Article pubs.acs.org/EF
Effect of Alkaline Preflush in an Alkaline-Surfactant-Polymer Flood Krishna Panthi and Kishore K. Mohanty* Department of Petroleum and Geosystems Engineering, The University of Texas at Austin ABSTRACT: An ultralow interfacial tension alkali-surfactant-polymer formulation was developed for a sandstone reservoir. Phase behavior was studied with the reservoir oil at different water−oil ratios and varying salt/alkali concentrations. The rheology of the resulting microemulsion phases was measured with and without polymers. The surfactant formulation was tested with a field core and an out-crop core, with and without an alkaline preflush. Waterflood recovered about 48% of the oil in place and reduced the oil saturation to 35% for the field core. The tertiary ASP injection in the field core without alkaline preflush yielded 80% cumulative oil recovery; the recovery increased to 85% in the same core (and the same surfactant formulation) if the alkaline preflush was used. The oil recovery in the out-crop core with the alkaline preflush was 94%. Alkaline preflush increases the core salinity to the optimum salinity of the surfactant formulation before the surfactant slug.
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INTRODUCTION Waterflood recovers about a third of the oil from petroleum reservoirs because of capillary trapping and large-scale bypassing due to permeability heterogeneity. In the U.S., about 168 billion barrels of oil have been recovered, but about 377 billion barrels have been left behind in known reservoirs.1 Tertiary recovery techniques such as chemical flooding, miscible gas displacement, and thermal recovery are needed to extract a part of this remaining oil. Chemical flooding using alkali, surfactants, and polymers (alkaline-surfactant-polymer or ASP) is a flexible technique applicable to many reservoirs. Surfactants lower the oil/water interfacial tension to the order of 0.001 mN/m so that the viscous forces can overcome the capillary forces and mobilize isolated oil blobs.2 Alkali form soap with acidic crude oils and lower surfactant adsorption.3−5 Polymers increase the viscosity of the aqueous phase and reduce bypassing.6 Past phase behavior experiments have shown that many surfactants have a three-phase microemulsion (Winsor III) phase behavior at an intermediate salinity.7,8 The interfacial tension has an inverse correlation with the oil and water solubilization in the micremulsion phase.9 The interfacial tension is ultralow (about 0.001 mN/m) in these three-phase systems.10 Many new surfactants have been discovered for chemical flooding in the last 20 years. For example, the internal olefin sulfonate surfactants are stable in high temperature reservoirs.11 The propoxy and ethoxy sulfate and sulfonate surfactants are tolerant of high salinity.12 Large hydrophobe (CnH2n + 2, n > 20) surfactants with more than 20 propoxy and ethoxy groups have been synthesized and used in surfactant formulations13 for viscous oils. There was a successful field pilot of chemical flooding in Illinois in 1980s.14−16 There have been many pilots of polymer and ASP techniques in the Daqing field in China in the last twenty years, but chemical flooding is not applied routinely after waterfloods.17 The increased oil price in the last five years has increased the interest in ASP flooding, but there is no simple method to identify the chemicals needed for a particular oil reservoir. The transport of alkali, surfactants, and polymers through the reservoir rock is also not well understood. © 2013 American Chemical Society
Surfactant formulation development for a specific reservoir is a complex procedure. The phase behavior is studied with the field oil and brine for many surfactants. The surfactants are identified which give three-phase behavior at a salinity close to the reservoir salinity. Cosurfactant, alkali, and alcohol are often added to improve the phase behavior and avoid liquid crystalline phases.18,19 The polymer is then added to increase the viscosity of the aqueous phase for mobility control. All of the chemicals are checked for long-term chemical and thermal stability at the reservoir conditions. Coreflood experiments are then conducted in outcrop or reservoir cores to study the transport of all of the chemical constituents, adsorption, and oil recovery.9 This article outlines a chemical formulation development for a sandstone reservoir. The phase behavior with the reservoir oil was studied for many surfactant combinations. The results with the selected formulation are described below. The viscosity of the three-phase system with polymer was measured. Then waterflood and tertiary ASP floods were conducted in an outcrop core and a reservoir core. The effectiveness of the ASP flood with and without the use of an alkaline preflush is described below.
