The Effect of Oil on Foam Generation - American Chemical Society

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Experimental and Simulation Study of the Steam-Foam Process - Part II: The Effect of Oil on Foam Generation Seyed Reza Bagheri Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.6b03348 • Publication Date (Web): 01 Feb 2017 Downloaded from http://pubs.acs.org on February 7, 2017

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Experimental and Simulation Study of the SteamFoam Process - Part II: The Effect of Oil on Foam Generation S. Reza Bagheri* Shell Global Solutions Canada Inc., Calgary Technology Centre, 3655 36 St NW, Calgary, AB, Canada, T2L 1Y8 KEYWORDS Steam-foam, Oil, Enhanced oil recovery, Porous media, Core flooding, Modeling

Abstract

The intent of this study was to examine the stability of foam in the steam-foam process, which is an Enhanced Oil Recovery (EOR) method used to improve the performance of a traditional steam drive. In this study, a surfactant solution was co-injected with steam at various qualities into a core holder filled with a sand pack. The core holder was kept inside an oven at 250°C to mimic the near-wellbore temperature in a steam flood. By measuring the pressure drop along the core with and without the surfactant, the mobility reduction factor (MRF) of the generated foam could be measured. The effect of oil saturation on steam-foam was also investigated. The results showed that the presence of oil had a detrimental effect on the foam strength; however, foam can be still generated in the presence of oil. At higher superficial gas velocities, the generated foam

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could not improve the oil recovery, but when the velocity was lowered, foam generation could significantly improve the oil recovery from the core. The Computer Modelling Group (CMG) STARS simulator model for foam generation was used to model the core-flood results, and shortcomings in the model have been identified. 1. INTRODUCTION The steam foam process is an Enhanced Oil Recovery (EOR) method which improves the performance of a traditional steam drive by using a foaming surfactant. The stability of foam in the presence of oil is an important criterion for the application of steam-foam in oil reservoirs. Some studies report that the generated foam is destabilized by the oil phase1-3 . There is some disagreement in the literature on whether or not this is an undesirable behavior. If the application of foam is only limited to steam diversion from a steam override zone (with little oil saturation) to an unswept zone (with high oil saturation), then the foam does not require a high level of oil stability4. Isaacs et al.5 conducted laboratory studies using heavy oil samples to examine the effect of oil on two commercial foam-forming surfactants. Foam generation experiments performed in a sandpack at 180°C demonstrated that the presence of residual oil can have a destabilizing effect on foam bubbles, preventing the generation of foam. The pack was first saturated by oil, and the oil saturations in the pack were later reduced by injecting hot water, hot water-surfactant, steam, steam-surfactant and hot water-toluene-isopropyl alcohol (IPA) mixtures. In each run, the mobility reduction of foam was measured at a different initial average oil saturation. The results showed that, by increasing the average oil saturation in the pack, the foam became weaker, and for an average oil saturation above 15%, no foam was formed in the sandpack (mobility


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reduction =1). In core-size displacement experiments, the reduction of steam mobility by foam formation in a high permeability (50 Darcy) flow channel resulted in a substantial enhancement in oil recovery. Even a low mobility reduction could result in some additional oil recovery. The aim of this paper is to study the effect of the presence of oil on foam generation in a porous medium during a steam-foam flood. To study the effect of oil saturation on foam strength, steam-foam corefloods were conducted at two different gas velocities. A high superficial gas velocity test mimics the near–well bore condition, and a low superficial gas velocity test mimics the deeper regions of the reservoir. The Computer Modelling Group STARS simulator foam model has been used to the model the corefloods, and its shortcomings for modelling the results of this study have been identified. 2. EXPERIMENTAL 2.1. COREFLOOD SETUP A schematic diagram of the experimental setup is depicted in Figure 1. The setup used and the experimental procedure for the steam flooding were described in detail elsewhere6. DI water and surfactant solution were injected through two pumps to produce the steam at the desired quality. One pump provided the water for the steam generator and the other provided the liquid water to be mixed with the generated superheated steam. The superheated steam and the liquid water were mixed together in the oven to generate saturated steam at a desired quality which was injected into the core. The superheated steam temperature (Ts) and the liquid water line temperature (Tw) were used, along with the cold water equivalent (CWE) rates of the two steam lines, to calculate the steam quality after the mixing point. The steam pressure before the injection point was measured using a pressure transducer. From thermodynamic calculations, the


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quality of steam as well as its temperature was determined at the injection point. During the surfactant flooding, the liquid water vessel was replaced with a surfactant solution vessel. Nitrogen was the third line that met the two other injection lines at the same junction. It was injected in low concentration to stabilize the foam (0.1 mol % of total steam rate). The core holder was kept inside an oven at 250°C to mimic the near-wellbore temperature in a steam flood. The core was mounted to give a uniform frontal flow in the tests with the presence of the oil. The lead sleeve was packed with unconsolidated Ottawa sand to have a permeability of about 3 D. Three differential pressure transducers read the differential pressures in each third of the core. These transducers are also displayed in Figure 1, and their pressure are identified as Pin and Pout for absolute pressures, and ∆P1, ∆P2 and ∆P3 for differential pressures.

