Effect of Continuous, Trapped, and Flowing Gas on Performance of

Publication Date (Web): August 22, 2013. Copyright © 2013 American Chemical Society. *E-mail: [email protected]. Cite this:Ind. Eng. Chem. Res...
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Effect of Continuous, Trapped, and Flowing Gas on Performance of Alkaline Surfactant Polymer (ASP) Flooding R. Farajzadeh,*,†,‡ A. Ameri,‡ M. J. Faber,† D. W. van Batenburg,† D. M. Boersma,† and J. Bruining‡ †

Shell Global Solutions International, 2288GS Rijswijk, Zuid Holland, The Netherlands Delft University of Technology, 2628 CN Delft, Zuid-Holland, The Netherlands

‡

S Supporting Information *

ABSTRACT: Alkali Surfactant Polymer (ASP) flooding has traditionally been considered in tertiary mode, i.e., after a reservoir has been sufficiently water flooded. In screening studies experiments are usually conducted under two-phase flow conditions, i.e., in the absence of a gas phase in the rock. In practice, oil reservoirs might contain some gas. In areas in the world, where gas flaring is not allowed and an infrastructure for gas transportation is not present, reinjection of produced gas is a common practice. Moreover, when the reservoir is depressurized below bubble point a gas phase will be created. To the best of our knowledge, there are no data in the literature concerning the influence of in situ gas phase (continuous or trapped) on the performance of ASP floods. The main objective of this paper is to evaluate how the presence of a free (nondissolved) gas phase affects ASP flood performance. To this end, several experiments were carried out to evaluate different conditions, where free gas was present, either flowing or trapped. We found that the ultimate residual oil saturation in most experiments is similar to the case without gas. When free gas is present in the porous medium, the oil-bank production occurs earlier, because a large fraction of the gas remains trapped, and therefore the “effective” pore volume for liquid flow is reduced. When the gas and the ASP solution are coinjected, the oil is mostly produced in emulsion form as gas enhances mixing of the in situ fluids. Trapped gas could lead to an efficient oil recovery, depending on the amount of trapped gas: the lower the trapped gas saturation the better the oil recovery.

1. INTRODUCTION It has been observed that the remaining oil after water flood in porous media can be effectively reduced by injecting a solution that achieves low interfacial tension (IFT) upon contact with the oleic phase.1−3 The low IFT can be achieved by injecting synthetic surfactants, by in situ conversion of petroleum acids into soap by injecting high pH solutions or combination of both.4 In most cases polymer is also added to the solution for mobility control. This technology, known as Alkali Surfactant Polymer (ASP) flooding, has been traditionally considered in tertiary mode, i.e., after the porous medium has been flooded with sufficient water. In screening studies usually the experiments are conducted under two-phase flow conditions, i.e., in the absence of a gas phase in the porous medium.5−8 In practice, the candidate oil reservoir might contain some gas. In areas in the world, where gas flaring is not allowed and there is no infrastructure for gas transportation, reinjection of the produced gas is a common practice. Moreover, when the reservoir is depressurized (below bubble-point pressure) and the oil contains gas, the dissolved gas is liberated from the oil. If the gas saturation exceeds a critical gas saturation, then the gas starts to flow.9 In such a condition, when the reservoir pressure is maintained or the reservoir is repressurized with water injection, the gas might be trapped in the reservoir. Even when the average reservoir pressure is larger than the bubble point pressure, local fluctuations of the pressure can lead to local release of gas. Furthermore, when surfactant is injected into the pores containing three phases, the water−oil interface competes with gas−water and gas−oil interfaces to adsorb the surfactant molecules. This can potentially deplete the surfactant from the oil−water interface and result in higher IFT’s than expected. © 2013 American Chemical Society

