) since the 1970s because significant amounts of residual oil can be recovered by CO2 injection.1-3 On the basis of 2002 production figures,3 the U.S. oil production from gas-injected EOR was estimated at 297 476 bbl/day or approximately 44.5% of the total EOR production in the U.S. However, many, if not all, gas-flooding field projects are often hampered by early CO2 breakthrough, poor sweep efficiency, and inefficient oil recovery due to viscous fingering resulting from a low gas-phase viscosity and an unfavorable mobility ratio. Poor sweep efficiency may also be caused by stratification or fracturing. Reservoir heterogeneity, particularly layering, is one of the most important factors affecting the CO2 flood performance. CO2 mobility, the ratio of effective rock permeability to the CO2 viscosity, is usually high relative to that of other reservoir fluids, and the resulting unfavorable mobility ratio enhances fingering that initially results from reservoir heterogeneity or gravity override. In more heterogeneous reservoirs, CO2 floods some layers more easily because of differences in porosity and permeability. In this case, CO2 breaks through faster to the producing wells. More CO2 is then required over the lifetime of the flood, which * To whom correspondence should be addressed. Tel.: (907) 474-5141. Fax: (907) 474-5912. E-mail: [email protected].

leads to higher CO2 costs per barrel of oil recovered and greater CO2 handling and recycle expenses. A need to control gas-phase mobility has resulted in many studies of processes that may alleviate the adverse mobility ratios that produce viscous fingering. One potential solution for reducing the gas mobility is the use of foam. In fact, it has been shown that foaming gas is a promising technique for achieving mobility control and diverting injected fluid to low-permeability strata within heterogeneous porous media.4,5 Foams have several advantages. Gas-phase mobility can be significantly reduced by foam.6 Foam reduces the gas mobility by liquid films trapping gas in the porous media and reducing the gas fraction available for flow.6,7 Foams are more efficient than water (in a wateralternating-gas process) in controlling gas fingering. Also, foams can decrease the aqueous permeability by increasing gas saturation. In addition, the low surfactant concentrations required to produce foams result in a potentially cost-effective process. Finally, the foam systems are reversible. Foam is best suited where total blockage is not desired or feasible. For foam applications, the surfactant must be capable of producing foams that are effective in controlling the gas mobility and generating chemically stable foams in contact with reservoir brines, crude oil, and reservoir minerals. Gas mobility in the presence of foam depends on the foam bubble size. The bubble size, on the other hand, may vary with the permeability and porosity of the porous media, the surfactant type and concentra-

10.1021/ie034021o CCC: $27.50 © 2004 American Chemical Society Published on Web 06/15/2004

4414 Ind. Eng. Chem. Res., Vol. 43, No. 15, 2004 Table 1. Chemical Description of Surfactants Selected for Foam Performance Tests name

chemical description, abbreviation

hydrophobe

Enordet AOS 1416 Enordet AOS 12 Enordet ES 1215-3S BW9125AT Alipal CD 128 Neodol 45-13 CD 1050 NP 9.5 Calsoft L-40 AKZO 9603 AKZO 9603

AOS, AOS 1416 AOS, AOS 12 ethoxylated sulfate, ES 1215-3S ethoxylated nonylphenol, NP 6.5 ethoxylated sulfate, CD128 ethoxylated alcohol, Neodol 45-13 alkyl phenol ethoxylate, CD 1050 ethoxylated nonylphenol, NP 9.5 linear alkyl sulfonate, L40 AMS AMS

C14-C16 C12 C12-C15 nonylphenol C8-C10 alcohol C14-C15 unknown nonylphenol unknown unknown unknown

