Immiscible Foam for Enhancing Oil Recovery - American Chemical

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Immiscible Foam for Enhancing Oil Recovery: Bulk and Porous Media Experiments A. Andrianov,† R. Farajzadeh,*,‡ M. Mahmoodi Nick,§ M. Talanana,‡ and P. L. J. Zitha⊥ †

Improved Oil Recovery team, Shell Global Solutions International, Kessler Park 1, 2288GS Rijswijk, The Netherlands Enhanced Oil Recovery team, Shell Global Solutions International, Kessler Park 1, 2288GS Rijswijk, The Netherlands § IOR studies, Statoil TNE, Sandslihaugen 30, room B256, Postboks 7200, Bergen, Norway ⊥ Dept of Geotechnology, Faculty of Civil Engineering and Geosciences, Delft University of Technology, Stevinweg 1, 2628CN Delft, The Netherlands ‡

ABSTRACT: This paper reports a laboratory study of foams intended to improve immiscible gas flooding in oil production. The study is relevant for both continuous and water alternating gas (WAG) injection schemes. The effect of oil on the longevity of nitrogen and air foams was studied in bulk for a selected set of surfactants. Foam heights were measured in a glass column as a function of time, in the absence and presence of mineral and crude oils. The column experiments indicated that foam longevity increases as the carbon chain length in the oil molecule increases; that is, foam is generally more stable in the presence of higherviscosity oils. The surfactant formulation that gave the most stable foam in the presence of oil was used in core floods. Oil recovery from natural sandstone cores with CO2 and with N2 foams was studied with the aid of X-ray computed tomography, while the injection rates, foam quality, and surfactant concentration were varied. The core floods revealed that foam increases oil recovery by as much as 20% of the oil initially in place (OIIP) as compared with water flooding, while gas injection increases oil recovery by 10% only. Thus, foam can achieve an additional recovery of up to 10% relative to gas injection. This confirms that foam is potentially an efficient enhanced oil recovery (EOR) method.

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flooding due to its ability to reduce gas mobility.12,13,15,18,35,39 There have been many successful field applications of foam30,35 as shown by the detailed review39 of foam projects executed in the USA until 1998. Foam generation is achieved either by coinjection of the gas and surfactant solution into the reservoir or by surfactant alternating gas (SAG) injection, similar to WAG.1,35,44 The best documented foam application to date has been performed in the Snorre field, offshore Norway.35 In recent years foam has been also used in the Ula field, for example.3 However, until recently foam has mainly been studied and applied as a mobility control agent. Only few studies and field pilots have focused on the use of foam drives to recover tertiary oil.1 The goal of this study is to gain insight into foam behavior in the presence of oil and to investigate the impact of foam−oil interactions on oil recovery by foam. A 2-fold approach was adopted for this purpose. First, foam−oil interactions were investigated by column experiments (bulk foam) with a selected set of surfactants. The effects of alkanes and crude oils on foam stability were investigated to find a surfactant solution that could generate a sufficiently oil-tolerant foam. The surfactant or mixture of surfactants that gave the most stable bulk foam in the presence of oil was used to perform the core floods. In these experiments the foam behavior and its effect on oil production in porous media containing oil (core flood

INTRODUCTION In the extractive production of oil from subsurface reservoirs, 65% of the oil initially in place (OIIP), on average, is left in the reservoir after as much oil as possible has been recovered by natural depletion and with the aid of water flooding.14,22 This residual oil is a target for enhanced oil recovery (EOR) methods, which currently include gas or solvent flooding, chemical flooding, thermal recovery, and combinations of these techniques. In gas flooding a compressed gas such as carbon dioxide (CO2), natural gas (consisting primarily of methane, CH4), nitrogen (N2), or flue gas is injected into the reservoir to displace oil toward the production wells. The injected gas either partially dissolves in the oil (immiscible gas flooding) or mixes completely with it (miscible flooding), leading mainly to swelling of the oil, viscosity reduction of the oil phase, and lowering of the interfacial tension (IFT) between the oil and displacing phase. Immiscible gas flooding can potentially recover a large fraction of the remaining oil after primary depletion or water flooding (WF). However, such potential has hardly ever been realized because of the poor vertical and areal sweep efficiency. Gas segregation and channeling (or fingering) through high permeability streaks are inherent in any gas flooding;1,2,8,9,32 they are due to the far higher mobility and far lower density of gas compared to oil or water. Water alternating gas (WAG) has been used to increase the gas segregation length, thereby enlarging the area swept in the reservoir. However, incremental oil recovery with WAG has remained modest due to the eventual segregation of water and gas.1 Foam emerged in the 1960s as a promising technology for improving the reservoir sweep efficiency in gas and steam © 2012 American Chemical Society

Received: Revised: Accepted: Published: 2214

August 23, 2011 December 28, 2011 January 5, 2012 January 5, 2012 dx.doi.org/10.1021/ie201872v | Ind. Eng.Chem. Res. 2012, 51, 2214−2226

Industrial & Engineering Chemistry Research

Article

droplet and the gas phase. If the pseudoemulsion film is ruptured, the oil may spread and form a lens at the aqueous phase/gas interface. It should be borne in mind that these theories have been developed for bulk foam and may not be directly relevant for foam in porous media.

experiments) were examined with the aid of computed tomography (CT) imaging.