The effect of free gas and trapped gas has been investigated for water flooding. It has been found that the presence of both free and trapped gas could favorably impact the ultimate recovery of the waterflood process because of (1) larger (microscopic) sweep efficiency of gas and (2) selective plugging action of the gas.10−14 On the other hand, water flooding in the presence of trapped gas can lead to a decrease in the relative permeability of oil and production loss.15,16 Note that the microscopic sweep of low-IFT surfactant is larger than or close to that of (immiscible) gas. This means that in surfactant flooding, the presence of gas does not contribute to a better sweep efficiency of the process. Some researchers investigated the effect of dissolved gas on the phase behavior of the surfactant solution and found that the dissolved gas influences the phase behavior of the aqueous and oleic phases.1,17 The surfactant appears to be more soluble in oil containing dissolved gas than the oil with no dissolved gas. This shifts the optimum conditions of the “live” oil to lower salinity compared to the “dead” oil. Pressurizing the crude oil with nitrogen does not affect the surfactant phase behavior.17 Some literature differentiated the synergistic effect of pressure and dissolved gas and concluded that while an increase in pressure shifts the phase behavior toward type II- (underoptimum), the addition of methane to dead oil does the reverse.18,19 Other investigators used the gas as the displacing agent in their experiments.20−22 They concluded that for such a Received: Revised: Accepted: Published: 13839

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in the presence of alkali. This solution, with the addition of polymer, was chosen to be injected in all of the experiments reported here. Note that the addition of alkali also reduces the surfactant adsorption. 2.3. Experimental Setup. Two ISCO pumps were used to ensure the supply of gas and liquid at stable rates at the experimental pressure and temperature. In the test unit, the sample core was placed inside a vertical cylindrical coreholder. The fluids were injected under gravitationally stable conditions, i.e., the liquids (water and the ASP solution) were injected from the bottom of the core and the gas was injected from the top of the core. The liquid production was collected in scaled tubes with a volume of 5−10 mL. Two high precision differential pressure transducers monitored the pressure drop along the core. By using a backpressure regulator the experimental pressure was set to 50 bar. The data acquisition system recorded gas and liquid injection rates and pressures. All experiments were conducted at isothermal conditions of T = 54 °C. 2.4. Experimental Procedure. Before starting the experiments all of the connections in the setup were checked for possible leakage by keeping the setup under high pressure and monitoring the measured pressures. Experiments consisted of different stages (see Table 1). The common stages in all the experiments were as follows:

process the oil recovery is due to the combined effect of low IFT between the oil and water and foaming of gas leading to favorable mobility control. To the best of our knowledge, there are no data in the literature concerning the influence of in situ gas phase (continuous or trapped) on the performance of the ASP recovery. This has implications for modeling ASP flooding in the presence of gas.23,24 The main objective of this paper is thus to investigate the effect of free (nondissolving) gas on the performance of the ASP floods in the porous medium. To this end, several experiments were designed to simulate different field conditions, where gas could be free (continuous), flowing or trapped. The experiments were designed under favorable conditions for ASP to exclusively focus on the effect of gas. Therefore, we conducted experiments with continuous injection of the ASP solution into a rock with relatively high permeability and low-clay content and in the absence of divalent cations. The structure of the paper is as follows: Section 2 describes the experimental setup and the experimental procedures. Section 3 presents the experimental results. History matching of the experiments and the effect of gas on the model parameters is discussed in Section 4. We end the paper with concluding remarks.

