Experimental investigation of CO2-foam stability improvement by alkaline in the presence of crude oil

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Experimental investigation of CO2 -foam stability improvement by alkaline in the presence of crude oil Seyed Amir Farzaneh ∗ , Mehran Sohrabi Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University, Edinburgh, UK

a b s t r a c t Dissolution of CO2 in heavy crude oil results in a significant reduction in the oil viscosity. However, CO2 injection in viscous oil reservoirs lacks acceptable sweep efficiency due to the high mobility of CO2 . Co-injection of CO2 and an appropriate surfactant can generate CO2 -foam in situ providings a means of controlling CO2 mobility and hence, improving sweep efficiency and oil recovery. Foam injection has been studied in the past but in the majority of these studies, foam has been investigated in the absence of crude oil. It is known that the stability of foam is adversely affected by crude oil and this problem has been a major obstacle for the application of foam injection for enhanced oil recovery (EOR). In this paper we present the results of a comprehensive series of visual experiments on foam stability in the presence of different heavy crude oil samples. Through these experiments, we have evaluated and compared the performance of a number of surfactants for foam generation. We have also tested the impact of three different alkalis (NaOH, Na2 CO3 , and Borate) on foam stability. The effect of gas type (CO2 versus N2 ) has also been investigated experimentally. The results show that while addition of NaOH drastically decreases the stability of CO2 -foam, Na2 CO3 and, in particular, Borate can significantly increase the stability of CO2 -foam. For these alkalis, there is an optimum concentration which corresponds to maximum foam stability. The results also reveal that higher oil viscosity increases the stability of CO2 -foam. Anionic surfactants with smaller carbon number produce better foam stability compared to non-anionic surfactants. As expected, foam stability increased with increasing surfactant concentration but there was an optimum surfactant concentration corresponding to maximum foam stability beyond which foam stability decreased. The results also revealed that N2 -foam was more stable compared to CO2 -foam. © 2014 The Institution of Chemical Engineers. Published by Elsevier B.V. All rights reserved.

Keywords: CO2 foam; Heavy oil recovery; Foam flood; Foam stability; Alkaline; Surfactant screening

1.

Introduction

Heavy oil, extra heavy oils and tar sands resources identified on the planet have been estimated at 2200–3700 billion barrels (Huc, 2011). The production of heavy and extra-heavy oils is on the rise driven by the increase in global energy consumption, rapid decline of light (conventional) crude oils, and high oil prices. Thermal processes are usually applied in these reservoirs in order to enhance recovery by reducing the oil viscosity (Upreti et al., 2007). The majority of these thermal methods

are a form of steam injection with cyclic steam stimulation (CSS) being one of the most successful of these techniques. Steam assisted gravity drainage (SAGD) is a newer technique that has shown promise (Butler and McNab, 1981; Butler and Stephens, 1981). However, over half of heavy oil reservoirs are not suitable for thermal recovery processes (FarouqAli, 1997) for various technical and economic reasons. Thermal methods are also energy intensive with a large carbon footprint and negative environmental impacts. There is therefore a need for developing non-thermal methods that can

∗

Corresponding author. Tel.: +44 131451 8084. E-mail address: [email protected] (S.A. Farzaneh). http://dx.doi.org/10.1016/j.cherd.2014.08.011 0263-8762/© 2014 The Institution of Chemical Engineers. Published by Elsevier B.V. All rights reserved.