tion, and the velocity of liquid and gas. Studies6,8 have shown the use of foam for mobility control in gas flooding. However, many of the original questions about foam flooding and the displacement efficiency of the process still remain unanswered. These include how foam interacts with the oil, how much oil could be recovered through this process, and how the performance of foams could be improved. The key to success of the foam application is to identify the conditions under which it could be utilized to economically improve the sweep efficiency and oil recovery in gas flooding. The objective of this study was to investigate the use of additives in conjunction with a surfactant solution to improve foam properties. An additive in the foam aqueous phase may improve foam stability and apparent viscosity.8 Both of these factors are important for improving mobility control. Also, an additive might improve surfactant tolerance to reservoir brines. Foams tend to be less stable in contact with crude oil, and additives could reduce the destabilizing effect of oil. All of these factors would allow for reducing costs, improving the ability of the surfactant solution to generate foams in situ, and providing a more effective foam for control of gas mobility. In this study, the effects of the aqueous solution salinity, aqueous-phase pH, and presence of oil on both conventional foams and polymerenhanced foams (PEFs) are briefly discussed. Foam is generated by flowing nitrogen, surfactant, and additives through a sandpack. The foam quality is measured from the effluent stream to study the effects of the foam additives. 2. Experimental Procedure All experiments were conducted at ambient temperature (21 °C) and atmospheric pressure. Foams were produced by flowing nitrogen gas and surfactant solutions through a foam generator. The foam generator was a sandpack in a 19-cm-long and 0.85-cm-i.d. stainless steel tube. The tube was packed with 20-40 mesh sand, and the pore volume was about 4.1 cm3. A schematic of the experimental apparatus is shown in Figure 1. The surfactants used in this study are listed in Table 1. Nitrogen flow was metered through a Brooks model 5850 mass flow controller at a constant flow rate of 60 cm3/min. The surfactant solution was injected by a syringe pump at a rate of 6.67 cm3/min. These flow rates produced a 90% quality foam measured at atmospheric pressure. The foam quality is defined as the fraction or percentage of the total volume that is gas. A fluid frontal advance rate is about 309 cm/min, which produced foam from the generator exhibiting a consistent evenly textured foam size (the foam texture is the bubble size distribution in a foam). Foam samples were collected only after flowing a surfactant solution and nitrogen gas

Figure 1. Foam generator.

for an extended time interval to allow for fluid flows and pressures to equilibrate in the foam-generating system. The foam stability was measured by filling a 100 cm3 buret with foam at ambient temperature and atmospheric pressure and then periodically measuring liquid drainage. The liquid drainage rate was used in this study as a measure of the foam stability. The foam stability was defined as the time required for 80% of the liquid to drain from the foam. Some investigators9 use the time value for half of the liquid drainage. However, the time for 80% provides a larger value without sacrificing measurement accuracy. The apparent viscosity, another important foam property, was determined by measuring the differential pressure across the foam generator at a constant foam flow rate. The term of apparent viscosity is used because a foam behaves as a non-Newtonian fluid. The apparent viscosity of the foam at any point is defined as the ratio of shear stress to shear rate, and it varies with the shear rate. From the flow rate (Q) of the foam and the differential pressure (∆P) across the sandpack, mobility (λ) of the foam can be evaluated from

λ)

Q/A ∆P/L

(1)

where A is the cross-sectional area of the sandpack and L is the length of the sandpack. Because the permeability (k) of the sandpack is known, the apparent viscosity of the foam can be determined from

µ ) k/λ

(2)