2. EXPERIMENTS 2.1. Material. Chemicals. Sodium carbonate (Na2CO3) was used as the alkali; Enordet H771 manufactured by Shell Chemicals (TDA 7 PO sulfate) was used as the surfactant. The polymer was supplied by SNF (Societe National Floerger). It is the powder polymer Flopaam 3430S, which is a hydrolyzed polyacrylamide with a molecular weight of 10 to 12 million Daltons, a hydrolysis degree of 28%, and an active matter content of 87.6%. Isopropyl alcohol was added to the polymer solution to deactivate radical components. The viscosity of the ASP solution was 30 cP at 54 °C. Brine Composition. The brine composition is provided in Table S1. Crude Oil. The viscosity and density of the crude oil at the reservoir temperature of 54 °C were measured to be 9.01 cP and 840 kg/m3, respectively. The crude oil used in the experiments contained no gas. The total acid number (TAN) of the crude oil was 0.09 mg KOH/g oil. Gases. CO2 was used to saturate the core. The experiments were flooded with nitrogen (N2). Porous Media. The porous medium used was consolidated, quasi-homogeneous, and quartz-rich Bentheimer sandstone. The porosity of cores was 0.21−0.22, and their permeability varied between 1.1 to 1.7 D. The permeability was calculated from the differential pressure data of a single-phase (brine) flow (with a known flow rate) through the core. The diameter and length of the core were 50 ± 1 mm and 300 ± 2 mm, respectively. 2.2. Phase Behavior Tests. A series of test tubes were filled with equal volumes of a surfactant solution (0.3 wt% surfactant in the brine) with different alkaline concentrations and an oleic phase with 1:1 ratio to determine the optimum salinity. The formation of a third phase, known as microemulsion phase, in the test tubes is a sign of low IFT between the phases. This occurred at an alkali concentration of 1.75 wt% at 54 °C. The optimum salinity was dependent on the water− oil ratio and increased with decreasing oil content in the test tubes implying that the natural acids in the oil were saponified

Table 1. Summary of Coreflood Experimentsa exp. no.

Step 3

Step 4

Step 5

1 2 3 4 5

water water gas gas water

ASP gas water ASP gas and ASP

ASP ASP -

a

In Step 1 the cores were saturated with water, and in Step 2 oil was injected to bring the water saturation to connate water. Water and ASP were injected from the bottom while gas was injected from the top.

Core Saturation (Step 1). The core was flushed with CO2 for at least 30 min to replace the air in the system. Afterward, at least 20 pore volumes of brine with a flow rate of qw = 2 mL/ min were injected to the system, while the backpressure was set to 50 bar. This ensured that all CO2 present in the core was dissolved into the brine and carried away. Oil Injection (Step 2). When no gas bubbles were observed at the outlet of the core, the oil was injected with a flow rate of qo = 4 mL/min to displace the brine. When the pressure was constant and no water production was observed, the injection was stopped. ASP Injection. The last stage of all experiments was continuous injection of the ASP solution. The ASP solution was injected with the flow rate of 0.1 mL/min at the inlet conditions, which corresponds to an interstitial velocity of ∼ 1 ft/day. Several experiments were designed to simulate different field conditions. These experiments include the following: Experiment #1: Base Experiment. In this experiment the core was flooded by water until no more oil was produced (Step 3). Afterward, the ASP solution was continuously injected to produce the remaining oil in the core (Step 4). This experiment served as a reference for comparing the performance of other experiments. The experiment was repeated to check the repeatability. Because we were interested 13840

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Figure 1. Oil cut and recovery factor of Experiment #1, at which the core was flooded with water and then the ASP solution. The symbols are experimental data, and the solid lines are results of the simulation.

Figure 2. Oil fraction in the effluent, incremental oil recovery factor, and concentration of the surfactant and carbonate in the effluent in Experiment #1. In this experiment the core was flooded with water and then with the ASP solution.

in the effect of gas on the efficiency of ASP flooding, the ASP solution was continuously injected into the porous medium. In practice only a fraction of pore volume of the reservoir will be injected. Therefore, when the conditions are not favorable, the results might be different. Experiment #2: Water/Gas/ASP. This experiment was performed to study the performance of ASP in the regions of the reservoir that have been previously flooded by gas. In this experiment, the core was first flooded by water (qw = 4 mL/ min) from the bottom until no oil was produced (Step 3). Afterward, gas was injected with a flow rate of 0.1 mL/min (interstitial velocity of 1 ft/day at inlet pressure) from the top into the core until there was no more oil production (Step 4). ASP solution was then injected from the bottom to produce the remaining oil to gas flooding (Step 5). Experiment #3: Gas/Water/ASP. In this experiment, the core was first flooded by gas with a flow rate of 0.1 mL/min from the top (Step 3). Afterward, water was injected (qw = 4 mL/min) from bottom into the core (Step 4). The injection of water was continued until there was no gas production. Part of