Figure 1. Steam-foam experimental setup


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A heat-traced line came out of the core holder to a heat exchanger bore. The temperature of the heat exchanger was controlled by a water bath. This temperature was set to 90°C such that, in the tests with the oil, the viscosity of the oil leaving the oven stays low so that the oil would flow. The heat exchanger was connected to a high pressure Jurgusen® visual cell which, again, was heat-traced to the same temperature. The gas and aqueous effluent flowed out of the core to this cell, which played the role of a separator. 2.2. SURFACTANT In this study, an Alkyl Benzene Sulfonate (ABS) anionic surfactant was used for the corefloods (denoted as Surfactant A in this paper). This surfactant was identified by conducting foam height tests and thermal degradation analysis of some commercial surfactants in the market to screen out a surfactant with high foamability and thermal stability at high temperatures. When the concentration of the surfactant is reported for a test in this paper, it means the concentration of the surfactant in the liquid part of the steam. 2.3. OIL ANALYSIS The oil sample used in the study was a Shell Peace River dewatered bitumen. The bitumen sample was dead and had no dissolved solution gas. The density and viscosity of the bitumen were measured at several temperatures up to 250°C. The density and viscosity of the bitumen is given in Table 1.


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Table 1. Density and viscosity of bitumen Temperature (°C)

Density (g/cm3)

Viscosity (cp)

23

0.9862

27015.73

50

0.9655

1462.89

100

0.9370

88.58

150

0.8973

21.84

200

0.8603

5.38

250

0.8273

1.33

Temperature, °C Density, g/cm3 Viscosity,

In the tests that included oil, the bitumen was injected to the core through a heat-traced transfer vessel. The core was 100% saturated with water at the beginning of each series of tests. The amount of water displaced with the oil provided the connate water saturation as well as the initial oil saturation in the core. The core was not cleaned of oil during the tests; it was only resaturated with the bitumen at the start of each run to re-establish the original initial oil saturation. The produced oil and condensed steam mixture was collected in glass jars from the bottom of the Jurgusen visual cell (Figure 1) every 6 or 12 minutes. The oil and water content of each sample was separated and measured. To separate them, firstly, the produced oil and water emulsion was dissolved in chloroform/toluene. Then, it was centrifuged at 3000 RPM to break the emulsion. The mixture was filtered using a Whatman® phase separation filter. The organic phase passed through the filter, and the water stayed on top, where it was easily collected using a pipette.


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2.4. EXPERIMENTAL PROCEDURE During steam flooding, the back pressure, the temperature and the rates of water and superheated steam were set to get the desired steam quality at the inlet of the core. After the start of foam generation, the pressure in a core should increase significantly, since foam reduces the gas mobility in a porous medium. This expected pressure increase is an important criterion for assessing the foam strength. The mobility reduction factor (MRF), which is usually reported in steam-foam studies, is the ratio of the pressure drop across the core in the presence and absence of foam7 :

‫= ܨܴܯ‬

∆௉೑

(1)

∆௉೙೑

where ∆Pf is the steady-state pressure drop across the core with foam flow, and ∆Pnf is the steady-state pressure drop across the core with gas/water flow at rates equivalent to those in the presence of foam. There were three pressure transducers to read the differential pressures in each one-third of the core (see Figure 1). In each run, the pressure drops across each section of the core (∆P1, ∆P2, and ∆P3 in Figure 1) were measured in a baseline steam flood in order to determine the values of ∆Pg for that section. After the start of surfactant injection, the new pressure drops were measured at each time interval to establish the value of ∆Pf for each onethird of the core. Then, the MRF value for each section was calculated using Eq 1. An MRF of larger than one is an indication of foam generation, and MRF will increase as the foam becomes stronger. If no foam is generated, the pressure drop will not increase and MRF will be equal to 1. To study the effect of oil saturation on foam strength, steam-foam corefloods were conducted at two different velocities. In each run, the sand pack was first saturated with oil, and then a baseline steam flood was used to reduce the oil saturation to its residual value (no more oil