Ind. Eng. Chem. Res., Vol. 43, No. 15, 2004 4415

The foam resistance is also determined in the experiments. The foam resistance is defined as the pressure drop measured across the foam generator with the presence of foam divided by the pressure drop for the same system without the presence of foam. Sandpack permeability was measured by flowing deionized water through the sandpack and measuring the differential pressure with a water manometer. For the sandpack used in these experiments, the permeability was approximately 100 darcys. Prior to each experiment, the sandpack was flushed with several liters of deionized water to remove all contaminants from the previous experiment that might affect the foam generation process. The apparent viscosity of foams depended on the foam cell size and pore size. The cell size is also one of the properties that influences foam stability. Many factors determine the cell size, including the pore size of the foam generator. Because foams are pseudoplastic, shear rates have a strong effect on the foam apparent viscosity. When sandpacks with similar permeability were used and the same flow conditions were maintained, foam samples could be compared at the same conditions. Salts with divalent ions were included in the aqueousphase solutions for experimental tests. Most of the foam tests were conducted with two aqueous-phase salinities. All salinities were measured by weight. The lower salinity aqueous phase, containing 3% NaCl, 0.38% CaCl2, and 0.12% MgCl2, will be referred to as a 3% brine. A high-salinity brine with 12% NaCl and 0.2% CaCl2 will be referred to as a 12% brine. Other aqueousphase salinities used in the experimental tests will be specified in the text. A Millipore purification system was used to purify water used in surfactant solutions. Unless the surfactant concentration is specified in the text, active surfactant concentrations are 0.1 wt % of the aqueous phase. 2.1. Reproducibility of Experimental Data. Reproducible experimental data were important for comparing the results and showing the effects of different factors on the foam performance. In this study, multiple tests were made to determine a statistical average for each test condition. Generally, each test was made by taking duplicate foam samples and averaging the results. Tests were repeated if the duplicate samples varied significantly. Test conditions could change over extended time intervals if, for example, the sandpack permeability changed. This would influence foam production and affect mobility or stability results. Some tests were repeated at different time intervals to show data reproducibility. 3. Results and Discussion The results obtained from the experiments are discussed in the following sections. 3.1. Effect of the Aqueous-Phase Salinity and Surfactants. A number of variables affect the foam performance.10 Aqueous-phase salinity and composition probably constitute the primary criteria for selection surfactant for foam application. Duerksen11 observed that increasing the salt concentration in the brine adversely affects the foam performance. The foam performance for a number of selected surfactants (see Table 1 for surfactant information) in an aqueous phase with a 3% brine and freshwater is shown in Figure 2. Arrows show the results when the salinity concentration was changed. All aqueous-phase

Figure 2. Foam performance of selected surfactants without salt and a 3% brine aqueous phase.

Figure 3. Foam performance of selected surfactants without salt and a 12% brine aqueous phase.

solutions contained 0.1% of the surfactant. In all cases, the apparent viscosity of the foams was adversely affected by increasing the salinity (as shown in Figure 2, mobility of the foams was increased by increasing the salinity). For the 3% salinity aqueous phase, the CD 128 and R-olefin sulfonate (AOS) surfactants showed approximately equal in apparent viscosities and their performances were superior to those of the other surfactants. Little change in the foam stability was observed except for the AOS surfactants that showed increased stability. For the 3% brine aqueous phase, AOS 1416 was superior in foam stability to the other foams. Figure 3 shows the results for a number of surfactants with 0% and 12% brine aqueous phases. Again, arrows show the results when the salt concentration was changed. As shown in Figure 3, the apparent foam viscosity was adversely affected by the high-salinity brine except for the CD 1050 surfactant, which showed a small improvement in mobility. For the high brine concentration, ES 1215-3S was slightly better than the other surfactants in providing resistant foam. However, the stability of ES 1215-3S was less than that of the other surfactants. Of all of the surfactants, AOS 12 was the most stable in the high-salinity brine and produced higher foam resistance, except for the ES 1215-3S surfactant. On the basis of the previous results, the AOS surfactant foaming agents were the most stable surfactants

4416 Ind. Eng. Chem. Res., Vol. 43, No. 15, 2004

Figure 4. Comparison of the foam performance with various polymer additives.

tested. For the AOS 1416 surfactant at 0.1% concentration, phase separation occurred with approximately an 8% brine aqueous phase. This surfactant performed well with low salinities. For high aqueous-phase salinities, the AOS 12 surfactant was chosen for testing because it was compatible in aqueous solutions of high salinity. According to other investigators,12 AOS surfactant foams are more stable for high-temperature applications. Therefore, these surfactants were used extensively in this study. 3.2. Effect of Polymers on the Foam Stability and Resistivity. The effect of polymer additives on the foam performance was examined by adding several water-soluble polymers, including xanthan, cellulose, and poly(acrylamide) polymers, to an aqueous-phase solution with 0.1% AOS surfactant. Aqueous-phase polymer concentrations of 0.1% were measured by weight. FP3430 was a high molecular weight (MW) poly(acrylamide) polymer, while FP1230 was a low-MW poly(acrylamide) polymer. Two cellulose polymers and a biopolymer (xanthan) were included. The cellulose polymers were hydroxyethyl cellulose (HEC) and carboxymethyl HEC. Experimental results are summarized in Figure 4 for aqueous phases with and without brine. A data point for brine is indicated by the head of an arrow in Figure 4. Several interesting relationships are shown in Figure 4. For the cases without brine (i.e., data points at the tail ends of the arrows), the polymer additives increased both the foam stability and foam resistance. This is seen in Figure 4 as an increasing liquid drainage time and a decreasing mobility of PEFs. At a polymer concentration of 0.1%, the PEFs were more stable and had a higher apparent viscosity (or lower mobility) than a conventional foam (i.e., without polymer). The cellulose polymers and xanthan biopolymer were the least effective for increasing the apparent foam viscosity (Figure 4). However, xanthan improved the foam stability significantly. Of the polymers tested, poly(acrylamide) polymers (FP3430 and FP1230) produced the highest foam resistance (lowest mobility). When brine was added to the surfactant solution (data points at the heads of the arrows, Figure 4), there was only a moderate decrease in the foam resistance (i.e., an increase in mobility) with all of the polymers. For the poly(acrylamide) polymers, as shown in Figure 4, the foam stability was adversely affected by salts in the