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BACKGROUND Foam is a dispersion of gas in a continuous liquid phase in which gas bubbles are separated by thin liquid films called lamellae (they can also be called foam films).7,38 This foam microstructure gives foam a much higher apparent viscosity than the free gas, thereby improving the mobility ratio between the displaced and displacing phases.7,11,16,17,19,24,29,31,35,39 Foam is a metastable system that coarsens spontaneously and finally decays completely due to liquid drainage from the lamellae and Plateau borders (lamellae intersections) and to capillary suction. This leads to rupture of the foam films and destruction of the foam. The lamellae are stabilized by means of surfactants10 or, to a lesser extent, polymers and nanoparticles; this study is focused on foams stabilized by surfactants. A typical surfactant is a polar or ionic molecule consisting of a hydrophilic head and a hydrophobic tail. Because of this dual nature the surfactant molecules have a strong affinity for interfaces between immiscible fluids, such as gas−water and oil−water. The surfactant molecules adsorb on these interfaces so that their hydrophilic ends are in the aqueous phase, and their nonpolar ends are on the nonaqueous phase.6 The adsorption of surfactant molecules at gas−liquid interfaces, in particular, stabilizes the lamellae, that is, thin liquid films, by adding a repulsive force between the two bounding gas−liquid interfaces.26 The surfactants in our case mainly change the elasticity of the surfaces, thereby preventing their intense undulations and reducing the probability of their rupture. Moreover, the surfactant molecules reduce the gas−liquid interfacial tension, that is, its surface energy, thereby assisting the formation of small bubbles. The main concern with the use of foam as an EOR method has been its survival in the presence of crude oil. Both bulk and porous media experiments have shown that certain oils could be detrimental for foam stability,4,21 but this has not been supported by other studies which have shown that foam could be relatively stable in the presence of oils.25 No solid theory has yet been developed that can fully account for all the experimental observations. Nevertheless, it has been possible to establish qualitative correlations of foam stability by means of parameters dependent on surface energies. Formulas for entering, spreading and bridging coefficients and lamellae numbers are presented in Table 5; these parameters are used to analyze foam stability. The entering coefficient E equals the sum of water−gas interfacial tension (IFT) and water−oil IFT minus oil−gas IFT: E = σw/g + σw/o − σo/g. Foam will be stable in the presence of oil if the entering coefficient E is negative or if the corresponding spreading coefficient S is also negative.23,28,34,35,40,41 Oil will neither enter into nor spread at the aqueous phase/gas interface; hence, oil will not act as a defoamer. If E is positive, the oil enters into the lamellae and may or may not spread. If in addition S > 0 the oil spreads at the gas−water interface and causes the lamellae to rupture. If S < 0 the oil does not spread in principle, but we cannot draw conclusions on the lamellae destabilization. Two other parameters have been used to investigate whether oil becomes emulsified and imbibes into the foam lamellae: the lamellae number L33,34 and the antifoaming efficiency of certain oil additives to foam, termed the bridging coefficient B.20,28 The stability of foam in the presence of oil can also be related to the stability of the pseudoemulsion film generated between an oil

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EXPERIMENTS Materials and Methods. Brine containing 3 wt % of NaCl, comparable to seawater in terms of salinity, was used in all bulk and porous media experiments. The surfactants used to conduct the experiments are listed in Table 1. For the bulk Table 1. Properties of the Surfactants Used in This Study short name

surfactant alpha olefin sulfonate (1) alpha olefin sulfonate (2) sodium dodecyl sulfate fluorochemical (1) fluorochemical (2) perfluoroalkyl betaine surfactant (1) perfluoroalkyl betaine surfactant (2)

supplier

active content (%)

charge

AOS-1

Stepan

40

anionic

AOS-2

40

anionic

SDS FC-1 FC-2 FS-1

Shell Chemicals Fischer 3M 3M Dupont

90 25 25 27

anionic nonionic nonionic zwitterionic

FS-2

Dupont

40

zwitterionic

experiments, the surfactant concentration was kept constant (either at 0.5 or in some tests 1.0 wt %), well above the critical micelle concentration (cmc). The surfactants were supplied in the liquid phase with the active contents given in Table 1. Mixtures of surfactants (i.e., AOS-1+FC-1, AOS-1+SDS, AOS2+FS-1) were also tested to study the effect of combining good foaming and oil tolerance (e.g., the good foaming ability of AOS and high oil tolerance factor of FC/FS surfactants). AOS, FC, FS surfactants numbered “1” and “2” have different molecular weight. Important factors in the choice of surfactants are their environmental properties (e.g., according to OSPAR diagrams) and their toxicity, especially in the case of fluorinated surfactants. The gas used in the bulk experiments was either N2 with 99% purity or air. Both CO2 and N2 gases were used in the core floods under immiscible conditions. N2 gas was used in most of our foam experiments while CO2 was used in the gas injection experiment. Under the experimental conditions of this study the dissolution of CO2 into the aqueous phase was assumed to be as discussed elsewhere.8 The oils used to conduct the experiments were the alkanes, pentane (C5), decane (C10), and hexadecane (C16), and crude oils from five oil reservoirs in the Middle East. The molecular weights, densities, viscosities, and surface tensions of these crude oils (denoted A to E) are given in Table 2. For the surfactants used in the core floods the surface tensions, oil− water interfacial tensions (IFT) were measured as function of concentration and then the cmc values were determined. The bulk experiments showed that foam could be stable with various combinations of surfactants and oils. In particular, foam produced with nitrogen and the AOS+FC mixture had the highest longevity in the presence of n-hexadecane. This combination was used in the subsequent core floods. The interfacial tensions of n-hexadecane/air, n-hexadecane/water and n-hexadecane/AOS+FC were measured as 28.7 ± 0.2, 51.0 2215

dx.doi.org/10.1021/ie201872v | Ind. Eng.Chem. Res. 2012, 51, 2214−2226


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column setup (Figure 2) consisted of a graduated glass cylinder with the same dimensions as the glass column in the first setup.