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production). After that, surfactant injection was started. For the near-wellbore region, a coreflood was conducted with 0.5 wt% of surfactant A and steam quality of 80% at a superficial gas velocity of 847 m/d. For the deeper regions of the reservoir, a low velocity core-flood was carried out. In this test, 0.5 wt% of surfactant A and a steam quality of 40% was used. Based on the results of a previous study6, the lowest velocity for foam generation with a 40% steam quality should have been 235 m/d. Initially, this was the superficial gas velocity used to generate the foam, and when the foam covered the core, the velocity was lowered to 48 m/d. 3. FOAM MODELLING The STARS simulator developed by the Computer Modelling Group uses an implicit texture local-equilibrium foam model based on the concept of the mobility-reduction factor developed in the study of Mohammadi et al.8. In this model, it is assumed that the gas phase mobility is reduced by a dimensionless interpolation factor, FM, which is defined as:

‫= ܯܨ‬

೑

௞ೝ೒

(2)

೙೑

௞ೝ೒

where: kfrg is the relative permeability of gas in the presence of foam and knfrg is the relative permeability of gas in the absence of foam. When there is no foam, FM is equal to one, and it decreases with the increasing foam strength. In STARS, FM is generally defined as 9, 10:

‫= ܯܨ‬

ଵ

(3)

ଵାிெெை஻.ிభ .ிమ .…

where: ஼

ೞೠೝ೑ ‫ܨ‬ଵ = ቀிெௌ௎ோி ቁ

ா௉ௌ௎ோி

ிெைூ௅ିௌ

೚ ‫ܨ‬ଶ = ቀிெைூ௅ିி௅ைூ௅ ቁ

(4)

ா௉ைூ௅

(5)


8

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Each of the Fi functions is unity when the foam is at maximum strength with respect to that dependent property. The FMMOB is a constant called the reference mobility reduction factor. The function F1 describes the effect of surfactant concentration on the foam strength, in which FMSURF is the critical surfactant concentration and EPSURF is an exponential parameter. The function F2 describes the destructive effect of oil on foam. FMOIL is the oil saturation above which foam is completely destroyed, and FLOIL is the minimum oil saturation below which oil has no effect on foam strength. EPOIL is an exponential parameter. There are also some other functions which are not mentioned here, and can be found elsewhere10. The effect of foam on the gas is handled via modified relative permeability curves in STARS. The original gas relative permeability curve is associated with FM=1 (no foam). A second set of gas relative permeability curves is generated by rescaling the original gas relative permeability endpoint downward (the endpoint value can be divided by FMMOB). This set is associated with the strongest foam (FM~1/FMMOB). Then, the current value of FM is calculated at each time step for each grid block, and the corresponding value of gas relative permeability is interpolated between these two sets using the current value of FM. This method is shown in Figure 2.


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Figure 2. Effect of foam on gas relative permeability 4. RESULTS AND DISCUSSION 4.1. HIGH VELOCITY TEST In the first run, the sand pack was first saturated with oil, then the baseline steam flood at 80% steam quality and a superficial gas velocity of 847 m/d was started. A high velocity and steam quality was used to mimic the near-well bore condition. The surfactant concentration was 0.5 wt%. The steam flood continued for 7.8 PV until there was no more oil production; the average oil saturation was estimated to be 23% at this point. Surfactant injection was then started, but no further oil recovery was observed. Figure 3 shows recovery the factor for the high velocity run.


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Figure 3. Recovery factor during the base steam flooding and steam foam flooding in the presence of oil at a steam quality of 80% and superficial gas velocity of 847 m/d. Figure 4 shows the MRF of the foam along the core. It also shows the results of a similar test which was carried out in the absence of oil. The average MRF in the absence of oil after 13 PV was 27.4 (steady state value); however, in the presence of oil after 14.3 PV, the average MRF was just 5.7 (steady state value). Thus, an oil saturation of 23% made the foam ~80% weaker. The foam in presence of oil moved more slowly because of a lower MRF, as was discussed in a previous study6. The presence of oil also increased the delay for foam generation somewhat.


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Figure 4. Foam mobility reduction in the core with and without oil at a steam quality of 80% and superficial gas velocity of 847 m/d. 4.2. LOW VELOCITY TEST In this run, the sand pack was first saturated with oil, then a baseline steam flood at 40% steam quality and a superficial gas velocity of 235 m/d was initiated. The lower gas superficial velocity and steam quality should mimic the deeper sections of the reservoir. This should be the minimum velocity for foam generation, based on the results of a previous study6. The steam flood was


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continued for 4.3 PV, then surfactant injection was started to generate foam. After another 3.4 PV (at 7.7 PV after the start of the run, and when the foam was close to breakthrough), the superficial gas velocity was lowered to 48 m/d. Figure 5 shows the cumulative oil production in this run. After switching to the lower velocity, there was a delay ~0.8 PV before any incremental oil was produced from the core.