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efficiently increases heavy oil recovery as alternative to thermal methods and as a solution for reservoirs in which thermal methods cannot be applied. Non-thermal methods mainly work by reducing the viscosity of heavy crude oils (e.g., by addition of a solvent), increasing the viscosity of the displacing fluids, or by reducing interfacial tension. A review of the major non-thermal methods for heavy oil recovery can be found elsewhere (Talash and Crawford, 1957; FarouqAli, 1997; Farzaneh et al., 2010, 2012). Unfortunately, non-thermal methods have not been very successful in increasing heavy oil recovery. A survey of 62 field projects showed that only immiscible CO2 injection has been marginally successful (FarouqAli, 1997). CO2 -EOR was tried for the first time in 1972 in Scurry County, Texas. Since then, CO2 injection has been used successfully throughout the Permian Basin of West Texas and eastern New Mexico (DOE report on oil and natural gas supply and delivery, 2010). Although miscible CO2 flooding of light oil reservoirs has been extensively tested in laboratories and in the field, similar studies for heavy oil reservoirs have been very limited (Klins and FarouqAli, 1982; Alikhan and Farouq Ali, 1983; Rojas and Farouq Ali, 1988; Araghi and Asghari, 2010; Zhang et al., 2010). However, recovery of heavy oil using CO2 immiscible flooding is considered to be the most promising amongst the non-thermal EOR processes (Klins and FarouqAli, 1982; Alikhan and Farouq Ali, 1983; Rojas and Farouq Ali, 1988). It has been reported that the CO2 requirement for the immiscible CO2 injection process is 20–70% of that needed for miscible flooding for the same volume of recovered oil (Reid and Robinson, 1981; Holm, 1982; Stalkup, 1983). Also, Beeson and Ortloff (1959) found that CO2 injection in gaseous state resulted in more heavy oil recovery in comparison with liquid condition of it per unit mass of injected CO2 . Several investigations have demonstrated that the dissolution of CO2 in heavy oil causes a significant reduction in the viscosity and an increase in the volume of oil. Other mechanisms that are attributed to enhanced oil recovery by CO2 are: oil swelling, interfacial tension (IFT) reduction, emulsification and blow down (Morsi et al., 2004; Emadi et al., 2011). A major technical challenge in CO2 injection is the ability to properly control the mobility of the injected CO2 . This challenge, which stems from the adverse viscosity contrast between CO2 and the reservoir fluids, is more difficult in heavy oil reservoirs compared to their light oil counterparts. Flood profile control in gas floods is instrumental for a successful project (Klins, 1984; Baviere, 1991; Kulkarni, 2003) and hence, improving sweep efficiency in gas floods is an active area of research (McKean et al., 1999; Enick et al., 2000). Attempts have been made to develop gas-soluble thickeners that can increase the viscosity of gases several folds. Other methods such as; modifications in the injection fluid slug such as the use of natural gas liquids (NGL) instead of water for highly viscous oils in low pressure, poorly producing and unconsolidated formations have also been proposed (Moritis, 1995). Although they seem promising at the laboratory scale, important issues like feasibility, cost, applicability, safety and environmental impacts still need to be addressed (Moritis, 1995). The mobility of CO2 may also be controlled by co-injection of CO2 with water under various injection strategies. Alternating injection of CO2 and water (WAG injection) can reduce the gas mobility by increasing the effective viscosity of the injectents. Despite the higher displacement efficiency of WAG its overall effectiveness can still be compromised by severe viscous fingering in heavy oil reservoirs (Chang et al., 1994; Tchelepi and Orr, 1994).