the gas will be trapped in this process. Finally, the ASP solution was injected with flow rate of 0.1 mL/min to produce the remaining oil. This experiment was also repeated to examine some of the observation in the first experiment. Experiment #4: Gas/ASP. In this experiment, the core was directly flooded by gas from the top with a flow rate of 1 mL/ min until no oil production was observed. The gas injection was followed by injection of the ASP solution with rate of 0.1 mL/ min. Experiment #5: Water/Coinjection of Gas and ASP. To study the effect of flowing gas in the porous medium, in this experiment after water flooding, the ASP solution and gas were injected simultaneously into the core from the bottom both with flow rate of 0.1 mL/min.

3. RESULTS AND DISCUSSION 3.1. Experiment #1: Base Experiment. Figure 1 shows the measured (data points) and the simulated (solid lines) fraction of the produced oil (oil cut) and the total recovery factor of Experiment #1. The model consists of three phases 13841

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(aqueous, oleic, and gaseous), and the properties of the aqueous phase are altered with changes of IFT and viscosity through capillary number. The effect of soap on the optimum salinity and eventually the IFT is considered through mixing rules described in refs 6 and 25. The surfactant can partition to the oleic phase as a function of salinity. The surfactant and polymer adsorption is represented by a Langmuir adsorption isotherm. The polymer viscosity, at a fixed shear rate, depends on the polymer concentration and salinity of the solution. The properties of the gas phase remain unchanged with lowering of the oil−water IFT. More details of the model can be found in refs 8 and 23. The simulation parameters are given in the Supporting Information of this paper. After 3 PV of water injection, 44% of the initial oil in the core was produced. With injection of the ASP solution, the recovery was increased to 96% (Sorc = 0.03). The agreement between the model and the experiment is rather good. The mismatch in the plateau part of the cut oil can be attributed to the formation of microemulsions in the core that are not accounted for in the model. It could also be due to the accuracy of measurements. In Figure 2 we plot the oil cut and the incremental recovery together with the pH and carbonate and surfactant concentrations of the effluent as a function of pore volume of ASP solution injected. We observe that the oil breakthrough occurred after 0.40 PV of ASP injection. The oil cut was above 60% until 0.90 PV of ASP injection, when the chemical breakthrough took place. The surfactant, carbonate, and polymer (not shown on the figure) were produced at the same time, indicating that the injected chemicals traveled with the same speed inside the core resulting in a stable and efficient displacement. The production of polymer was qualitatively incurred from change of viscosity of the produced aqueous phase. The measured viscosities were not reliable due to the mechanical degradation of the polymer inside the back pressure regulator. We also observe from Figure 2 that about half of the injected surfactant was retained in the oleic phase (and possibly in the microemulsion phase) and in the core. Note that the plotted data are only concentrations in the aqueous phase. The pressure drop along the core increased to 100 mbar at the breakthrough of the oil bank and then reached a plateau value of 60 mbar until the end of the experiment. For the sake of comparison with other experiments and to eliminate the effect of slight differences in the core permeability and length, an “apparent” viscosity was calculated for each experiment using Darcy law. This calculation neglects the effect of relative permeability. For Experiment #1, the apparent viscosity of flowing fluids at the breakthrough time of the oil bank was about 50 cP. When the pressure reached its plateau value the apparent viscosity was calculated to be about 33 cP, which is very close to the viscosity of the injected ASP solution. This is another indication that at the end of experiment, the ASP solution has efficiently displaced the remaining oil from the core. Experiment # 1 was repeated to test the repeatability of the experiment. Figure 3 compares the results of the two experiments. In the second experiment the water reduced the oil saturation down to 0.37. However, similar to the first experiment the injection of ASP efficiently produced 90% of the remaining oil and increased the total oil recovery to 96%. We observe that due to the differences in the initial conditions of the two experiments, the oil breakthrough occurred later in the second experiment. The chemical breakthrough occurred at the same time for both experiments indicating similarities in the chemical consumption.