Figure 5. Cumulative oil production during the base steam flood and steam-foam flood in the presence of oil at a steam quality of 40% and superficial gas velocity of 235 to 48 m/d. Figure 6 shows the oil rate during this delay time, where there appeared to be a small increase in the oil production. The steam-foam process obviously gave some incremental oil in this case.


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It is important to note that the foam breakthrough happened much later than the start of incremental oil production. Figure 7 shows the recovery factor for this test. It is not possible to exactly calculate the recovery factor for the foam at 235 m/d, since the core was already producing some oil because of the steam flood. After switching to the low-velocity foam, the recovery factor increased from ~70% to 95%. It is important to mention that the actual increase in the recovery factor may have been underestimated in this run. First of all, the baseline steam flood was done at a much higher velocity (235 m/d), which gave a higher capillary number and lower residual oil. If the baseline steam flood had been carried out at 48 m/d, more oil would have been left in the sandpack. In addition, it should be noted that the test was stopped while the core was still producing oil. Figure 6 shows the instantaneous produced oil and water rate versus the differential pressure profile of foam in the core (when the core is producing oil, the viscosity of the fluids in the core is constantly changing, so it is not possible to define a baseline pressure drop for the test and calculate the MRF. As a result, only the differential pressure is shown in Figure 6 and later in Figure 8). When foam generation started at 235 m/d, the core was already producing oil because of the steam flood; however, the oil rate was decreasing and became zero. Even after switching to the lower gas velocity, there was no oil production for some time. Thus, the foam generated at 235 m/d possibly did not produce any incremental oil, like the foam generated at high velocity in Section 4.1.


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Figure 6. Differential pressure and the produced oil and water rate during the steam foam flood at a superficial gas velocity of 235 m/d


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Figure 7. Recovery factor during the base steam flooding and steam foam flooding in the presence of oil at a steam quality of 40% and superficial gas velocity of 235 to 48 m/d. Using the differential pressure profile of Figure 6, the foam breakthrough time appears to be approximately 7.7 PV after the start of the test. However, the water rate showed a peak at roughly the same time. This peak can be attributed to the water front which was generated at the core inlet and moved ahead of the foam until reaching the core outlet. Figure 8 shows the differential pressure profile and oil and water rates when the gas velocity was lowered to 48 m/d. At 8.5 PV, a large peak in the oil rate can be observed. However, looking at the differential pressure data, it appears that the differential pressure in the


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Figure 8. Differential pressure and the produced oil and water rate during the steam foam flooding at superficial gas velocity of 48 m/d


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third section of the core was starting to rise, but had not yet reached its maximum value. In other words, the foam front is in the third section of the core, but the foam breakthrough has not yet happened. As a result, there should be an oil bank formed in front of the foam which moves toward the core outlet. The presence of this oil bank has been reported in other studies11. In addition, at ~9 PV, a peak in the water rate was again observed; this was due to the water front in the front of the foam. Farajzadeh et al.12 studied CO2 and N2 foam flooding, and reported that, prior to gas breakthrough, the saturation profiles along the core showed a steep increase of water saturation at the foam front. This was attributed to an effective front-like displacement of the initial liquid. However, this water front cannot be formed during displacement; if this was the case, a clear boundary between the oil bank and the water front behind it could not be observed, and only a water-oil emulsion would be observed at the interface. As was discussed in a previous study6, the water front forms at the core inlet during the apparent delay time for foam generation. Once the foam behind it starts to move, it will push the water front from behind, and the water front, in turn, will sweep the oil in the core and form an oil bank which moves ahead of the water front. Thus, at the core outlet, first the oil bank breakthrough is observed, then the water front breakthrough occurs, and then the pressure profile indicates foam breakthrough. Figure 9 shows this process. It is also important to note that water breakthrough has been observed at both high and low velocities. This means that, when the gas velocity is lowered and a strong foam is generated, it builds up another water front in the core inlet. Most probably, more water is required to generate a stronger foam; this is not available in the core until a water front builds up.