Co-injection of CO2 and a surfactant solution may generate CO2 foam in the reservoir which could provide a solution for the poor sweep efficiency of CO2 in heavy oil reservoirs. However, for this method to be effective in controlling the gas mobility in gas flooding process, a stable foam capable of lasting long enough to travel deep into the reservoir between the injection wells and the producers. This represents a challenge because, as mentioned before, foam stability can be adversely affected by crude oil and by the high salinity of formation water typically found in an oil reservoir. Screening tests have been used to assess the effect of oil on foams, including adding refined hydrocarbons or crude oil to low pressure air foam and nitrogen foam (Dellinger et al., 1984; Andrianov et al., 2012; Simjoo et al., 2013) or high pressure CO2 -in-brine foams (Mannhardt et al., 2000). However, much less work has been done to investigate the performance of foam in heavy oil reservoirs using actual heavy crude oil samples, which is the focus of the current study. Also, the wide range of surfactant types and concentrations used in this study provide an opportunity to experimentally investigate the relationship between surfactant concentration and foam stability. Foams have applications in well drilling, mobility control in gas/steam injection, production well management and process plant in the petroleum industry. Foam flooding emerged in the 1960s as a promising technology for improving the reservoir sweep efficiency in steam and/or gas flood due to its ability to reduce gas mobility (Schramm Laurier, 1994). Successful field tests on foam application have also been reported (Shan and Rossen, 2004). But, foam is a metastable system that coarsens spontaneously and decays due to liquid drainage from lamellae and plateau and capillary suction. An important parameter that should be considered regarding the ability of foam to control gas mobility is the effect of crude oil on foam stability. Oil becomes detrimental to foam at oil saturations above 5–20% (Schramm Laurier, 1994). The success of foam injection for EOR depends on a number of parameters but the most important one is the ability of the surfactant to form stable foam under reservoir conditions (e.g., pressure, temperature, salinity). Foam stability is the key parameter in foam flood design for mobility control purposes. Many factors affect the strength and stability of the foam in the reservoir which have to be taken into account in order to select a suitable surfactant. For instance, while most surfactants can readily generate foam under normal conditions of low salinity water and in the absence of crude oil, very few can perform well in the presence of crude oil and high salinity formation brine. A review of the parameters pertinent to foam stability has been provided in our previous work (Farzaneh and Sohrabi, 2013). The lowering of interfacial tension (IFT) using surfactants for producing foam has been known for decades. Addition of alkali to surfactants (AS) is also well known due to decades of research in the area of chemical flood by many investigators (Reisberg and Doscher, 1956; Martin et al., 1985; Nelson et al., 1984; Lieu et al., 1982; Green and Willhite, 1998). The addition of alkali to a surfactant solution can decrease the IFT further which would be expected to produce more stable foam. Alkali reacts with certain components of crude oil to generate soap-like molecules in situ. The types and compositions of these components of crude oil have been discussed elsewhere (Shuler et al., 1989; Seifert, 1975; Dunning et al., 1953; Pasquarelli and Wasan, 1979). By combining the natural soap generated by alkali with a surfactant, a sharp decrease in IFT can be obtained or a lower amount of

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surfactant is required to achieve the same (low) IFT level without alkali. The use of alkali is also known to reduce the adsorption of anionic surfactants on sandstones. Better chemical compatibility of Nitrogen, led researchers to employ new chemicals for improving foam stability and reduction of surfactant adsorption mostly in air-foam/N2 -foam rather than CO2 -foam. However, due to significant reduction in heavy oil viscosity associated with injection of CO2 , CO2 -foam has attracted more attention over N2 foam. However, CO2 cannot be injected with the widely used alkalis such as NaOH because it will neutralize the alkaline solution. The aim of this study is to further investigate foams behaviour in order to improve our understanding of heavy oil/foam performance and the effect of addition of alkalis on the stability of CO2 -foam. This paper consists of three parts. In the first part, a comprehensive series of tests to screen a number of leading surfactants for their ability to generate stable foam at various concentrations in the absence of crude oil have been carried out. In the second part, the stability of foams generated by two selected surfactants and N2 or CO2 in the presence of heavy crude oil with different concentrations is examined. In the third part, the impact of different alkalis on CO2 -foam stability both with and without crude oil is presented via using three different alkalis (NaOH, Na2 CO3 , and Borate).

2.

Experimental facilities

2.1.

Fluids and chemicals

A brine solution with the total salt concentration of 10,000 ppm representing the formation water of the heavy oil reservoir of interest in this study was synthetized, degased and then used in the foam stability experiments. The brine contained 0.8 wt.% NaCl and 0.2 wt.% CaCl2 . Table 1 lists the details of the different surfactant solutions used in our experiments. For simplicity, the surfactants are referred to here as: “C1”, “C2”, “S2”, “Bio-Terge”, “CD-128”, “Neodol”, “XP-0010” and “Alpha Foamer”, as shown in Table 1. Surfactant solutions with different active concentrations (below and above the critical micelle concentration) were prepared by mixing an appropriate quantity of a surfactant in a brine solution. Then, the resultant surfactant solutions were homogenized by using a magnetic stirrer for a few hours. In the alkaline surfactant solutions, a constant active concentration of 0.3 wt.% of a surfactant with different concentrations of an alkali (NaOH, Na2 CO3 and Neobor) was prepared by dissolving the alkali in the brine. A heavy crude oil (Crude J) with 16◦ API and the viscosity of 674 mPa s (at tests temperature of 20 ◦ C) was used in these experiments. In order to examine the effect of crude oil, two other crude oil samples; Crude A with 39◦ API and viscosity of 1 mPa s and Crude E with 19◦ API and viscosity of 100 mPa s were also used in the tests. CO2 and N2 with 99% purity were used in the bulk foam experiments.