Figure 5. Comparison of polymer solution viscosities with and without brine (viscosities were measured at the same shear rate of 23/s).

Figure 6. Comparison of the performance for different poly(acrylamide) polymers.

aqueous phase. However, for the cellulose and xanthan polymers, the foam stability was improved by salts, with cellulose polymers improving the foam stability slightly and xanthan improving the stability significantly. Xanthan polymers are compatible in solutions with a wide pH range, many salts, and most water-soluble solvents. These polymers are often used in high-salinity reservoirs. As shown in Figure 5, brine nearly doubled the xanthan polymer solution viscosity. Probably, increasing the viscosity of the brine aqueous phase was responsible for improving the stability of the xanthan foam. The effect of MW on the foam performance was examined by testing four different MWs of poly(acrylamide) polymers (FP1230, FP3220, FP3330, and FP3430). As shown in Figure 6, foam properties changed with the different polymers. The higher MW polymer was more effective at increasing the foam resistance and stability with freshwater aqueous phase. At the polymer concentration of 0.1%, the FP3330 polymer [the second highest MW poly(acrylamide)] produced the most resistant foam. The low-MW poly(acrylamide) (FP1230) was also effective in increasing the foam resistance. The foam stability, however, was greatly reduced by the presence of brine, with all of the foams having approximately the same drainage times. In addition, the foam resistance also decreased with the brine aqueous phase.

Ind. Eng. Chem. Res., Vol. 43, No. 15, 2004 4417

Figure 7. Comparison of the foam performance for different concentrations of FP3430 polymers (surfactant concentration was 0.1% AOS 1416 with no salt and 3% brine).

Other tests were conducted to measure the effect of the polymer concentration on foam properties. The concentration of FP3430 was varied with 0.1% surfactant in freshwater. As shown in Figure 7, the foam resistance increased rapidly, even with very low polymer concentrations. An improvement in the foam resistance was measured even with concentrations of 25-50 ppm of the polymer. Figure 7 also shows the effect of the polymer concentration with 3% brine in the aqueous phase. Without brine, the physical properties of 100 ppm of the polymer were approximately equal to the properties of a brine aqueous phase with 500 ppm of the polymer. Although the foam mobility was reduced by the presence of salt in the aqueous phase, the foam resistance remained high. The poly(acrylamide) polymers can significantly improve the foam performance with gas flooding. High foam resistance and greater stability can be achieved by using relatively low concentrations of these polymers. 3.3. Effect of the Surfactant Concentration on the PEF Performance. The effect of the surfactant concentration was measured for the foam performance with the AOS 1416 surfactant. The aqueous phase contained 500 ppm of the FP3330 polymer. Two cases, with and without salt, were studied. As shown in Figure 8, without salt in the aqueous phase, no significant change was observed in foam properties with concentrations between 250 and 1000 ppm. However, the foam stability decreased as the surfactant concentration increased from 1000 to 5000 ppm. The foam stability was improved by lowering the surfactant concentration. Over the studied range of 250-5000 ppm of AOS, the surfactant concentration had little effect on the foam mobility. For the case with the 3% brine aqueous phase, the foam stability and resistivity decreased with lower surfactant concentration. Tests were also conducted at different surfactant concentrations (AOS 12) in brine (3% brine) without and with 1000 ppm of the poly(acrylamide) (Alcoflood 1275). Figure 9 compares surfactant concentrations ranging from 250 to 5000 ppm. Without the polymer additive, increasing the foam resistance and stability was measured for higher surfactant concentrations up to 1000 ppm. There was essentially no change in the foam mobility and stability with a surfactant concentration increased from 1000 to 5000 ppm. This indicated that

Figure 8. Comparison of foam properties with changing AOS 1416 concentrations (all solutions contained 500 ppm of the FP3330 polymer).