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Figure 9. The MRF of the core sections and the locations of the foam, water front and oil banks at corresponding times. 4.2.1. THE RELATIONSHIP BETWEEN PRESSURE DROP AND OIL SATURATION Figure 10 shows the average remaining oil saturation in the core at different times versus the differential pressure. During the foam flood at a superficial gas velocity of 48 m/d, oil is produced and the oil saturation starts to decrease gradually. As the oil saturation decreases, the foam recovers its strength, and the pressure drop in each section starts to increase. This interesting feature allows the foam to recover more oil, and also provides a way to determine the relationship between the average pressure drop and the oil saturation. To find this relationship, first the average pressure drop of all the three sections of the core was calculated. Then a linear regression was carried out on the average pressure drop. The values of pressure drop coming from the linear regression were then plotted versus the oil saturation at the corresponding time,


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Figure 10. Pressure drop of the three sections of the core versus oil saturation as is shown in Figure 11. The data points show a highly linear trend. The data for higher oil saturations is not available, but the line can be extrapolated assuming that the trend remains linear. The results suggest that the surfactant has a very high oil tolerance, and should be stable at the oil saturations commonly observed in the field


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Figure 11. The relation between the average MRF and oil saturation 4.2.2. THE RELATIONSHIP BETWEEN FOAM STRENGTH AND INCREMENTAL OIL PRODUCTION The results of Figure 11 suggest that the pressure drop has a linear relationship with the oil saturation, which implies that it should be easy to model the effect of oil on foam generation. However, foam generation is a necessary but not sufficient condition for establishing incremental oil production.


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A vertical sandpack was used in this study to remove the possibility of gravity override of the steam in the sandpack. The sandpack was also prepared uniformly to minimize the chance of channelling. This configuration, plus the experimental evidence for the formation of an oil bank, suggests that the incremental oil production is the result of oil displacement by the foam and not by improved conformance of the steam. In fact, the foam can act like a piston and displace the oil because of its lower mobility, although it requires a certain MRF to be able to accomplish that displacement. When the average MRF is below 10 (such as the foam in the high-velocity test), there is very little or no oil production. In the high-velocity test (Section 4.1), the average MRF was ~5, and no incremental oil was produced during the foam flood. The MRF was not shown in Figure 10; however, by using some simplifying assumptions, its value can be estimated. The main difficulty in estimating the MRF is the variable oil saturation in the core, as this changes the viscosity. In the period between 4.3 PV (the start of surfactant injection) and 8.3 PV (before oil breakthrough at 48 m/d), the oil production was not very large, and it can be assumed that the oil saturation is constant, so the MRF in this period can be calculated. The pressure drop at the start of surfactant injection can be taken as the baseline pressure drop (without foam) for calculating the MRF. However, at 8.3 PV, the oil production started again and oil saturation decreased with time, so the viscosity of the fluids in the core should be lower, and the base pressure drop should be lower as well. As a result, the calculated MRF will be underestimated during this period. The results are shown in Figure 12, which shows that, by reducing the gas velocity, the average MRF goes from ~18 to 110. This is possibly the minimum MRF required for oil displacement.


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Figure 12. The relationship between oil saturation and average MRF of the core. The average MRF of the core after 150 min has been calculated assuming that the oil saturation remains constant 4.3. MODELING THE EFFECT OF OIL ON FOAM GENERATION A 2D grid was used to model the core flood results. The Cartesian grid for this model had 10 x 1 x 50 elements (I x J x K). An injector well was used for steam injection, and the producer had a constant bottom-hole pressure. The grid porosity and horizontal permeability were 0.371 and 1200 mD, respectively. For the PVT model, only a single oil component was used (in the oil


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phase). Since the bitumen sample was dead, no gas component was included. The three pseudocomponents used in this PVT model were oil, water and surfactant. The foam parameters initially used for this model are given in Table 2. Table 2. Foam model parameters used for history matching Parameter

Value

FMMOB

220

FMSURF

3.85E-5

EPSURF

1

EPCAP

0

EPOIL

0

FMDRY

0.2

EPDRY

1000

Figure 13 shows the predicted injection pressure (solid curve with FMMOB= 200) versus the laboratory data. When the surfactant is injected (at a superficial gas velocity of 235 m/d) at 4.3 PV, the foam model does not predict the delay time for foam generation and the time that is required for foam to fill the core at a slower frontal velocity compared to that of the surfactant front. In fact, the foam model simply assumes that the foam front always moves with the surfactant front. However, the results of a previous study suggest that the foam front usually moves more slowly than the surfactant front6, so there is a foam front retardation not captured in this model. As a result, the foam model shows an almost instantaneous foam generation (since foam moves with the surfactant in this model), which results in an instantaneous increase in the injection pressure; however, the final value of the pressure is still correct (The foam front