2.2.

Foam stability measurement apparatus

The apparatus used in the foam stability experiments consisted of three transferred cells for storing CO2 , surfactant and crude oil, a visual foam column made from toughened glass, displacement pumps, and a wet gas flow metre (Fig. 1). The rig is also equipped with a camera which is connected to a computer and is capable of working at magnifications up to

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Fig. 1 – Schematic of foam stability setup. 200 times. Pictures of the foam column were digitally taken by a computer interface and recorded. These pictures were later used for visual investigation and measurement of the foam height to analyze and quantify foam stability in each test.

2.3.

Experimental procedure

Foam stability experiments were carried out in a visual cell at 250 psi and 20 ◦ C. As will be explained in more details later, pressure and temperature had limited effects on the foam stability at surfactant concentrations higher than critical micelle concentration (CMC). The surfactant concentration was higher than CMC in majority of the foam stability experiments. Some earlier studies have also shown that the effect of pressure and temperature on foam stability at concentrations higher than CMC is negligible (Borchardt et al., 1985; Holt et al., 1996). Therefore, the results of the tests performed at 250 psi can be extended to higher pressures as well. The visual cell was first filled by 10 cc of the surfactant/alkaline-surfactant solutions of interest. A constant volume of CO2 (with mass flow controller) was then injected into the visual cell through the bottom valve. The flow of CO2 through the surfactant caused foam formation and the foam column reached its maximum height after 3–5 min. The injection of CO2 then stopped and the foam height above the liquid level was measured as a function of time. The foam generation procedure was kept the same in all foam stability tests. The foam stability is defined as the time required for the foam column decaying to 50% of its initial height (i.e., foam half-life). A longer half-life time indicates stronger foam and a better surfactant performance.

3.

Foam stability experiments

3.1.

Results and discussions

The success of foam injection for EOR depends on a number of parameters but the most important one is the ability of the surfactant to form stable foam at reservoir conditions. Many factors affect the strength and stability of foam in an oil reservoir which have to be taken into account in order to select a suitable surfactant. Here a comprehensive series of tests have been carried out to investigate foam stability. A number of leading surfactants have been tested in this study and ranked based on their performance. The effects of alkali and gas type (CO2 versus N2 ) on foam stability have also been investigated. In these experiments we have used the rate of the collapse of a column of foam generated by injecting CO2 /N2 through a surfactant/alkaline-surfactant solution. A list of the foam column experiments which have been carried out are presented

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Table 1 – Surfactants used in this work. Surfactant

Type TM

Petrostep C1 Petrostep C2TM Petrostep S2TM Bio-Terge AS-40 TM Rhodapex CD-128TM Alpha FoamerTM Neodol 25–7TM XP-0010TM

Anionic Anionic Anionic Anionic Anionic Anionic Non-anionic Anionic

Active (wt.%)

CMC (g/L)

Formula

39 46 22.38 39 56 52 100 30

0.3 0.0082 25 0.3 1.4 2.2 0.016 NA

(C14) Sodium Alpha Olefin Sulfonate (C12–C16) Sodium Alpha Olefin Sulfonate (C15–C18) Sodium internal Olefin Sulfonate Sodium Olefin Sulfonate Ammonium C8–10 Alkyl Ether Sulfate Ammonium Alkyl Ether Sulfate (C12-C15) Alcohol Ethoxylate Propietary Surfactant

Fig. 2 – Effect of surfactant type on foam half-life time at different concentrations. in Table 2. Some experiments were repeated to examine the repeatability of the results. Good repeatability was observed with only around 5% difference in the measured half-life and foam decay times in repeated tests. No surfactant precipitation was observed during the tests for the range of surfactant concentrations used in the measurements.

3.1.1.