Table 2. Physical Properties of Crude Oils oil

density @ 20 °C (g/cm3)

molecular weight (g/mol)

A

0.838

223.0

B

0.853

224.0

C

0.874

253.2

D

0.909

380.3

E

0.931

459.2

viscosity (mPa·s) 2.08 (77 2.99 (69 5.76 (60 102 (46 304 (50

°C) °C) °C) °C) °C)

viscosity (20 °C) (mPa·s)

API gravity (°API)

surface tension (mN/m)

6.72

37.82

24.98

9.04

34.77

25.53

18.90

30.44

26.73

402.29

24.70

28.42

2725.85

20.18

30.09

± 0.2, and 1.5 ± 0.2 mN/m, respectively, at room temperature and atmospheric pressure. Core Material. The core material used in the experiments was Bentheim sandstone, which mainly consists of quartz, and is quasi-homogeneous and isotropic. Table 3 presents the main Table 3. Bentheim Sandstone Core Properties permeability (mD)

porosity (%)

length (mm)

effective diameter (mm)

main composition

1200 ± 10

22 ± 1

170 ± 0.1

38 ± 0.1

quartz

physical properties of the Bentheim sandstone core. The porosity was measured by X-ray computed tomography (CT scan). The total pore volume of these cores was 42.5 ± 2.0 mL. The cores were mounted inside a cylindrical core holder, made of polyether ether-ketone (PEEK). This material has good mechanical strength and low X-ray attenuation. Before it was mounted inside the holder, the core was encapsulated in a 2 mm thin layer of Araldite resin with low X-ray attenuation. This was done to fit the core into the core holder and prevent possible wall effects such as fluids potentially bypassing the core along the low-resistive interface of the core holder. Foam Column Setup and Procedures. Foam column setup. Two set-ups allowing visual observation and measurement of foam heights were used to study foam stability. The first one (Figure 1) consisted of a glass column with a diameter

Figure 2. Second setup used for bulk foam experiments; air is dispersed into 300 mL solution by mixer.

To create the foam, air was dispersed into the surfactant solution. Then the height of the foam column was monitored over time to measure the longevity of the foam. The surfactants listed in Table 1 and their mixtures were tested to check the stability of their foams in the absence and presence of oil. Foam Column Procedures. Preliminary foam tests were conducted by shaking bottles containing the surfactant, which were inspected regularly to estimate to what extent the foam volume had diminished. In the first setup 30 mL of surfactant solution was used to make the foam. Nitrogen gas was supplied at a flow rate of 144 mL/min (±5%). In the second setup 300 mL (in some cases, 150 mL) of surfactant solution was used. The gas was air, and the mixer used to generate the foam was a Retsch MR1. There was an unlimited air supply and no constraint was imposed on foam expansion during the mixing. Foam was obtained by mixing for 5 min at a speed of 2000 rpm; after the foam was mixed, the column was sealed. For all core flood experiments the surfactant concentration was 0.5 wt % (active content) in brine. A foam column was obtained with all surfactant solutions in both set-ups. The experiments were performed at room temperature (T = 20 °C) and atmospheric pressure. For the experiments with oil, two different methods of adding oil to the system were tested. In the first setup, after making the foam column, we waited for 2 min to have the foam surface stabilized, and then 1 mL of oil was sprayed over the foam column. In the second setup, 1 wt % of oil was added to the surfactant solution before the mixing: the amount of added oil was calculated as a weight fraction of the total surfactant solution, and the oil was dispersed in the solution during mixing. In all the experiments the height of the foam column (foam decay) above the liquid phase was measured as a function of time after the foam had been generated. Some of bulk foam experiments were repeated to ensure their reproducibility.

Figure 1. First setup for the bulk foam experiment; nitrogen is injected through the sandstone.

of 5 cm and height of 50 cm with a porous disk made of medium-sized sintered glass beads at the bottom. A mass-flow controller connected to the bottom of the setup ensured that gas was injected at the constant flow rate. The second foam 2216



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Core Flood Setup and Procedures. Core Flood Setup. The core flood setup was designed for conducting both highand low-pressure experiments (only low-pressure experiments are presented in this paper). The details of the setup and core preparation are described in detail elsewhere.8,9 The pressure was monitored at five locations within the core. The outlet of the core was connected to the back-pressure regulator (set to atmospheric pressure). Since the pressure drops at the different sections of the core were small and within experimental error, only the overall pressure drop is reported, that is, the pressure difference between the core inlet and outlet. Moreover, the CT scanner was used in all the core flood experiments. The contrast of oil and water in the CT scans was low, 7.5 wt % sodium tungstate (Na2WO4.2H2O) was added to the surfactant solution to increase in the contrast between oil and water. We verified that at this concentration the IFT and foaming properties of the solution were only marginally affected. Core Flood Procedures. Three types of experiments were conducted in this study: CO2 gas flooding, combined CO2 gas and N2 foam flooding, and N2 foam flooding. The experiments were conducted according to the procedure summarized in Table 4. All experiments were conducted with the core placed vertically and under gravity-stable conditions.

gravity-stable displacement, oil was injected at a very low rate (0.5 mL/min.). In each experiment 15 mL of oil was injected, but only 13.5 mL (i.e., 0.35 PV of the core) actually penetrated the core; the difference is due to dead volumes. This means that the bottom section of the core was never contacted by oil and could be used as a foam generation “chamber”. Part of the core was deliberately left free of oil in order to avoid an entrance effect, that is, to generate a strong foam. Subsequently, water was injected from the bottom to simulate water flooding (WF), resulting in a post-WF residual oil saturation Sorw. In our experiments with different oils and flow rates we observed slightly different oil recoveries by water, which can be explained by the Buckley−Leverett theory. The water injection rate in WF was always between 2 and 4 mL/min.; 7 to 8 PV of brine were injected until no more oil was produced and the oilbearing part of the core was at the experimental residual oil saturation Sorw. The main WF-assisted recovery of oil is always achieved before the water breakthrough during injection of the first 1.0 PV. About 50% of the oil initially in place was produced during this stage. After the water flooding, either CO2 was injected (experiment 1a in Table 6) or the core was flushed with 1.0 PV of surfactant solution to saturate the core with surfactant, satisfy surfactant adsorption, and ensure a good foam generation (experiments 1b, 2, 3, and 4 in Table 6). After the surfactant preflush, N2 gas and surfactant solution were coinjected to generate foam and displace the oil. Foam behavior was evaluated by means of CT scan images and the oil recovery results, and by measuring the steady-state mobility reduction factor (MRF), which is defined as the ratio of foam to no-foam pressure drops at the same injection rates.1,8,27 CT Scan Data Processing. CT scan images obtained during core floods are maps of the attenuation coefficients of the core and the flows. They are expressed in Hounsfield units (HU) as follows:

Table 4. Summary of the Experimental Procedure Used in the Core-Flood Experiments flow rates

step

description

1

flush core with CO2 to remove air saturate core with brine inject oil into core (primary drainage) displace oil by brine (imbibition) displace oil with surfactant solution (imbibition) gas flooding foam flooding

2 3 4 5

6a 6b

pore volumes injected (PV)

back pressure (bar)

>10

1

20

>10

25

0.5

0.35

1

2−4

7−8

1

2−4

1−2

1

3.5 3.5

1 1

liquid (cm3/min)

gas (scm3/min)

2/60

1 1

HU = 1000(μ − μw )/μw where μ and μw are the local attenuation coefficients of the specimen and of pure water. Clearly for vacuum HU = −1000 and for pure water HU = 0. Later, the saturations can be estimated.

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RESULTS AND DISCUSSION Column Experiments. Figures 3 through 6 show relative foam heights versus time. Relative foam height is h/h0, where h is the foam height at the present time and h0 is the initial foam height. Foam in the Absence of Oil. After foam generation, the foam height decreases gradually. Foam collapse is caused by slow liquid drainage, which leads to foam thinning and eventually rupture of foam films. Foam decays fast when most of the liquid has drained out of the Plateau borders. Figures 3 and 4 show the normalized foam heights in the absence of oil for some of the surfactants studied. For the experiments with the first setup, the SDS foam exhibits the highest stability for the full duration of the test, while AOS-1 produces the most stable foam initially, and the fluorinated surfactant (FC-1) shows the least stability in the absence of oil. The texture of the SDS foam is very fine and its coarsening rate is much slower than that of other foams, while the FC-1 foam’s coarsening rate is the highest out of the surfactants examined. However, in these tests the foam column

Table 5. Spreading and Entering Coefficients, Lamella and Bridging Numbers for 0.5 wt % AOS-1 Foam in the Presence of Alkanes spreading

entering

lamella

bridging

formulas

S = σw/g − σw/o − σo/g

E = σw/g − σw/o − σo/g

B = σw/g2 − σw/o2 − σo/g2

pentane decane hexadecane

8.81 1.40 −2.28

16.66 9.44 6.64

L= 0.15σw/g/ σw/o 1.13 1.10 0.98

597.95 304.95 142.51

To saturate the core, first the sandstone core was flushed with at least 10 pore volumes (PV) of CO2 gas to remove all the air. Then the core was flooded with brine at a back-pressure of 25 bar to ensure that all the CO2 gas was dissolved in water and the core was 100% saturated with brine: this flooding took about 3 h, which corresponds to about 10 PV of injected brine. Next, the oil was injected from the top of the vertical core (primary drainage). To avoid instabilities in the core and ensure 2217



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Table 6. Summary of Core Flood Experiments with N-Hexadecane Recovery Factor, RF expt

type of gas

type of surfactanta

waterb

gas

1a 1b 2 3 4

CO2 N2 N2 N2 N2

None AOS+c AOS+ AOS+ AOS+

51%

10%

49% 53% 56%

surfactantd

foam

total

2.0% 3.0% 6.6%e 4.0%

15.3% 21.0% 10.0% 21.0%

78.3% 73.0% 69.6% 81.0%

a The surfactant concentration is 1 wt %. For experiment 4 it is 0.5 wt %. bExperimental error in the recovery is ±2%. cAOS+ represents mixed surfactant (AOS + FC). dOil recovery by 1 PV of surfactant injected. eOil recovery by 2 PV of surfactant.

Figure 6. Relative foam height for different 0.5 wt % surfactant solutions (first setup, 1 mL of n-decane was sprayed).

Figure 3. Relative foam height; foam made with 0.5 wt % of surfactant solution in brine, no oil (first setup, not sealed).

was not sealed. When gas injection (and foam generation) is stopped (Figure 3, time 0), the SDS foam initially undergoes a steady decay followed by a leveling off to the constant foam height; the AOS-1 foam and AOS-1/FC-1 mixture foam show a constant foam height initially which then starts to decay. The FC-1 foam shows a different behavior altogether: the foam is very stable in the first stage of the experiment, but later decays rapidly. The initial decay rate is related to the stability of the thin lamellae films. Figure 4 reports results obtained with the second setup. For both AOS-2 and FS-1 surfactants the generated foams are rather stable over relatively long periods of time. However, the FS-1 based foam (not shown in the figure) lasts much longer, up to a week. Over time the thin lamellae films become almost invisible to the naked eye; this probably coincides with the black film regime. The AOS-2 based foam collapses after around 12 h. Foam Stability in the Presence of Alkane. The effect of three alkanes having different molecular weights and five crude oils on foam stability was investigated to identify a surfactant that could generate sufficiently oil-tolerant foam. The initial foam column height was similar for all surfactants (30.0 ± 0.5 cm). However, foam collapse occurred when oil was sprayed on top of it. In the second setup 1 wt % of oil was added to the surfactant solution before foam generation. Figure 5 shows that for the foam obtained with 0.5 wt % AOS-1 solution (active content), the strongest destabilizing effect was observed with npentane in the first stage of the test, and with n-decane in the second stage. With n-decane, the foam almost disappeared in less than 50 min. The presence of n-pentane leads to moderate destruction of foam, while n-hexadecane is the least active defoamer (compare the AOS-1 curves in Figures 3 and 5). It appears from these observations that the lighter synthetic oils are more harmful to foam. The experiments with AOS-1 were repeated to ensure their reproducibility. New tests confirmed

Figure 4. Relative foam height; foam made with 0.5 wt % of surfactant solution in brine in the absence of oil (second setup).