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retardation can be captured by the foam model by adding a tracer which moves slower than the surfactant and connecting the foam strength to the tracer concentration instead of the surfactant concentration. This method has been used in a previous study6, however, it is not possible to use it in STARS). It should be noted that, after switching to the lower gas velocity of 48 m/d, the model fails to predict the injection pressure correctly; the predicted value becomes much lower than the actual amount. The predicted cumulative oil production (see Figure 14, solid line) shows a similar inconsistency. Initially, the oil production was predicted correctly, but after switching to the lower gas velocity, the model did not predict any oil production at all (however, as Figure 8 shows, after switching to the lower gas velocity, the oil production rate was above 0.05 ml/min). In previous sections, it was shown that, after switching to a lower velocity, the foam will be much stronger due to shear thinning behavior or the change in the bubble texture, so using a higher FMMOB in the model (which means a stronger foam) may solve the problem.


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Figure 13. The the bottom-hole pressure of the injector versus the lab data with the new FMMOB


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Figure 14. The the cumulative oil production versus the lab data with the new FMMOB However, it is interesting to note that, no matter how much the FMMOB was increased; no increase in the injection pressure or oil production was observed in the simulation. Figure 13 shows the result of changing the FMMOB to 220,000; the foam becomes 1000 times stronger. The injection pressure can now be matched, but the oil production prediction shows no significant improvement (see Figure 14, dashed line) because, at the time of the velocity change, the liquid saturation in the first half of the core is around 0.52. Using the initial relative permeability curves, the oil permeability will be almost zero at this saturation, so no matter how


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much the gas mobility is decreased by foam, the model predicts that no more oil can be produced. This means that the role of the surfactant is not only in reducing the mobility of the gas phase, but also in changing the mobility of the oil phase, which results in incremental oil production. The injection pressure may look fine in the simulations with the new FMMOB, but in order to match the higher values of pressure which happen after foam breakthrough (such as the 5,700 kPa seen at around 8.5 PV in Figure 13), the FMMOB would need to be in the order of 22,000,000; this is not a reasonable number. Such a high mobility reduction could easily make the gas permeability zero and stop the steam flood completely in the simulation. In order to improve the oil production in the model, the solution is to change the liquid-gas relative permeabilities. The oil rate and injection pressure can only be matched at the same time by changing some of the parameters at different times. Table 3 shows how these parameters must be altered with time. Table 4 shows how the FMMOB parameter changes with each restart file. At later times, a change in FMMOB cannot alter the results significantly; thus, the main parameters for maintaining the pressure are the connate and critical gas saturations and the Corey exponents. Figure 15 shows the schematic graph for relative gas-oil permeability curves and how they change from their initial values to their final values.


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Table -3. Modified Corey parameters for relative permeability data Parameter

Base run

Restart at 7.7 PV

Restart at 7.9 PV

Restart at 8.7 PV

Restart at 9.1 PV

Restart at 9.3 PV

Restart at 9.6 PVn

Restart at 9.8 PV

Restart at 10.9 PV

Restart at 11.5 PV

Restart at 12.3 PV

Connate gas (SGCON)

0.001

0.5

0.62

0.625

0.6285

0.63

0.633

0.633

0.636

0.638

0.68

Critical gas saturation (SGCRIT)

0.001

0.5

0.62

0.625

0.6285

0.63

0.633

0.633

0.636

0.638

0.68

Oil-water Corey exponent (Now)

2.5

2.5

2.5

2.5

2.5

2.5

2.5

1.3

1.3

1.3

1.3

Oil-gas Corey exponent (Nog)

5.3

5.3

1

1

1

1

1

1

1

1

1

1

7

7

7

7

7

7

7

7

7

6

Gas Corey exponent (Ng)

Table 4. Foam model parameter changes at different runs Parameter

Base run

Restart at 7.7 PV

Restart at 7.9 PV

Restart at 8.7 PV

Restart at 9.1 PV

Restart at 9.3 PV

Restart at 9.6 PVn

Restart at 9.8 PV

Restart at 10.9 PV

Restart at 11.5 PV

Restart at 12.3 PV

fmmob

220

500

5000

5000

5000

5000

5000

5000

5000

5000

5000


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Figure 15. The change in the gas–oil relative permeability curves during the simulation The changes in the relative permeability parameters started at 7.7 PV, when the superficial gas velocity changed from 235 to 48 m/d. The shear thinning behavior of foam or the change in the bubble texture should result in a much stronger foam at this lower velocity. Both the connate and critical gas saturation now increase significantly (in the model), which means that a very large amount of gas would be now immobilized. Foam bubbles can exist in the pores as both trapped and flowing phases. The decrease in the gas-phase relative permeability due to the trapping of the bubbles has been reported before13. It seems that the bubble trapping only occurred at the lowest superficial gas velocity. Friedmann et al.13 suggested that since the capillary forces that trap foam bubbles are stronger in smaller pores, it is more likely that the trapped bubbles will reside in the smaller of the gas-filled pores, while the flowing bubbles will