Effect of surfactant type

In order to investigate the effect of surfactant type on foam stability, eight different types of surfactants were selected from both the anionic and non-anionic categories. The experiments were carried out in a full-view visual cell made of toughened glass. Foam was generated under various conditions by injecting a quantity of a surfactant in the visual cell and then injecting gas (e.g., CO2 ) in the cell from the bottom of the cell and through the surfactant solution. The results show that anionic surfactants have a better foam stability and longer half-life. The non-anionic surfactants generally performed poorly in terms of foam stability under the conditions of our experiments. Neodol showed the lowest foam stability amongst the surfactants used in this work. Fig. 2 presents the results of the foam stability tests for various surfactants and shows higher stability for foams generated by anionic surfactants. C1, Bio-Terge, and Alpha Foamer have relatively similar foam stability at the CMC and lower concentrations. XP-0010, has the highest foam stability even in comparison with anionic surfactant. The figure also shows the impact of surfactant concentration on the stability of the foam column generated with different surfactants. As can be seen, different surfactants have performed significantly differently. While some have produced very unstable and weak foam, some others have produced much stronger foams. The effect of carbon number of the surfactants on foam stability is also illustrates in Fig. 2. The surfactants with smaller carbon number have higher foam stability. However, the foam stability of surfactants is not directly proportional

Fig. 3 – Effect of CD-128 concentrations on foam height versus time. to carbon chain length because the activity of foaming agents depends not only on the surface and interfacial tensions but also on the intermolecular interaction. Based on earlier studies (Boonyasuwat et al., 2009; Wu and Pan, 2010), surfactants whose carbon number is lower than ten are not suitable to be used as foaming agents. For surfactants with very long carbon chains, the intermolecular interaction is greater which results in not only a lower solubility in water solution but also poorer film elasticity. Therefore, surfactants with too long a carbon chain are not suitable foaming agents either (Huang et al., 1986).

3.1.2.

Effect of surfactant concentrations

The results of the tests demonstrate that the foam half-life increases with increasing the surfactant solution concentration, as expected. But, it can be seen from the results that the foam stability first increased by increasing concentration up to a specific concentration and then decreased when surfactant concentration increased further. This suggests that there is an optimum surfactant concentration which corresponds to the maximum foam stability and foam half-life. Based on these results, the effect of surfactant solution concentration can be explained in more details as follows. Tests 1–5 were carried out in order to measure the impact of concentration of CD-128 on its foam stability. It can be seen from Fig. 3 that the foam half-life for concentrations of 0.14 wt.%, 0.28 wt.% and 0.7 wt.% were 2 min, 5.5 min and 2 min, respectively. It means that for the range of surfactant concentrations examined in our tests, 0.28 wt.% is the optimum concentration as increasing the surfactant concentration beyond that has not increased the foam stability. The half-life of CD-128 is considerably lower than the other anionic surfactants (Fig. 2). In order to observe the effect of C1 concentrations on foam stability, Tests 6, 7, 8, 9, 10 and 11 were carried out. At C1

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Test no.

CD-128/0.07 CD-128/0.14 CD-128/0.28 CD-128/0.7 CD-128/1.4 C1/0.006 C1/0.015 C1/0.03 C1/0.06 C1/0.15 C1/0.3 C2/0.0082 C2/0.1 C2/0.3 C2/0.5 C2/1 C2/1.5 S2/0.03 S2/0.5 S2/1.25 S2/2.5 S2/5 S2/12.5 Bio-Terge/0.024 Bio-Terge/0.12 Bio-Terge/0.3 Bio-Terge/1.2 Neodol/0.08 Neodol/0.3 Neodol/0.5 Neodol/1.6 XP-0010/0.03 XP-0010/0.1 XP-0010/0.3

Crude oil/saturation (%) – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – –

Alkaline/concentration (wt.%) – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – –

Test no. 35 36 37 38 39 40* 41 42 43 44 45 46 47 48 49* 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 *