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EXPERIMENTAL METHODOLOGY
Chemicals. Commonly available chemicals were used in the surfactant formulation. Surfactants Tridecyl Alcohol Propoxy Sulfate (TDA−PO−SO4) and C20−24 Internal Olefin Sulfonate (C20− 24IOS) were obtained from Stepan chemical company. Polymer HPAM 3330 was obtained from SNF Floerger company. Its molecular weight was 8 × 106 gm/mol and the degree of hydrolysis was 25−30%. Sodium carbonate (Na2CO3) was used as the alkali. The injection (and formation) brine composition was approximated by 192 ppm potassium chloride (KCl), 19601 ppm sodium chloride (NaCl) and 1228 ppm sodium bicarbonate (NaHCO3), which is called the “synthetic injection brine”. The stock tank oil from the reservoir was used. Its density was 0.86 g/cm3 and viscosity was 12 cP at 59 °C, the Received: November 12, 2012 Revised: February 1, 2013 Published: February 5, 2013 764
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volume of the mixture of field brine and 2500 ppm HPAM3330. This polymer slug was followed by about 1 pore volume of synthetic injection brine. Then the core was cleaned and prepared, as described above. The second ASP flood was similar to the first ASP flood except for one difference. After the waterflood, an alkali preflush was injected for 0.4 PV before the injection of ASP slug. This slug consisted of synthetic formation brine, NaCl, and NaCO3. Coreflood 3 was conducted in the outcrop core; the procedure was similar to Core Flood 2. The core used in Core Flood 1 was cleaned in the following manner after the ASP flood: it was first injected with a 2 PV of brine followed by 2 PV of tetrahydrofuran (THF), which was further followed by 2 PV of chloroform, followed by 3 PV methanol, and flooded with about 10 PV of brine again. Injection of oil led to a high residual water saturation of about 49%. To lower the Swi, 1.5 PV of a viscous oil was injected and then 1 PV of 1:1 mixture of the viscous oil and the field oil, which was followed by 2 PV of the field oil. The core was then aged in oven at the reservoir temperature, 59 °C. This core was then used in Core Flood 2.
reservoir temperature. The total acid number of the oil was 2.04 mg KOH per gm of oil. Phase Behavior. Equal volumes of oil and 1 wt % surfactant solution were mixed in pipettes and sealed. They were equilibrated at the reservoir temperature and their phase volumes were observed. NaCl concentration was varied (in a series of pipettes) keeping the concentrations of KCl, NaHCO3, Na2CO3, and surfactant constant. The solubilization of the oil and water in the microemulsion phases was calculated from the phase volumes. The interfacial tension was estimated from the Huh equation.8 The phase behavior was studied as a function of water-to-oil ratio (WOR). Polymer (2500 ppm HPAM) was added to some of the phase behavior samples and the viscosity of the equilibrated phases was measured by an ARES rheometer. The viscosity was measured at shear rates ranging from 1 to 100 s−1. Core Material. Two reservoir core plugs were combined together to get a total length of 9.6 in.. This core mount is referred to as the Field Core in Table 1. The diameter was 1.5 in. The porosity was 20%
Table 1. List of Coreflood Experiments flood #
core
condition
length (inch)
Φ (%)
k (mD)
Soi (%)
1 2 3
field field outcrop
no preflush preflush preflush
9.6 9.6 10.7
20 20 18
990 990 300
67 79 79
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RESULTS AND DISCUSSIONS Phase Behavior. The surfactant formulation consisted of 0.75 wt % TDA−PO−SO4 as a surfactant, 0.25 wt % C20− 24IOS as a cosurfactant, and 0.5 wt % Na2CO3 in the synthetic injection brine to which an additional amount of NaCl (0−2.5 wt %) was added. Equal amounts of reservoir dead oil and surfactant solution were mixed in pipettes, that is, WOR = 1. Part a of Figure 1 shows the phase behavior as a function of the additional NaCl concentration (0−2.5 wt %). At low salinity (tubes AO-41, AO-42), there are two phases: the bottom phase is the microemulsion; the top phase is oil (Type I). Three phases (water, microemulsion, and oil) exist in the intermediate salinity (in 4 samples AO-43 to AO-46); this is called Type III phase behavior. Two phases (water and microemulsion) exist at the high salinity for the tubes AO-47 to AO-49 (Type II). This is the typical oil−water−surfactant phase behavior. Part b of Figure 1 shows water and oil solubilization ratios. The optimal salinity is 1.1 wt % additional NaCl; the solubilization ratio (S) at the optimum is 19. The interfacial tension in this system is estimated from the Huh equation, IFT (mN/m) = 0.3/S2. The lowest IFT is 0.0028 mN/m. This IFT is adequate for mobilization of oil in porous media, as will be shown in the corefloods. The phase behavior experiments were conducted at WOR other than 1. The effect of WOR on the type of phase behavior is shown in Figure 2. A high WOR corresponds to a small oil/ (oil+water); Type III phase behavior shifts to a smaller salinity. A high WOR also corresponds to less soap formation because of lower amount of oil. Thus, the soap to synthetic surfactant ratio is lower at a high WOR. This shows that the synthetic surfactant is more hydrophobic than the soaps generated by the reaction with alkali. The WOR is important when dealing with acidic oils which contain naphthenic acids or other similar organic compounds that become soaps when reacts with alkali. HPAM (2500 ppm) was added to the brine at the optimal salinity (for WOR = 1). Equal volume of oil was then added to the surfactant−polymer solution. Mixing of oil, brine, surfactant, and polymer at the optimal salinity resulted in three phases. Figure 3 shows the viscosity of the pure oil and the three equilibrium phases at the optimum salinity. The oil viscosity is independent of the shear rate. The top phase viscosity is almost equal to that of the oil. The middle phase and bottom phase viscosities are shear rate dependent. The middle phase viscosity is about 2 to 3 times more viscous than