Figure 5. Relative foam height in the presence of oil for 0.5 wt % AOS1 solution (first setup, oil was sprayed). 2218



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the results shown in Figure 5: the alkane with the lowest carbon number had the strongest destabilizing effect on the generated foam, and that, as demonstrated above, n-hexadecane is less harmful to foams produced with the chosen surfactant−oil combinations. In the next set of experiments two oils were selected with different surfactants for foam generation, that is, n-decane and n-hexadecane (Table 1). The results indicated that the surfactant mixture AOS-1 + FC-1 (ratio of 1:1) created the most stable foam in the presence of the oils (see Figures 6 and

Figure 9. Foam longevity for solutions with 0.5 wt % of active content of surfactant in brine and 1 wt % of n-hexadecane (second setup, oil added to the solution).

Figure 9 shows foam stability in the presence of 1 wt % of nhexadecane (second setup). In these tests oil was added to the surfactant solution. First the figure demonstrates that oil spraying is far more harmful to foams. Stable foams were achieved with all surfactant solutions (one particular mixture, AOS-2 and FC-2 in a 1:1 ratio, created less stable foam). Foam Stability in the Presence of Crude Oils. Figure 8 shows the normalized heights of foam generated with 0.5 wt % of AOS-1 solution, with 1 mL of different crude oils A−E sprayed on top of the first setup’s foam column (coalescence of the bubbles starts at this moment). The oils started to drain out, destroying the foam at different rates. In some cases oil stayed in the skeleton of lamellae and Plateau borders even after most of the lamellae were broken (otherwise the oil phase lies in between the water phase and the remainder of the foam column); this corresponds to the most stable foam. The foam was most stable with oil E which has the highest viscosity. Oil B gave the most unstable foam, which completely disappeared in about 35 min. The literature and our results indicate that the general trend seems to be that more viscous oil is less harmful to foam, while lighter oil is a more active defoamer (although the lighter oil can be more easily displaced by foam). Interpretation of Foam Stability. The spreading (S) and entering (E) coefficients, lamella L and bridging numbers B for the alkanes used in our tests are listed in Table 5 together with their calculation formulas. A detailed description is provided by Vikingstad et al.40,41 and in the Background section. All coefficients in Table 5 depend on surface and interfacial tensions, so the accuracy of these measurements is important. Foam stability in the presence of oil is related to a negative entering coefficient, which implies a negative spreading coefficient. Only hexadecane has a negative spreading number and minimum entering number. According to our observations, hexadecane has the least destabilizing effects on foam. With respect to lamella number, the foam with hexadecane present has the best stability in the presence of oil. Pentane and decane foams are in the moderate foam range; our experiments confirmed this. Skauge et al.35 came to the same conclusion. Core Flood Experiments. Drainage and Imbibition. Figure 10 shows the CT scan images obtained at different times during top-to-bottom primary drainage in a core previously saturated with brine. The images are water saturation maps obtained by subtracting the images taken during oil injection from those for the oil-saturated core, and dividing the result by the difference between the images for the fully water- and oil-

Figure 7. Foam column height for different 0.5 wt % surfactant solutions (first setup, 1 mL of n-hexadecane was sprayed).

7). This model systema combination of surfactant mixture and hexadecane oilwas selected for the core flood experiments. Suffridge et al.36 studied the effect of C11 and C18 alkanes on foam stability. They found that alkane with a lower molecular weight is less favorable for foam longevity than alkane with a higher molecular weight: foam in the presence of C18 was the more stable one (even more stable than with no oil at all). This is in line with the results we obtained with C16 oil (with the second setup as shown in Figure 9). Generally, any factor which

Figure 8. Foam column height for solutions of 0.5 wt % AOS-1 in brine and 5 wt % of different crude oils. Oil viscosities are given in Table 2.

reduces the rate of drainage (under gravity) from the Plateau borders may increase the stability of films. The oil may be present as a continuous phase inside the Plateau borders. Nonpolar oils, like long-chain hydrocarbons, usually make asymmetric films very stable. This could lead to better foam stability as a consequence of slower film drainage.7,8,37 2219



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Leverett displacement. The “inlet” saturation So = 0.58 ± 0.01 is much smaller than the range of values 0.82−0.86 corresponding to connate water saturation So = 1 − Swc as determined from our SCAL measurements on the Bentheim core. It should be noted that the inlet was not measured exactly at the edge of the core but corresponds instead to an average value over a short length in the core. Oil saturation decreases along the direction of flow (vertically downward). First it decreases with a slope of 0.043 ± 0.001 1/cm from 0.58 ± 0.01 to 0.40 ± 0.01 at locus x = 12.8 ± 0.1 cm, and then drops more steeply over 1.6 ± 0.01 cm until it reaches zero. The point where oil saturation reaches zero defines the segment of the core that is filled with oil and thereby the separation zone between the bottom water-saturated (Sw = 1.0) part and the upper oil-bearing part of the core. We shall see later that the brine-saturated part acts quite well as the foam generation chamber. The total volume of injected brine was 2.0 PV at an injection rate of 1 mL/min. The oil saturation profile corresponding to the end of water flooding exhibits a qualitative trend similar to described above. It starts at So = 0.32 ± 0.01 at the top of the core and then decreases rather slowly to So = 0.25 ± 0.01 which is reached at x = 13.0 ± 0.01 cm. Subsequently oil saturation decreases sharply to zero over the next 1.6 ± 0.01 cm. Note that the oil saturation at the top of the core is only slightly higher than the Sor = 0.28 ± 0.02 obtained from the SCAL measurements. To reach the Sor value, many pore volumes of brine would have to be injected. The oil saturation profile for surfactant injection is qualitatively similar to that of water displacement, but the oil saturation values are 3−4% lower. CO2 Gas Flooding. To quantify oil recovery by gas flooding and establish a baseline, CO2 gas was injected after water flooding (Table 6, experiment 1a). The back-pressure was atmospheric; the oil was n-hexadecane. The drainage and imbibition cycles were carried out as described above. The CT images corresponding to CO2 injection are shown in Figure 13. They reveal that the CO2 flow is highly unstable, leading basically to isolated bubbles that are much larger than the pores: the gas bubbles travel up through the lower oil-free and the upper oil-bearing sections of the core. This was also discussed earlier by Wellington and Vinegar.42,43 The change in the color of the oil-bearing core section indicates that the injected CO2 induces further oil production. The production of oil was confirmed by measurements of the effluents. Gas breakthrough was observed after a fairly short time (after 0.3 PV of CO2 had been injected), whereas oil production started only after 0.6 PV. Oil production stopped after 1.1 PV and CO2 injection was stopped after 2.0 PV had been injected. Oil production was around 10% of OIIP and occurred mainly within the first PV of the injected CO2. Total recovery from the core, including recovery by WF, was 61% of OIIP. The relevant mechanisms possibly involve the spreading of oil at the gas− water interface and some mass transfer of CO2 into the oil. Foam Injection. Foam Following Free CO2. This experiment was conducted to find out whether more oil could be recovered by using foam after the injection of free CO2 gas (experiment 1a, Table 6). After the CO2 flood described above, 1.0 PV of surfactant solution (0.5 wt % AOS + FC) was injected into the core to achieve adsorption and generate foam. Surfactant injection recovered a small amount of oil, about 2% of OIIP. Subsequently N2 and surfactant solution were co-injected to generate foam at rates of 1.0 mL/min and 3 mL/h, respectively, (inlet foam quality = 96%). The images