Figure 9. Comparison of foam properties with different surfactant concentrations with and without polymer in a 3% brine aqueous phase.

there was no improvement in foam properties at the higher surfactant concentration. Also, as shown in Figure 9, greater foam resistance and stability were measured for the PEFs. The foam stability increased with increasing the surfactant concentration up to 5000 ppm. No optimum surfactant concentration was found with the PEF. Figures 8 and 9 indicate a general pattern of the foam mobility with the surfactant concentration. As the surfactant concentration is increased, the mobility starts to decrease and then decreases at an increasing rate.6 Eventually, at much greater concentrations, the mobility reaches its lowest values, beyond which it cannot be lowered further by this surfactant.6 This phenomena can be explained by the surfactant chemical stabilities as follows. At low concentrations, surfactants concentrate in an adsorbed monolayer at a surface that may provide a stabilizing influence in foams. At higher concentrations, micelles start to form. When it reaches the critical micelle concentration (cmc), micelle formation becomes significant. At cmc, a maximum reduction in the surface tension occurs; thus, the mobility of the foam reaches the lowest values. 3.4. Effect of the pH on the Foam Performance. Another condition that affects the foam performance is

4418 Ind. Eng. Chem. Res., Vol. 43, No. 15, 2004 Table 2. Foam Performance of PEFs with Different pH Aqueous Phases surfactant

additive

brine (%)

pH

mobility (darcy/cP)

drainage time (min)

quality (%)

0.1% AOS 12

0.1% FP1230

3

7.13

7.2 7.2 7.2 7.4 7.7 7.7 8.2

37 40 41 40 36 36 30

90.1 90.2 90.2 90.0 90.0 90.0 89.9

4.06 2.02

Figure 10. Effect of the permeability on foam properties (12% brine aqueous phase).

the pH of the aqueous phase. Some reservoirs have acidic oils or gases, such as H2S, which may reduce the pH of the foam aqueous phase. For CO2 floods, the aqueous-phase pH will be lowered by the presence of carbonic acid. The brine pH may be reduced to about 4 because of CO2 equilibrium. The effect of the pH on the foam performance was investigated by adjusting the aqueous-phase pH. Prior to pH adjustment, the aqueous-phase (0.1% AOS 12 and 0.1% FP1230 in a 3% brine) pH measured 7.13. Two different acidic phases were tested for the foam performance. For a pH 4.06 solution, the aqueous-phase pH was adjusted using acetic acid. Hydrochloric acid was used for a pH 2.02 solution. The results are listed in Table 2. As shown in Table 2, no significant change was observed in the foam performance with a lower pH of the aqueous phase. For the solution with a pH of 4.06 (the pH level for foams with CO2 as the gas phase), only a small decrease in the foam stability and resistivity was measured. The experimental results suggest that PEFs should also be applicable in acidic reservoir conditions such as CO2 flooding. 3.5. Effect of the Permeability and Flow Rate on Foam Properties. Foam properties depends on the geometry of the flow system and the foam flow velocity (Green and Willhite,10 pp 165-167). Experiments were conducted to show the effects of permeability in sandpacks and sandstone cores. Sandpacks with 20-40, 4060, 80-120, and 200-325 mesh sizes were used. Permeabilities of these sandpacks were approximately 130, 50, 13, and 3 darcys, respectively. In addition, tests using Bentheimer and Berea sandstone cores with permeabilities of approximately 1 and 0.2 darcys, respectively, were studied in this work. The aqueous phase contained 0.1 wt % of AOS surfactant with a 12% brine. The experimental results are shown in Figure 10. For comparable flow rates, there was essentially no change in the apparent foam viscosity for the sandpack perme-

Figure 11. Effect of the flow rate on foam properties.