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be in the largest. So it is possible that at higher gas velocities, the foam bubbles only generated in the bigger pores and no trapping occurred, however, by decreasing the gas velocity the foam bubbles started to be generated in the smaller pores and were trapped there. The gas Corey exponent was also increased in the model to further decrease the gas permeability. It should be noted that, at around 7.9 PV, the relative permeability parameters change again in the model. This is the time at which a stronger foam starts to generate and fill the core. The connate and critical gas saturations were increased somewhat in the model to match the injection pressure increase, and the oil-gas Corey exponent was decreased in order to increase the oil permeability at lower liquid saturations. If this exponent did not change, then the oil permeability would remain very low and no oil would be produced at all. At later times, the connate and critical gas saturation can be increased stepwise to match the pressure data. As Table 4 shows, the FMMOB parameter in the foam model remains constant. At 7.7 PV, when both the connate and critical gas saturations are changed from 0.001 to 0.5, it is possible to increase the FMMOB to get the same pressure drop instead of increasing the connate and critical gas saturation gradually to achieve this effect. However, the FMMOB should rise to large values in the order of 100,000 to match the pressure. It is also possible to combine the increase in connate and critical gas saturation and FMMOB to match the injection pressure; however, this option has not been tried in this study. Later, at 9.8 PV, the oil-water Corey exponent was also decreased to give a higher permeability to the oil phase in order to be able to match the oil production data. The fact is that in steam-foam flooding with a high steam quality, the amount of flowing liquid water in the pores can be very limited 6. A high steam quality results in a low volume fraction of the liquid water. The water saturation in the pores can be high, but the majority of this water is connate water which cannot be moved. So when the strong


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foam generation starts, it is possible that the majority of the flowing water in the pores be used for foam generation. If the foam bubbles are trapped in the pores, it simply means that this liquid water (which now forms the foam lamellae) is trapped too. So the result will be a reduction in both the water and gas relative permeability and an increase in the oil relative permeability. As a result the oil-water and oil-gas Corey exponent changed to account for this increase. Figure 16 (solid line) shows the predicted cumulative oil production versus the laboratory data. In the period between 7.8 and 8.5 PV, the predicted values are higher than the laboratory data. The reason for this is that the foam model given an almost instantaneous foam generation, but in actuality the foam moves with a slower velocity and needs some time for breakthrough. Figure 17 (solid line) depicts the predicted injection pressure, and a similar deviation can be seen in the injection pressure during the same period from 7.8 and 8.5 PV. However, at other times, the pressure and the oil rate can be matched reliably. The results of this history matching exercise are consistent with the results of Section 4.2.2. They suggest that the foam is doing more than simple conformance control in the core, and it has the ability to change the oil mobility significantly. The fact that increasing the mobility reduction of the gas phase alone cannot match the oil production in the core suggests that the current implicit-texture foam model needs some modifications. First of all, the increase in the critical gas saturation due to the bubble trapping should be incorporated into the model. However, this increase only happened at the lowest gas velocity and can be a function of the gas velocity. In addition, the trapping of liquid water inside the bubbles can be also important which results in a change in the relative permeability of the oil phase in the lower gas velocities. More research is necessary to improve the model.


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Figure 16. The cumulative oil production versus the lab data with the modified relative perms


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Figure 17. The bottom-hole pressure of the injector versus the lab data with the modified rel perms 5. CONCLUSIONS In this study, a steam-foam core-flooding was carried out to investigate the effect of oil saturation on foam generation. The experiments were carried out at two different gas velocities to mimic both the near well-bore and deep reservoir conditions. The results showed that the presence of oil had a detrimental effect on the foam strength; however, foam can be still


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generated in the presence of oil. At higher velocities, the generated foam could not improve the oil recovery, but when the velocity was lowered, foam generation could significantly improve the oil recovery from the core. The results of this study suggested that the surfactant has a good tolerance for the presence of oil. This suggests that steam foam using this surfactant could be a good candidate for a steam assisted gravity drainage (SAGD) process. The short distance between the SAGD well pairs ensures a high concentration of the surfactant in the porous medium and a high MRF of the generated foam, which would be able to improve the oil displacement towards the producer well. More studies would be needed to evaluate the efficiency of a foam-based SAGD process. Finally the STARS foam model was used to model the experimental results. The results suggested that scaling down the gas relative permeability endpoint was not enough to match the injection pressure and cumulative oil production, and both the oil-water and liquid-gas relative permeability curve needed to change to match the results. AUTHOR INFORMATION Corresponding Author *E-mail: [email protected]. Phone: +1 (403) 384 7821

REFRENCES

1.