Figure 10. Drainage mechanism, blue color represents oil and water saturated pores and red represents water-only area.

saturated cores. The red color corresponds to the fully watersaturated core (Sw = 1) while the blue color corresponds to the presence of oil. The color range is arbitrary but it was the same for all the images presented in this paper. As previously mentioned, the flow rate was 0.5 mL/min and in each experiment 13.5 mL of n-hexadecane oil was injected. The displacement is fairly stable, although at the end the images show a slightly preferential flow along the core edges. Figure 11

Figure 11. Core CT image after water flooding, yellow color (at the top) indicates region with residual oil.

shows the image of the core at the end of the bottom-to-top water flooding. The removal of oil is evident from the change of the blue color to a yellowish tint. For quantitative analysis, water and oil saturation profiles corresponding to the end of primary drainage (blue), water flooding (red), and surfactant flooding (green) were plotted in Figure 12. The profiles were obtained by averaging the saturation images, perpendicular to the flow direction, that were produced by processing the CT images obtained from the measured CT scan data.8 These profiles show that the oil saturation profile for drainage is reminiscent of the Buckley− 2220



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Figure 12. Experiment 4: drainage, imbibition, and surfactant flooding.

Figure 13. CT images for CO2 core flooding: The images show the gas propagation through the core in the form of large bubbles.

presented in Figure 14, corresponding to the beginning and end of foam injection, show clearly that foam propagates through the core leading to further oil recovery. Measurements of the effluent established that the injection of 3.5 PV of N2 foam yielded an incremental oil recovery of 15.3 ± 0.5%. Since oil recovery by water flooding and CO2 gas injection was 61.0 ± 2.0% in the previous experiment, the overall oil recovery including surfactant flooding and foam flooding was 78.3 ± 2.0% of OIIP. Figure 14 demonstrates clearly the ability of foam flooding to displace a substantial volume of the liquids after gas flooding. A comparison between the foam experiments with nitrogen and carbon dioxide has been presented by the authors.8 N2 Foam Flooding. Experiments were performed to find out more about the development of foam in the porous media and about oil recovery by foam (without prior gas injection). Three experiments (Table 6, experiments 2−4) were conducted to check the reproducibility of the results. Only experiment 4 is

Figure 14. Saturation images after the gas and foam flooding in experiment 1; on the left the core is shown after the gas flooding, on the right after foam flooding.

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Figure 15. CT images for foam flooding.

Figure 16. Experiment 4, foam flooding: water saturations before foam penetrates the oil-bearing core section.

respectively, so that the foam quality was 97%. The CT images corresponding to foam propagation are shown in Figure 15, together with the images obtained at the end of drainage and surfactant flooding. The images show excellent foam development in the lower part of the core (foam “chamber”). The foam propagated as a sharp front until it reached the upper section containing the remaining oil, at about 0.5 PV. Thereafter foam

discussed in detail below as in this experiment extensive CT scanning was applied. The drainage was carried out as described above and then, to mimic water flooding, 7.0 PV of water were injected at a flow rate of 3 mL/min. This was followed by the injection of 1.0 PV of the surfactant solution (0.5 wt % of 1:1 ratio of AOS + FC). Then N2 and surfactant were coinjected into the core at rates of 1.0 mL/min and 2.0 mL/h, 2222