abilities of 130, 50, and 13 darcys. However, for the less permeable sandpacks and cores, there was a strong relationship between the porous media permeability or pore size and the apparent foam viscosities. The less permeable 200-325 mesh sandpacks (3 darcys in permeability) had a significantly lower apparent foam viscosity at comparable flow rates. The influence of small pores on the apparent foam viscosity was also evident with low-permeability cores. For the Bentheimer sandstone cores with a permeability of 1 darcy, the foam viscosity was lower than that of the sandpacks at the same flow rate (Figure 10). For the Berea cores with a permeability of about 0.2 darcy, the apparent viscosity, again, was lower than that of the Bentheimer core, which is consistent with the trend of lower apparent foam viscosity for lower permeability porous media. The observed permeability dependence could be explained by the balance of lamellae generation, flow, and destruction in pores of different sizes. Heller et al.13 pointed out that the effect of the pore walls on the foam behavior will be significant if the pore size is smaller than 20 times the foam bubble size. This wall effect will result in the facts that the very smallest pores contain only liquid, the medium-sized pores contain predominantly trapped lamellae, the larger fraction contains moving lamellae, and the very largest pores (if present) are occupied by continuous gas.6 Experiments were also conducted to measure the effects of the flow rate on the apparent viscosity. The aqueous phase contained 0.1 wt % of AOS 12 surfactant in high- (12% brine) and low-salinity (3% brine) brines. PEFs were also used where the aqueous phase contained 0.1 wt % of a low-MW poly(acrylamide) polymer (FP1230). Changes in Darcy flow rates were obtained by adjusting nitrogen and surfactant solution flows and using tubes with different internal diameters of 0.559, 0.775, and 1.103 cm. The results of variable flow rates on the apparent foam viscosity are shown in Figure 11, where shear

Ind. Eng. Chem. Res., Vol. 43, No. 15, 2004 4419 Table 3. Oils Used for Experimental Tests To Determine the Effect of Oil Contact on the Foam Performance oil abbrvn paraffin oils heptane dodecane tetradecane mineral oil crude oils North Burbank Unit, Osage Co., OK Government Wells North, Duval Co., TX Hepler Field, Crawford Co., KS

3

12

viscosity (cP) (24 °C)

C7 C12 C14 MO

0.4 1.5 2.0 141

NBU GWN Hepler

Table 4. Comparison of Conventional Foam Properties with 3% and 12% Brine in Contact with Different Oils brine (%)

API gravity

39.5 26.1 20.1

Table 5. Comparison of PEF Foam Properties with 3% and 12% Brine in Contact with Different Oils

oil

apparent viscosity (cP)

drainage time (min)

brine (%)

no oil NBU C7 GWN C14 MO no oil NBU C7 GWN C14 MO

6.9 3.9 6.7 6.7 6.9 7.3 7 1.2 2.3 1.7 5.3 7.3

26 8 23 34 32 47 58 1 1 1 19 91

3

thinning changed the apparent foam viscosity; i.e., it decreased with increasing velocity. This is consistent with the pseudoplastic nature of the foams. As expected, the PEFs provided higher foam resistance when compared to the conventional foams. However, the effects of shear thinning dominated the apparent viscosities. Shear thinning should be advantageous for injection of pregenerated foams. High shear conditions near the wellbore should produce low viscosities and, as a result, allow for low injection pressures. As the foams penetrate into the reservoir away from the wellbore, lower shear conditions should increase the effective foam viscosities with greater mobility control. 3.6. Effect of Oil on the Foam Performance. Several investigators12,14 have reported the destabilizing effects of oil on foam, although some studies15 have shown a positive effect on the foam mobility and stability in the presence of crude oils. Tests were conducted to examine the effects of different oils. Nitrogen, surfactant solution, and oil were injected simultaneously through the sandpack prior to foam generation. Oil was injected by a syringe pump at a rate of 10% of the aqueous-phase volume. This produced oil/ foam mixtures with an oil concentration that was 10% of the aqueous-phase volume. The effect of oil MW and viscosity was investigated by using different oils. Heptane (C7), tetradecane (C14), mineral oil (MO), crude oil from North Burbank Unit of Oklahoma (NBU), and crude oil from Government Wells North of Texas (GWN) were used as the oil phases with viscosities of 0.4, 2.0, 140, 7, and 35 cP, respectively (Table 3). AOS (AOS 12) was used as the foaming surfactant for conventional foams and PEFs. A low-MW poly(acrylamide) polymer, FP1230, was used as the polymer additive. Results for different salinity aqueous phases, 3% and 12% brines, also are shown in Tables 4 and 5. 3.6.1. Conventional Foam Performance with Oil Contact. With a 3% brine aqueous phase, conventional foams were compared for contact with different oils (shown in Table 4). Only the lightest crude oil, NBU