and the permeability 990 mD for brine. The pore volume was 51.3 cm3. The out-crop core was a Berea sandstone having a length of 10.69 in. and diameter of 1.49 in.. The porosity was 18% and the permeability was obtained as 300 mD for brine. The pore volume was 55 cm3. Core Preparation. The cores were first fully saturated with the formation brine and then flooded with the reservoir oil. They were then aged at 80 °C for about two months to attain reservoir wettability. After aging, the cores were flooded with 2 PV of fresh oil and kept in an oven at the reservoir temperature, 59 °C. It is presumed that this preparation brings the core to its reservoir condition at the time of waterflood. The cores were then flooded in a vertical orientation with 3 PV of synthetic formation brine from the bottom at the rate of 1 ft/D and then 2 PV of the same brine was injected at the rate of 10 ft/D. The first step represents a waterflood at a typical field rate; the second step is conducted to identify any capillary end effect. ASP Coreflood. The tertiary ASP flood consists of an ASP slug followed by a polymer slug which is followed by injection brine. The surfactant concentration in the ASP slug was half of that in the phase behavior experiment, a total of 0.5 wt %. The larger amount is used in the phase behavior experiment so that the third phase volume would be large enough to be measured accurately. In Core Floods 2 and 3, an alkaline preflush slug is injected before the ASP slug. The slug compositions are given in Table 2. In coreflood 1, after waterflood, 0.3 pore volume of ASP slug was injected, followed by about 1 pore
Table 2. Slug Compositions in ASP Flood chemical PV injected TDA−PO− SO4 C20− 24IOS HPAM NaCl Na2CO3 NaHCO3 KCl
waterflood brine (ppm) 5
preflush slug (ppm) 0.4
ASP slug (ppm) 0.3 3750
polymer slug (ppm) 1
1250
19 600
30 600
1228 192
5000 1228 192
2500 11 000 + 19 600 5000 1220 192
2500 19 600 + 5000 1220 192 765
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Figure 3. Viscosity of original oil and oil-surfactant water equilibrated phases at the optimum salinity (WOR = 1).
Core Floods. Table 1 shows the conditions for the corefloods. Two corefloods were conducted with the reservoir core and one with the out-crop core. Core Flood 1. This core flood was conducted in the reservoir core with the reservoir dead oil. The waterflood was followed by ASP flood. Figure 4 shows the oil recovery during water flooding. The initial oil saturation was about 67%. Waterflood at 1 ft/D rate reduced the oil saturation to 35% in about 3 PV injected. The water injection rate was then increased by 10 times, but very little oil was produced implying minimal capillary end effect. The waterflood was followed by 0.3 PV ASP slug which included 0.375% TDA−PO−SO4, 0.125% C20−24 IOS, 5000 ppm Na2CO3, 11 000 ppm NaCl, and 2500 ppm HPAM3330 in addition to the simulated injection brine. After the ASP slug, a 1 PV polymer slug was injected which included 5000 ppm NaCl and 2500 HPAM3330 in the simulated formation brine; the simulated formation brine was injected after the polymer slug for 2 PV. Figure 5 shows the tertiary oil recovery during ASP flooding. In the beginning, no oil was produced because the core was at waterflood residual at the start of the surfactant flood. Oil bank broke through at about 0.5 PV injected. Oil cut increased to 85% for a short time and then decreased. Most of the oil was produced by 1.75 PV injection; the residual oil saturation was reduced to 13%. Cumulative oil recovery for the waterflood was 47%; at the end of the ASP flood the cumulative recovery rose to 80%. Table 3 reports the oil recovery in the corefloods. Figure 6 shows the conductivity of the effluent brine in Core Flood 1; both waterflood and chemical flood effluents are plotted together in this figure. The conductivity is a proxy for the brine salinity. It shows that the conductivity starts increasing at about 5.5 PV injection, reaches a highest conductivity of 570 μS briefly between 6 PV and 6.2 PV injection and decreases. It does not quite reach 75% of the injected ASP value (600 μS). There is mixing between the formation brine and the surfactant slug and the optimal salinity is not attained throughout the surfactant slug. In the next coreflood, a preflush of the optimal salinity brine was injected ahead of the ASP slug to separate it from the field brine. The decrease of salinity after the surfactant slug is desirable to reduce surfactant retention and increase the polymer solution viscosity (due to the salinity decrease). Core Flood 2. In Core Flood 2, the core flooding was done in the same core under the same conditions as Core Flood 1, but the core was preflushed with 0.4 pore volume of optimum salinity brine (no surfactant or polymer) before injecting the ASP slug. Also, the salinity of the polymer slug was 70% of the optimum salinity.