Figure 3. Comparison of two experiments with different initial oil saturations. In both experiments, the core was flooded by water and then the ASP solution. In the experiment with lower oil saturation the oil breakthrough occurs later.

3.2. Experiment #2: Water/Gas/ASP. Figure 4 shows the oil recovery of Experiment #2 and compares it with model prediction. For the gas injection part, only the final oil production was recorded. We observe that the injection of water produced about 47% of the oil (similar to Experiment #1). With injection of 10 PV of nitrogen, another 10% of the oil was produced. For the sake of plotting the 10 PV of gas injection is plotted as 2 PV in Figure 4. Before ASP injection the average remaining oil saturation in the core was 37%. From simulation results and material balance, at this stage the average gas and water saturations were 50% and 13%, respectively. Note that since gas was injected from the top, the liquid saturation at the top was lower than at the bottom due to capillary effects. We also observe from Figure 4 that after injection of the ASP solution, 85% of the remaining oil was produced, which increased the total oil recovery to 95% (Sorc = 0.04). The differential pressure in this experiment reached a maximum value of 180 mbar and then dropped to 150 mbar until end of the experiment. These values correspond to “apparent” viscosities of 101 cP and 84 cP, respectively. These values are higher than the values calculated for Experiment # 1 due to the effect of trapped gas among other parameters. Figure 5 shows schematically the propagation of different banks and fronts when ASP is injected into a reservoir flooded previously by water and gas. When the ASP solution is injected into the porous medium, it forms an oil bank ahead of which a gas bank is formed. The gas bank is pushed by the flowing liquids, and as we can see from Figure 6 initially only gas is produced. The oil bank breakthrough occurred after 0.2 PV of ASP injection in our experiment, because in this case a large fraction of the gas remained trapped in the core (25−30% from simulation results), and, therefore, the “effective” volume for liquid flow was reduced. This resulted in a higher propagation rate for the oil front. Another interesting feature of this experiment was the small production of the gas together with the oil bank (shown by a green dashed line in Figure 5 and a green line with a yellow marker in Figure 6). The gas production stopped after breakthrough of the ASP front. Figure 7 shows the fraction of oil in the liquid part of the production, the incremental recovery factor and the effluent pH, and its surfactant and carbonate concentration. A comparison with Figure 2 reveals some similarities and 13842

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Figure 4. Oil cut and recovery factor of Experiment #2, in which the core was first flooded by water, then gas, and finally the ASP solution. For the gas injection only final point of the cumulative oil production is reported.

case. This could be due to a higher clay content of the core in Experiment #2, which consumes injected alkali in other reactions and adsorbs more surfactant. The more likely explanation is depletion of surfactant into gas-fluid interfaces. 3.3. Experiment #3: Gas/Water/ASP. Figures 8−10 present the production history of Experiment #3. With injection of 1.4 PV of gas from the top (gravitationally stable) it was possible to recover about 56% of the initial oil. At this stage both water and oil were produced before gas breakthrough. The water fraction in the first sampling tube was 24%. The water production stopped after 0.1 PV of gas injection. Within measurement accuracy and based on a simple mass balance, at the end of the gas injection period the average water, oil, and gas saturations in the core were 0.09, 0.39, and 0.52, respectively. Injection of water from the bottom increased the oil recovery to 64% and reduced the average oil saturation to 0.30. The oil produced by water was most likely the oil trapped in the bottom part of the core due to capillary effect (note that gas was injected from top). The accurate modeling of this experiment requires considering hysteresis effects in relative permeability functions, which is out of scope of this paper. With the injection of ASP solution, the recovery factor increased to 95% (Sorc = 0.04), which is similar to Experiment #1 and Experiment #2. The pressure drop along the core reached to a slightly higher value of 190 mbar (corresponding to apparent viscosity of 113 cP) and then decreased to a constant value of 160 mbar (corresponding to apparent viscosity of 95 cP). Figure 9 shows the fluid production history of the ASP part of Experiment #3. Initially only water was produced. After ∼0.05 PV, a small amount of gas was also produced. The largest amount of gas was produced together with small amounts of oil after ∼0.15 PV injection of the ASP solution. One would think that the oil was produced by the gas released by the ASP solution due to higher imposed capillary number, which was the result of higher aqueous-phase viscosity and possible reduction in gas−water interfacial tension. However, the main reason can be inferred from Figure 10, on which we plot the oil cut together with the measured values of pH, carbonate concentration, and surfactant concentration. After the produc-