7.0 35 63

12

oil

apparent viscosity (cP)

drainage time (min)

no oil NBU C7 GWN C14 MO no oil NBU C7 GWN C14 MO

13.9 13.3 13.5 14.1 13.9 14.1 15.2 9.4 10.4 11.4 15.2 15.4

40 47 43 51 51 70 82 44 45 51 68 111

crude, significantly reduced the foam apparent viscosity and foam liquid drainage time. In fact, the higher viscosity oils such as tetradecane (C14) and GWN crude oil improved the foam liquid drainage time, while the highest viscosity mineral oil significantly increased the foam liquid drainage time. The presence of NBU crude, however, reduced both the foam apparent viscosity and stability. NBU crude is a light oil with an API gravity of 39.5. The larger concentration of lighter components in NBU crude may have caused the foam to collapse and, as a result, reduced the foam performance. With a 12% brine aqueous phase, oil contact more adversely affected the foam performance. No foam was produced when contacted by NBU crude, C7, and GWN crude oils, as shown in Table 4. In those cases, the foams collapsed immediately after contact with the oil during the tests. When contacted with high-MW oils, such as C14 and mineral oil, the adverse effect of oil on the foam performance was reduced. In fact, the high-viscosity oil increased the foam stability, while the less viscous oil (C14) reduced the time for liquid drainage. 3.6.2. PEF Performance with Oil Contact. Adding polymer to the aqueous phase improved the foam performance and reduced the adverse effect when contacted with oil for both the low- and high-salinity aqueous phases. Compared with a conventional foam in the low-salinity case (3% brine), the PEF increased the apparent viscosity and liquid drainage time significantly (as shown in Table 5). The presence of oil produced almost no change in the measured foam apparent viscosity. In fact, for the lower salinity aqueous phase, oil contact improved the foam liquid drainage time slightly, with the high-viscosity oil resulting in more stable foams. In the high-salinity case (12% brine), the PEF also increased the apparent viscosity and liquid drainage time significantly when compared with the conventional foam. The tests showed that PEF contact with C14 and MO had virtually no effect on the apparent viscosity of the foam. The tests showed that the apparent viscosity

4420 Ind. Eng. Chem. Res., Vol. 43, No. 15, 2004

Figure 12. Effect of the C14 oil concentration on the foam liquid drainage time.

and the liquid drainage time of the PEFs were reduced by low-viscosity oils. However, the impact of low oil viscosity was less with the PEF. The observed trend indicated that decreasing the oil MW resulted in an increasing adverse effect on the foam performance. Heavier and more viscous oils improved the foam stability and apparent viscosity; conversely, lighter oils destabilized foam films. The effect of the oil concentration was measured by using different C14 concentrations with the injected aqueous phase. The aqueous-phase solutions contained 0.1% of AOS 12 surfactant and 0.1% of FP1230 polymer in 3% brine. The tetradecane concentration was varied in 2, 10, 20, and 40% of the aqueous-phase volume. The tests showed that the oil concentration had virtually no effect on the apparent viscosity of the foam. However, there was an increasing relationship of the foam liquid drainage time with the oil concentration. Figure 12 shows the time for 80% of liquid drainage for PEF with different oil concentrations. As shown in Figure 12, greater foam stability was measured with higher oil concentration. Tests were also performed to evaluate two experimental surfactants in a 3% brine aqueous phase, AKZO 96003 and 96007. These surfactants, which are amine oxide surfactants (AMSs), are good foaming agents with some unique properties. One interesting property of these surfactants is the comparatively high viscosity of the aqueous-phase solution even at low concentrations. Also, the surfactant is salt-tolerant and the aqueousphase viscosity increases with increasing salinity. These are desirable foam characteristics for gas-flooding applications. AMS foams without and with a poly(acrylamide) polymer additive (FP3430) were tested for stability and mobility. As shown in Figure 13, without polymer additive, oil (C7) contact severely reduced the foam stability and apparent foam viscosity. The PEF, however, significantly increased the apparent foam viscosity (lowered mobility as shown in Figure 13) and reduced the adverse effect of oil contact on the foam stability. In many cases, surfactant mixtures do not improve foam properties. However, when a 0.1% concentration of a 12-carbon AOS surfactant (AOS 12) was mixed with 1% AMS in a 3% brine aqueous phase, the foam drainage time or stability increased significantly from about 700 min to over 1500 min. Also, there was a small improvement in the foam resistance with the cosurfactant foam. When the cosurfactant mixture was in-