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water saturations have increased over the entire oil-bearing section. As the foam front advances the water-saturated section shrinks, while water saturation continues to decrease throughout the entire oil-bearing section. This means that before the foam front reaches the oil-bearing zone the production of oil continues, due to surfactant flooding, as shown in Figure 17. The water-saturated zone disappeared completely when the foam front reached the oil-bearing zone at 0.57 PV. At this point, the flow in the oil-bearing zone changes from two-phase flow (oil and surfactant solution) to a three-phase flow (oil, surfactant solution and foamed gas). Only at this point can oil recovery be definitely attributed to foam. The total liquid saturation profiles plotted in Figure 18 show clearly that liquid (water and oil) continues to be produced as the foam advances through the oil-bearing part of the core. The production data shows that incremental oil is produced during foam flooding. Cumulative oil production during foam injection is presented in Figure 19. The curve suggests that oil is produced in two stages: first 2.5 mL between 0.9 and 1.1 PV, and second 0.7 mL between 1.8 and 2.2 PV of foam injection. One can observe that there is a breakdown in oil production between 1.1 and 1.8 PV. This has no clear physical cause. It was probably due to a temporary deficiency of the fraction collector. The delay in oil production is due to dead volume in the setup. Moreover, the dead volumes could not be determined accurately as they included rabbets in the cap of the core-holder. However, the cumulative oil (effluent) measurement was good enough to determine the oil RF (recovery factor), which is 22% of OIIP after the injection of 2.2 PV of foam. Part of this recovery (4%) corresponds to the continuation of surfactant flooding when foam travels from the inlet toward the beginning of the oilbearing section. Thus, the RF corresponding to foam is 18%. The pressure obtained during foam flooding is shown in Figure 20. The pressure drop fluctuations are due to the gas mass flow controller which had difficulties in handling the relatively small flow rates involved in the experiment (to replicate field-realistic conditions). Nevertheless, we see a continuous build-up of the pressure drop. The pressure drop reaches steady state at about 0.15 bar at the end of the foam flooding. On the basis of this value we could estimate that the apparent foam viscosity is about 13.8 cP. From these measurements we are able to develop the following general interpretation of foam flooding. Under the experimental conditions of this study, the IFT between oil and AOS-1 + FC-1 surfactant was found to be about 1.5 mN/m. This is an order of magnitude lower than the IFT between brine and oil (51 mN/m). It may explain why some oil could be mobilized during surfactant flooding and incremental oil was recovered, as observed in all the experiments. By taking the foam viscosity estimated above and other relevant parameters, we can deduce that the capillary number corresponding to foam flooding displacement is Nc =1.26 × 10−4. This value is higher than for the surfactant solution and may partially explain the oil production.

continued to propagate but the front was no longer sharp: gas breakthrough was observed shortly after 0.5 PV. This single experiment clearly indicates that foam is much less stable in the presence of oil than in its absence. However, the foam was strong enough to induce a gradual reduction of the liquid saturation and increase the production of oil, as can be clearly seen from the change in the color of the upper (oil-bearing) part of the core from yellow-reddish to an intense blue. As shown below, the mobility of the foam was much lower than that of gas, and as the CT scan images confirm, the sweep efficiency was enormously improved by foam compared to gas flooding. The CT scan images show much lower water fractions (compared to gas flooding), and even at the outlet high gas fractions were observed. Nonetheless, some water and oil were still produced, and we were able to displace more liquids by injecting more foam into the core. For further analysis of the foam flooding, we also plotted the saturation profiles obtained by averaging the images perpendicularly to the flow direction in Figures 16 through 18. Figure 16 gives the water saturation profiles corresponding to foam propagation up to 0.68 PV, i.e. when foam reaches the oilbearing core section. Figure 17 gives the corresponding oil

Figure 17. Experiment 4: oil saturation profiles.

saturation profiles. The saturations in the foam chamber and in the oil-bearing section could be determined from CT scan measurements at a single energy by using relevant two-phase flow formulas. This requires the CT data for the dry core and for the 100% water-saturated core. Figure 18 provides the total liquid saturations corresponding to foam flow through the oilbearing section, in which a three phase flow occurs. Strictly speaking, we can only resolve the saturation in this case by using true dual-energy CT scanning. This option was available in the CT scanning machine, but the dual-energy scans did not provide enough contrast to discriminate between the water and oil saturations. Therefore, we relied on the total liquid saturation, that is, the sum of oil and water saturations. The water saturation before foam injection is shown in green: Sw is equal to 1.0 up to about 11.8 cm and then diminishes to 0.72 (So = 0.28). Focusing on the saturation profile snapshot taken at 0.3 PV, the three regions discussed above can be characterized as follows. In the foam front Sw diminishes from 0.40 at the inlet to a minimum of 0.32 and then rises to 1.0 at 5.2 cm. In the intermediate section, between 5.2 and 11.8 cm, obviously Sw = 1. In the oil section the water saturation diminishes following a typical Buckley−Leverett profile. Compared with the situation before foam injection, the

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CONCLUSIONS • This work has identified the surfactants that give good foam stability in the presence of alkanes and crude oils. • Foam stability depends on the oil and surfactant molecules carbon chain length. The data showed that oils with a higher carbon number affect foam stability less dx.doi.org/10.1021/ie201872v | Ind. Eng.Chem. Res. 2012, 51, 2214−2226


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Figure 18. Total liquid saturations obtained during foam flooding, after foam penetrates the oil-bearing section.

• A negative spreading coefficient and very low value of entering coefficient are good indicators of foam stability. The lamella number, also dependent on surface and interfacial tensions, was found to have no predictive power. • The mixture of AOS-1 and FC-1 gave the best foam stability in the presence of oil, but some further studies are needed for a full explanation. For crude oils the general trend is similar to alkanes: foam stability increased with the molecular weight (and viscosity) of the oil. Oil E with the highest molecular weight and largest viscosity had the least negative impact on foam stability. • Core floods demonstrated that stable foams can be generated in porous media in the presence of oil (results of hexadecane experiments are shown). • Gas breakthrough occurs early after the beginning of gas injection. This can be changed by foam, which controls the gas mobility and delays the breakthrough. Foam recovers nearly twice the amount of oil recovered by free gas injection (without surfactant). • With N2 foam, most oil production was achieved within the first PV of foam injection. For CO2 this was after at least 1.5 PV foam injection, possibly due to its higher solubility in water8 (and possibly oil). Moreover, with nitrogen foam a clear oil bank was obtained that is different from the carbon dioxide foam experiment. • Our experiments demonstrate that high incremental recoveries by foam are possible with moderate injection rates and pressure gradients along the core (typical field rates and gradients). • Foam has a great potential to improve gas flooding (including WAG). As demonstrated in this paper, foam tolerance to oil may be tuned experimentally. Optimization of the surfactant mixture (AOS + FS and/or

Figure 19. Cumulative oil production during foam injection in experiment 4.