Figure 1. Phase behavior at 59 °C with 0.75% TDA−PO−SO4 as a surfactant, 0.25% C20−24 IOS as a cosurfactant, 0.5% Na2CO3 and scanning with 0−2% NaCl in addition to synthetic injection brine, WOR = 1 (a) photograph of pipettes (AO-41 to AO-49 in increasing order of additional NaCl from 0% to 2%), (b) oil and water solubilization ratios.
Figure 2. Effect of water−oil ratio on phase behavior.
the oil at 10 s−1 shear rate. This indicates that the middle phase is high structured as also shown by Kaler et al.20 766
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Figure 4. Water flood oil recovery, Core Flood 1.
Figure 5. Tertiary chemical flood oil recovery, Core Flood 1.
was injected at the rate of 10 ft/D. These floods represent a waterflood. Then 0.4 PV of preflush (brine at optimum salinity, that is, a mixture solution of softened field brine, 5000 ppm sodium carbonate, and 11 000 ppm additional NaCl), was injected. The next slug was 0.3 pore volume of ASP. It included 0.375% TDA−PO−SO4, 0.125% C20−24 IOS, 5000 ppm Na2CO3, 11 000 ppm NaCl, and 2500 ppm HPAM3330 in addition to the simulated formation brine. After 0.3 PV of ASP slug injection, 1 PV of the mixture of 2500 ppm HPAM3330 and 26 000 ppm salinity brine, that is, simulated field brine along with 5000 ppm additional NaCl, was injected. This slug was followed by about 2 PV of simulated field brine.
Table 3. Oil Recovery in Coreflood Experiments flood #
core
1
field
2 3
field outcrop
condition no preflush preflush preflush
initial oil saturation (%)
WF oil recovery (% OOIP)
WF+ASP recovery (% OOIP)
67
47
80
79 79
42 48
85 94
The field core was brought to Swi after the Core Flood 1, as described in the methodology section. The core was then flooded with 3 PV of synthetic formation brine, from the bottom at the rate of 1 ft/D and then 2 PV of the same brine 767
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Figure 6. Conductivity of effluents: Core Flood 1(solutions are diluted 200 times, conductivity of SFB = 460 μS, ASP solution = 800 μS, and polymer slug = 720 μS), Core Flood 2 (solutions are diluted 400 times, conductivity of SFB = 230 μS, preflush = 400 μS, solution = 400 μS, and polymer slug = 359 μS). Figure 8. Tertiary chemical flood oil recovery, Core Flood 2.
Figure 7 shows the oil recovery during water flooding. The initial oil saturation was about 78%. Waterflood at 1 ft/D rate reduced the oil saturation to about 46% in about 3 PV injected. The water injection rate was bumped up by 10 times, but very little oil was produced indicating little capillary end effect. Figure 8 shows the tertiary oil recovery during preflush followed by ASP flooding, which was further followed by polymer flooding. In the beginning, some oil was produced at a low oil cut because of the preflush; then the oil bank broke through at about 0.5 PV injected. Oil cut increased to 40% for some time and then slowly decreased. Most of the oil is produced by 1.5 PV injections; the residual oil saturation was reduced to 11%. Cumulative oil recovery for the waterflood was 42%; at the end of the ASP flood the cumulative recovery increased to 85% OOIP. Figure 9 shows the pressure drop during the tertiary recovery. The pressure drop started at about 5 psi corresponding to brine flow at the Sorw, increased to about 35 psi during the ASP injection and then decreased to below 20 psi during polymer injection. Eventually, it fell to about 5 psi
Figure 9. Pressure drop during tertiary oil recovery, Core Flood 2.
during the brine flood at the end. The high pressure drop during the ASP slug indicates a high viscosity for the microemulsion phase, as seen in Figure 3. The oil recovery can be further improved by decreasing the microemulsion viscosity.