Figure 5. Schematic representation of the propagation of fluid banks in a reservoir flooded by water, gas, and eventually ASP.

Figure 6. Fraction of the produced fluids in Experiment #2, in which the core was flooded sequentially with gas from the top, water and then the ASP solution from the bottom.

differences between the experiments. Similar to Experiment #1, most of the oil was produced in a stable bank, and all the chemicals broke through at the same time. However, unlike Experiment #1, in Experiment #2 the rise in carbonate concentration and the measured pH values was not as sharp. The produced surfactant concentration was also less in this 13843

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Figure 7. Production history of Experiment #2. Sor is the remaining oil after gas flood.

the trapped gas. The gas production stopped after the oil cut increased to higher values. It can also be seen from Figure 10 that during the production of the oil bank the pH of two tubes was equal to the pH of the initial solution. Moreover, these tubes did not contain detectable amounts of carbonate ions. This observation confirms the previous interpretation of different flow paths in the core. Experiment #3 was repeated twice to examine the repeatability of the observed features. The results are presented in Figure 11. In the first repeat (Experiment 3-R1), the injection of gas from the top followed by injection of water from the bottom reduced the average oil saturation to 0.26, which was lower than the first experiment. In the second repeat (Experiment 3-R2) after injection of gas and water, the average oil saturation in the core was 0.29, which was close to the first experiment. We also noted that the recovery efficiency of the gas flood part increased with an increase in the value of initial water saturation or decrease in water wetness of the core (see Table 2). The injection of the ASP solution in Experiment 3-R1 increased the total recovery factor to 86% (Sorc = 0.12), which means that slightly more than half of the remaining oil was produced. The oil breakthrough in this experiment occurred after 0.60 PV of ASP injection. This could be due to the low remaining oil saturation before injection of the ASP solution and/or different relative permeability parameters of the core in this experiment. In Experiment 3-R2 the oil bank arrived after 0.38 PV of ASP injection, and in total 96% (Sorc = 0.03) of the initial oil was produced. Unlike the first experiment, in the repeat experiments there was no sign of discontinuous fingers in the effluents, and all the chemicals were produced simultaneously with the production of the microemulsion phase. The differential pressure in Experiment 3-R1 reached a maximum value of 290 mbar (apparent viscosity of 136 cP) and stabilized at 150 mbar (apparent viscosity of 71 cP) after production of the emulsion phase. The higher apparent viscosity of this experiment could be attributed to formation of emulsions inside the core or possibly to high trapped gas saturation. We leave the discussion on these experiments to a future work. Accurate measurement of the phase-saturation profiles will provide essential information for understanding of the results.

Figure 8. Oil production history of Experiment #3, in which gas injection (from the top) was followed by water and ASP injection (from the bottom).

Figure 9. Fraction of produced fluids in Experiment #3, in which gas injection (from the top) was followed by water and ASP injection (from the bottom).

tion of oil, small traces of surfactant and carbonate ions were found in the tubes. This indicates that the ASP solution has bypassed or traveled through the parts of the core containing 13844

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Figure 10. The oil cut, pH, and concentration of the surfactant and carbonate in the effluent of Experiment #3, in which gas injection (from the top) was followed by water and ASP injection (from the bottom). The blue shading in the figure is to demonstrate the (disappearing) fingers in the experiment.

Figure 11. Repeat of Experiment #3 with different initial oil saturations.