Figure 20. Pressure drop measured during foam flooding.

than those with a lower carbon number. This difference is most likely because the solubilization of the surfactant in oil diminishes as the carbon number of the oil increases (in general; in our case the results for n-pentane are outlying). 2224



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(14) Green, D. W.; Willhite, G. P. Enhanced Oil Recovery; SPE Textbook Series, Vol. 6; SPE: Richardson, TX, 1998. (15) Hirasaki, G. J. A Review of the Steam Foam Process Mechanisms, SPE 19518-MS, unpublished supplement to SPE 19505, 1989. (16) Hirasaki, G. J.; Lawson, J. B. Mechanisms of Foam Flow in Porous Media: Apparent Viscosity in Smooth Capillaries. SPE J. 1985, 25, 176−190. (17) Kovscek, A. R.; Radke, C. J. Fundamentals of foam transport in porous media. In Foams: Fundamentals and Applications in the Oil Industry; Schramm, L. L., Ed.; American Chemical Society: Washington, DC, 1994; pp 115−163. (18) Kovscek, A. R.; Patzek, T. W.; Radke, C. J. Mechanistic Prediction of Foam Displacement in Multidimensions: A Population Balance Approach. Chem. Eng. Sci. 1995, 50, 3783−3799. (19) Kovscek, A. R.; Patzek, T. W.; Radke, C. J. Mechanistic Foam Flow Simulation in Heterogeneous and Multidimensional Media. SPE J. 1997, 4, 511−526 ; SPE 39102. (20) Kruglyakov, P. M. In Thin Liquid Films: Fundamentals and Applications; Surfactant Science Series; Ivanov, I. B., Ed.; Marcel Dekker: New York, 1988; Chapter 11, p 29. (21) Kuhlman, M. I. Visualizing the Effect of Light Oil on CO2 Foams. J. Pet Technol. 1990, 42, 902−908. (22) Lake, L. W. Enhanced Oil Recovery, 2nd ed.; Prentice Hall: Englewood Cliffs, NJ, 2006. (23) Lau, H. C.; O’Brien, S. M. Effects of Spreading and Nonspreading Oils on Foam Propagation Through Porous Media. SPE Resevoir Eng. 1988, Aug, 893−896. (24) Li, B.; Hirasaki, G. J.; Miller, C. A. Upscaling of Foam Mobility Control to Three Dimensions, SPE 99719, SPE/DOE Symposium on Improved Oil Recovery, Tulsa, OK, USA, 22−26 April 2006. (25) Li, R. F.; Hirasaki, G. J.; Miller, C. A.; Masalmeh, S. K. Wettability Alteration and Foam Mobility Control in a Layered 2-D Heterogeneous Sandpack, SPE 141462, SPE International Symposium on Oilfield Chemistry, Woodlands, TX, 21−23 February 2011. (26) Lobo, L.; Wasan, D. T. Mechanisms of Aqueous Foam Stability in the Presence of Emulsified Non-aqueous Phase Liquids: Structure and Stability of Pseudoemulsion Film. Langmuir 1993, 9, 1668−1677. (27) Mannhardt, K.; Svorstøl, I. Surfactant Concentration for Foam Formation and Propagation in Snorre Reservoir Core. J. Petrol. Sci. Eng. 2001, 30, 105−119. (28) Neethling, S. J.; Lee, H. T.; Grassia, P. The Growth, Drainage and Breakdown of Foams. Colloids Surf. A 2005, 263, 184−196. (29) Nguyen, Q. P.; Zitha, P. L. J.; Currie, P. K.; Rossen, W. R. CT Study of Liquid Diversion with Foam, SPE 93949. SPE Production and Operations Symposium, Oklahoma City, OK, USA, 17−19 April 2005. (30) Patzek, T. W. Field Applications of Foam for Mobility Improvement and Profile Control, SPE Distinguished Lecture Paper. SPE Resevoir Eng. 1996, 79−85. (31) Ransohoff, T. C.; Radke, C. J. Mechanisms of Foam Generation in Glass-Bead Packs, SPE 15441. SPE Resevoir Eng. 1988, 3, 573−585. (32) Rossen, W. R.; van Duijn, C. J.; Nguyen, Q. P.; Vikingstad, A. K. Injection Strategies to Overcome Gravity Segregation in Simultaneous Gas and Liquid Injection Into Homogeneous Reservoirs. SPE 99794, SPE/DOE Symposium on Improved Oil Recovery, Tulsa, OK, USA, 22−26 April 2006. (33) Schramm, L. L.; Novosad, J. J. Micro-visualization of Foam Interactions with a Crude Oil. Colloids Surf. 1990, 46, 21−43. (34) Schramm, L. L.; Ayasse, C.; Novosad, J. J.; Mannhardt, K. Method for improving enhanced recovery of oil using surfactantstabilized foams. US, Canadian, UK, and Norwegian patents, 1991− 1998, incl. U.S. Pat. 5,060,727, 29 Oct. 1991. (35) Skauge, A.; Aarra, M. G.; Surguchev, L. M.; Martinsen, H. A.; Rasmussen, L. Foam-Assisted WAG: Experience from the Snorre Field. SPE 75157, SPE/DOE Symposium on Improved Oil Recovery, Tulsa, OK, USA, 13−17 April 2002. (36) Suffridge, F. E.; Raterman, K. T.; Russell, G. C. Foam Performance Under Reservoir Conditions. SPE 64th Annual Technical

AOS + FC) may result in strong foams in the presence of oil in the porous media. • The physics of foam in bulk and porous media are rather different, and bulk foam experiments should be considered a first screening step in the choice of the surfactant.

AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected].

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ACKNOWLEDGMENTS

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REFERENCES

The authors thank Shell Global Solutions International (SGSI) for permission to publish this paper and for sponsoring the project through the Gamechanger program. C. Glandt, R. Faber, T. Matsuura, and V. Brock from Shell are gratefully acknowledged for their input and ideas. At Delft University of Technology, A. Maljaars and H. van der Meulen are gratefully acknowledged for their technical support and M. Simjoo for his help in processing the CT scan images. We thank R. Bouwmeester from Shell for his help with data, setups, and experiments. The authors are very grateful Prof. G. Hirasaki from Rice University for many valuable discussions.

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