Schramm, L. L.; Novosad, J. J., The destabilization of foams for improved oil recovery

by crude oils: effect of the nature of the oil. J. Pet. Sci. Eng. 1992, 7, 77-90.


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2.

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Jensen, J. A.; Friedmann, F., Physical and chemical effects of an oil phase on the

propagation of foam in porous media. SPE 16375 In 57th California Regional Meeting of the Society of Petroleum Engineers, Ventura, CA, 1987. 3.

Schramm, L. L., Chapter 4: Foam sensitivity to crude oil in porous media. In Foams:

Fundamentals and Applications in the Petroleum Industry, Schramm, L. L., Ed. American Chemical Society: Washington D.C., 1994. 4.

Rossen, W. R., Foams in Enhanced Oil Recovery. In Foams: Theory, Measurements and

Applications, Prud'homme, R. K.; Khan, S., Eds. Marcel Dekker: New York, 1996; pp 413-464. 5.

Isaacs, E.; Jiant, L.; Green, K.; McCarthy, C.; Maunder, D., Use of Foam-Forming

Surfactants to Enhance the Recovery of Heavy Oils. AOSTRA J. Res. 1988, 4, 267-276. 6.

Bagheri, S. R., Experimental and Simulation Study of Steam-Foam Process. Energy

Fuels [Online early access]. DOI: 10.1021/acs.energyfuels.6b02341. Published online: Dec 1, 2016. http://pubs.acs.org/doi/abs/10.1021/acs.energyfuels.6b02341 (accessed Dec 15, 2016). 7.

Maini, B. B.; Ma, V., Laboratory evaluation of foaming agents for high temperature

applications -II. measurements of thermal stability and foam mobility in porous media. In 36th Annual Technical Meeting of the Petroleum Society of CIM, Edmonton, Alberta, Canada, June 25, 1985. 8.

Mohammadi, S. S.; Coombe, D. A.; Stevenson, V. M., Test of steam-foam process for

mobility control in South Casper Creek reservoir. J. Can. Pet. Technol. 1993, 32, (10), 49-54. 9.

Ma, M.; Ren, G.; Mateen, K.; Morel, D.; Cordelier, P., Modeling Techniques for Foam

Flow in Porous Media. SPE J. 2015, 20, (3), 453-470.


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10. Computer Modeling Group (CMG) Ltd., STARSTM User's Guide, Version 2015. Calgary, Canada, 2015. 11. Farajzadeh, R.; Andrianov, A.; Zitha, P. L. J., Investigation of Immiscible and Miscible Foam for Enhancing Oil Recovery. Ind. Eng. Chem. Res. 2010, 49, 1910–1919. 12. Farajzadeh, R.; Andrianov, A.; Bruining, H.; Zitha, P. L. J., Comparative Study of CO2 and N2 Foams in Porous Media at Low and High. Ind. Eng. Chem. Res. 2009, 48, 4542–4552. 13. Friedmann, F.; Chen, W. H.; Gauglitz, P. A., Experimental and simulation study of hightemperature foam displacement in porous media. SPE Reservoir Eng. 1991, 6, (1), 37-45.


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Figure 1 199x131mm (300 x 300 DPI)


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Figure 2 80x53mm (300 x 300 DPI)


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Figure 3 160x135mm (300 x 300 DPI)


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Figure 4 151x149mm (300 x 300 DPI)


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Figure 5 154x140mm (300 x 300 DPI)


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Figure 6 167x242mm (300 x 300 DPI)


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Figure 7 154x140mm (300 x 300 DPI)


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Figure 8 168x249mm (300 x 300 DPI)


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Figure 9 70x41mm (300 x 300 DPI)


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Figure 10 168x138mm (300 x 300 DPI)


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Figure 11 154x122mm (300 x 300 DPI)


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Figure 12 165x146mm (300 x 300 DPI)


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Figure 13 156x134mm (300 x 300 DPI)


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Figure 14 154x135mm (300 x 300 DPI)


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Figure 15 90x67mm (300 x 300 DPI)


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Figure 16 154x139mm (300 x 300 DPI)


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Figure 17 156x134mm (300 x 300 DPI)


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The Effect of Oil on Foam Generation - American Chemical Society

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