Figure 7. Water flood oil recovery, Core Flood 2. 768
dx.doi.org/10.1021/ef301847z | Energy Fuels 2013, 27, 764−771
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preflush (brine at optimum salinity, i.e., a mixture solution of softened field brine, 5000 ppm sodium carbonate, and 11 000 ppm additional NaCl), was injected. The next slug was 0.3 PV of ASP. It included 0.375% TDA−PO−SO4, 0.125% C20−24 IOS, 5000 ppm Na2CO3, 11 000 ppm NaCl, and 2500 ppm HPAM3330 in addition to the simulated formation brine. After 0.3 PV of ASP slug injection, 1 PV of the mixture of 2500 ppm HPAM3330 and 26000 ppm salinity brine, that is, simulated field brine along with 5000 ppm additional NaCl, was injected. This slug was followed by about 2 PV of simulated field brine. Figure 12 shows the oil recovery during water flooding. The initial oil saturation was about 79%. Water flood at 1 ft/D rate reduced the oil saturation to about 42% in about 3 PV injected. The water injection rate was bumped up by 10 times, but very little oil was produced indicating little capillary end effect. The oil recovery in the waterflood was 47% of the OOIP. Figure 13 shows the tertiary oil recovery during preflush followed by ASP flooding which was further followed by polymer flooding. In the beginning some oil was produced at a low oil cut because of the preflush; then the oil bank broke through at about 5.5 PV injected. The surfactant injection started at 5.4 PV. Oil cut increased to 50% for a brief period and then slowly decreased. Most of the oil was produced by 8 PV injection (2.6 PV after surfactant injection initiation); the residual oil saturation was reduced to 4%. Cumulative oil recovery for the waterflood was 47%; at the end of the ASP flood the cumulative recovery increased to 94% OOIP. This flood showed that the surfactant formulation is very effective in a relatively homogeneous core. The effluent viscosity (at 10 s−1 shear rate) is shown in Figure 14. The viscosity is a proxy for the presence of polymer and shows that the chemicals (surfactant and polymer) breaks through around 6.2 PV injected. Two-thirds of the oil bank is produced by this time indicating that the ASP slug pushed the oil bank. The pressure drop data for the ASP flood is shown in Figure 15; it was about 3 psi during the alkaline preflush at the flow rate of 0.05 ft/D. The pressure drop increased to about 13 psi during the ASP and polymer injection. It fell back to about 3 psi after brine injection. The conductivity of the effluent brine for both waterflood and chemical flood are plotted together in Figure 16. The conductivity increased above 3mS (75% of the injected ASP solution conductivity) between 6 and 7 PV during the surfactant injection. The salinity decreased during the polymer flood and the subsequent brine flood. The salinity gradient drives the fluids into the type I region after the surfactant slug,
The conductivity of the effluent brine (both waterflood and ASP flood) is plotted together in Figure 6 (along with that of Core Flood 1). It shows that the salinity increased to the highest salinity (conductivity above 300 μS, 75% of the injected ASP conductivity) at about 5.3 PV, before the arrival of the surfactant slug and was sustained during the surfactant slug, up to 6.7 PV injected. The use of the alkaline preflush moved the mixing with the formation brine away from the surfactant slug. Figure 10 shows the pH of the effluent brine; both waterflood
Figure 10. pH of effluent samples during Core Flood 2.
and ASP flood are plotted together. The pH increases when the preflush is injected and maintains the high pH condition throughout the surfactant injection. The effluent surfactant concentration was measured and is shown in Figure 11. It is not shown, but the two surfactants moved together in the core. Surfactant breakthrough occurred at 5.7 PV injected. The oil also arrived at about the same time. This shows that the surfactant slug did not push the oil bank effectively. Ideally, the surfactant should have broken through after the oil bank. The retention of surfactant in the core was calculated from the effluent surfactant concentration by material balance. The retention was 0.015 mg of the surfactant per gram of the core, which is a reasonably low (