Table 2. Summary of Coreflood Experimentsc exp. no.

k (mD)

Soi

1 1 (R1b) 2 3 3 (R1) 3 (R2) 4 5

1438 1181 1377 1455 1155 1632 1152 1438

0.84 0.83 0.85 0.87 0.84 0.89 0.85 0.90

Sorw (RF) 0.47 0.37 0.45 0.30 0.26 0.29 0.47

(0.44) (0.56) (0.47) (0.66) (0.70) (0.67) (0.48)

Sorg (RF) 0.37 0.39 0.35 0.47 0.46 -

(0.57) (0.56) (0.59) (0.47) (0.46)

Sorc (RF) 0.03 0.03 0.05 0.04 0.12 0.03 0.01 0.09

(0.96) (0.96) (0.94) (0.95) (0.86) (0.96) (0.99) (0.90)

OB BTa (PV)

μapp @BT (cP)

μapp plateau (cP)

0.40 0.60 0.20 0.40 0.64 0.46 0.15 0.10

50 46 101 113 136 52 120 80

33 32 84 95 71 44 120 95

OB BT stands for “oil bank breakthrough time”. bR1 and R2 stand for “Repeat 1” and “Repeat 2”, respectively. cAll experiments were conducted at P = 50 bar and T = 54 °C. RF represents the total recovery factor at the end of each stage.

a

3.4. Experiment #4: Gas/ASP. Figure 12 presents the production history of Experiment #4 and compares it to the simulation results. The injection of 1.95 PV of gas from the top produced 47% of the oil initially present in the core. From material balance calculations it was obtained that the water, oil, and gas saturation values at the end of the gas injection stage were 0.09, 0.46, and 0.45, respectively, which matches well with

the simulation results. The injection of ASP solution increased the total recovery factor to 99%. It is observed from Figure 13 that the oil-bank breakthrough occurred after 0.15 PV of ASP injection. Note that prior to the oil-bank breakthrough small amounts of oil were produced together with gas, which means that the oil was either still mobile at the end of gas-injection stage or some oil was trapped in the tubing and back-pressure 13845

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regulator. A small amount of gas was also produced with the initial oil bank. The water production started after 0.30 PV of ASP injection. This coincided with the production of alkali and polymer. At this stage the gas production was minimal. At the breakthrough time of the microemulsion (and surfactant), which is observed at 0.72 PV of ASP injection, about 92% of the remaining oil after gas injection was produced. At the end of ASP injection the average water, oil, and gas saturations were 0.62, 0.01, and 0.37, respectively. The value of the trapped gas saturation in this experiment was larger than the trapped gas saturation after water injection in Experiment #3 (Sgc < 0.25), which could be attributed to the higher injection rate of waterflood stage. In the simulations the best match was also obtained with Sgc = 0.37. Note that this value was chosen to match the breakthrough time of the oil bank in the experiment. Choosing smaller values of Sgc delays oil production time and results in lower ultimate oil recovery than the experiment. This value should be lower if the early breakthrough would be due to instabilities. The differential pressure in this experiment increased to value of 200 mbar (corresponding to apparent viscosity of 120 cP) at a breakthrough of the oil bank and after some fluctuations (due to production of emulsions) remained at a constant value of 200 mbar until the end of the experiment. Figure 14 presents the fraction of oil in the liquid part of the production, the incremental recovery factor and the effluent pH, and its surfactant and carbonate concentration. Alkali (and polymer) was produced together with water production in the effluent. This reduced the oil cut to lower values. In this experiment there was a significant difference (0.30 PV) between the breakthrough times of the surfactant and the polymer. The surfactant breakthrough coincided with the production of the emulsions. Due to lower oil saturation after ASP flood, compared to the other experiments more surfactant was recovered, i.e., smaller amount of the surfactant was partitioned into the oleic phase. Based on this data, Figure 15 shows schematic of the propagation of different banks and fronts when ASP is injected into a reservoir flooded previously by gas. Similar to Experiment #2, because of a large amount of the trapped gas, the oil breakthrough occurs early. Note that this process could be even more effective if there was no

Figure 12. Oil production history of Experiment #4, in which gas injection (from the top) was followed by ASP injection (from the bottom).