Figure 13. Comparison of the AKZO 96007 foam and PEF with and without heptane contact in a 3% brine.

Figure 14. Comparison of AKZO 96003 and AOS surfactant foams with and without polymer enhancement and the effect of heptane contact in a 3% brine.

creased to 0.2% AOS 12 with 1% AMS, the liquid drainage increased by nearly a factor of 2. Comparison tests were made for the AKZO 96003 and AOS 12 surfactant foams, each foam with the same surfactant concentration in a 3% brine aqueous phase. PEFs of each surfactant were also compared, and the performance of each foam was measured when contacted by heptane. As shown in Figure 14, the AMS surfactant (AKZO 96003) was superior in performance when the foam was not in contact with oil. However, oil contact severely reduced the performance of the AMS surfactant foam, whereas oil contact had only a limited impact on the AOS surfactant foam. This indicated, when the foams were contacted by oil, that AOS foams were superior to the AMS foams. As shown in Figure 14, the addition of polymer with the AMS foam improved the foam mobility and reduced the effect of oil contact. The AOS surfactant foam with polymer was superior to the AMS surfactant foam in contact with oil. Polymer enhancement of the AOS surfactant foam produced a small increase in the stability at the low oil-phase concentration. The tests again indicated that the addition of polymer improved the foam performance and reduced the adverse effect of oil contact.

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The AMS foams may be useful for some foam applications in dry gas reservoirs where the foams are not in contact with oil, such as reducing leakage from gas storage reservoirs. However, the AMS foams performed poorly when in contact with oil. The AOS surfactant was superior for oil reservoir applications. 4. Conclusions This study was designed to screen surfactants for foams in gas flooding. In addition, it was intended to study the effect of using polymer additives. Within the framework of this study, the following conclusions are derived: (1) Aqueous-phase salinity dramatically affected foams and must be considered in formulating the foaming agent and additives. AOS surfactants were tolerant to higher salinity brines and compatible with polymer additives. (2) The performance of PEF foams was much better when compared to that of conventional foams. This study showed that the foam performance was significantly improved over a broad range of polymer concentrations. (3) The application of PEFs for mobility control of gas flooding was affected by crude oil presence. This work showed that lighter crude oils resulted in less stable foams, while heavy oils increased the foam stability. The polymer additives, however, improved the performance of foams contacted by oils. (4) When foam is not contacted by crude oil, a cosurfactant mixture (0.2% AOS 12 and 1.0% AMS concentration) provided the highest foam performance of all of the aqueous phases tested. (5) To generate foam, the optimum surfactant concentration for stable foams should be near the cmc. There was no improvement in foam properties at higher surfactant concentrations. (6) Foams are characterized by shear thinning. At low shear rates, foams have high resistance factors. For the foams tested, the foam resistance generally increased with increasing rock permeability. The ability of foams to provide high foam resistance in higher permeability sands would be useful in suppressing fluid channeling in fractures and high permeability channels. Acknowledgment This work was supported by the U.S. Department of Energy under Contract DE-AC22-94PC9 1008. The authors thank the Department of Energy for providing financial support for this work. The authors also thank A. Strycker, C. J. Raible, and K. Vineyard for their input.

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Received for review July 25, 2003 Revised manuscript received April 4, 2004 Accepted April 16, 2004 IE034021O