Figure 13. Fraction of produced fluids in ASP part of Experiment #4, in which gas injection (from the top) was followed by ASP injection (from the bottom).

Figure 14. The oil cut, pH, and concentration of the surfactant and carbonate in the effluent of Experiment #4, in which gas injection (from the top) was followed by ASP injection (from the bottom). 13846

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(corresponding to “apparent” viscosity of 95 cP). The increase of pressure was likely due to formation of weak foam inside the core. The final oil recovery is this experiment was slightly lower compared to the previous experiments. This is again attributed to the formation of viscous emulsions and/or creation of preferential flow paths in the core with the gas flow, which leads to bypassing of some of the in situ oil. Moreover, it seems from Figure 16 that the gas does not have significant contribution in the production of oil as the volume of injected surfactant solution for production of equivalent amount of oil is similar to the previous experiments. Figure 15. Schematic representation of the propagation of fluid banks in a reservoir flooded by gas followed by ASP. In the absence of chromatographic separation polymer and surfactant fronts move with the same speed.

4. SUMMARY AND CONCLUSIONS In this study we investigated the impact of the presence of gas on recovery efficiency of surfactant flooding process. Several experiments were designed to represent different situations in the reservoir, where gas can be continuous, trapped, or flowing. The type of experiments and the obtained results are summarized in Table 2. The following conclusions can be drawn from this study: • The presence of the initial gas in the porous medium does not influence the displacement efficiency of the ASP flooding. • When the ASP solution is injected after a gas flood, a large fraction of gas is trapped, as a consequence of which the effective volume for liquid flow of the ASP solution and oil is reduced and therefore the oil breakthrough occurs earlier. This has favorable impact on the economics of the ASP projects because of the accelerated production. • The presence of trapped gas results in different results depending on conditions before the injection of the ASP solution. Seemingly, the efficiency of the ASP flood decreases with the increasing trapped gas saturation, i.e., smaller oil saturation. • The pressure drop or injectivity could be an operational limit when ASP is applied in a reservoir with large amount of trapped gas. • When the ASP solution and gas flow simultaneously in the core, the flow of gas enhances the mixing between the in situ

chromatographic separation between the surfactant and polymer. In this case the surfactant and polymer fronts overlap, and the oil-bank fraction before emulsion breakthrough remains close to unity. 3.5. Experiment #5: Coinjection of Gas and ASP. In Experiment #5 gas and ASP solution were injected simultaneously (both from the bottom) to the core that contained remaining oil to waterflood. Figure 16 shows the production history of Experiment #5. Water injection produced 45% of the oil in place. With injection of 1.7 PV of ASP solution (or 3.4 PV of ASP+gas injection) the recovery factor increased to 90% (Sorc = 0.09). The oil bank arrived after 0.3 PV of ASP injection. Note that the gas breakthrough occurred after 0.1 PV of total fluid injection. The interesting feature of this experiment was the high oil cut before the chemical breakthrough (as high as 90%). Moreover, after the chemical breakthrough all the oil was produced in (unstable) emulsion form. The produced emulsion is easily separated into oil and water due to gravity. The formation of emulsion could be attributed to the flow of gas, which enhances mixing between water and oil and creates emulsion. The pressure in this experiment increased steadily until end of the experiment and reached value of 170 mbar

Figure 16. Production history of Experiment #5, in which gas and ASP were injected simultaneously from the bottom to a core with remaining oil to waterflood. 13847

dx.doi.org/10.1021/ie401475u | Ind. Eng. Chem. Res. 2013, 52, 13839−13848

Industrial & Engineering Chemistry Research

Article

fluids and therefore creates emulsion. The efficiency of the ASP flood in this case largely depends on the stability and flow of these emulsions through the core. • Foaming of the gas upon mixing with the injected surfactant solution can provide favorable mobility control behind the oil bank.

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