Surfactant type/concentration (wt.%) XP-0010/1 Alpha-Foamer/0.03 Alpha-Foamer/0.15 Alpha-Foamer/0.3 Alpha-Foamer/1 C1/0.3 XP-0010/0.3 XP-0010/0.3 XP-0010/0.3 XP-0010/0.3 C1/0.3 C1/0.3 C1/0.3 C1/0.3 C1/0.3 C1/0.3 C1/0.3 C1/0.3 C1/0.3 C1/0.3 C1/0.3 C1/0.3 C1/0.3 C1/0.3 C1/0.3 C1/0.3 C1/0.3 C1/0.3 C1/0.3 C1/0.3 C1/0.3 C1/0.3 C1/0.3 N2 used as gas instead of CO2

Crude oil/saturation (%) – – – – – – J/10 J/20 J/30 J/40 J/10 J/20 J/30 J/40 J/10 E/10 A/10 J/10 J/10 J/10 J/10 J/10 J/10 J/10 J/10 J/10 J/10 J/10 J/10 J/10 J/10 J/10 J/10

Alkaline/concentration (wt.%) – – – – – – – – – – – – – – – – – NaOH/0.1 wt.% NaOH/0.2 wt.% NaOH/0.5 wt.% NaOH/1 wt.% Na2 CO3 /0.1 wt.% Na2 CO3 /0.2 wt.% Na2 CO3 /0.5 wt.% Na2 CO3 /1 wt.% Na2 CO3 /1.5 wt.% Na2 CO3 /2 wt.% Na2 CO3 /4 wt.% Neobor/0.5 wt.% Neobor/1 wt.% Neobor/1.5 wt.% Neobor/2 wt.% Neobor/4 wt.%

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Surfactant type/concentration (wt.%)

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Table 2 – Foam stability test performed in this study.

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Fig. 4 – Effect of C1 concentrations on foam height versus times.

Fig. 5 – Effect of C2 concentrations on foam height versus time. concentration below or around the CMC, foam stability increased when C1 concentration increased. But, at CMC and higher concentrations, the stability of foam increased very slightly by increasing the C1 concentration. Therefore, for C1 surfactant, it would not be beneficial to increase the concentration to a value above 0.15 wt.% (Fig. 2). The stability of the CO2 -foam generated by C1 at different concentration is shown in Fig. 4. Tests 12–17 were performed to check the performance of surfactant C2. Fig. 2 indicates that the behaviour of C2 is similar to that of C1, but the foam stability of this surfactant was significantly lower. The concentration of 0.5 wt.% is the optimum concentration which results in the maximum foam height (Fig. 2). The undesirable low foam stability performance of C2 can be explained by the lower CMC of this surfactant which has longer surfactant molecules. At the same concentration, more micelles are present in the solution of the longer chain surfactants, and the result is an easier micellar ordering and lower foam stability. The foam height of C2 versus time at different concentration is shown in Fig. 5. To investigate the effect of concentration on the performance of S2, Tests 18–23 were performed. According to the results shown in Figs. 2 and 6, higher S2 concentration resulted in higher foam stability, excluding 1.25 wt.% and 5 wt.% (Tests 20 and 22). It should be noted that, in all the tests the surfactant concentrations were lower than CMC. The effect of concentration of Bio-Terge on its foam stability has been studied in Tests 24–27. The results of these tests are shown in Fig. 7. The foam stability increased when the Bio-Terge concentration increased between 0.024 wt.% and 0.3 wt.%. However, further increasing the Bio-Terge

Fig. 6 – Effect of S2 concentrations on foam height versus time.

Fig. 7 – Effect of Bio-Terge concentrations on foam height versus time.

Fig. 8 – Effect of Neodol concentrations on foam height versus time. concentration to 1.2 wt.% was not beneficial and even resulted in lower foam half-life (Fig. 2). In Tests 28, 29, 30 and 31, the effect of concentration of Neodol on the stability of the foam generated by this surfactant has been investigated. Non-anionic surfactants are not good foaming agents for the conditions of our experiments, as we can see from Fig. 8. Based on these results, foams generated from Neodol increased with a surfactant concentration beyond the CMC within the measured range. Also, previous research results have shown that a second CMC point exists for non-anionic surfactants with foam half-life still increasing after the first CMC (Bikerman, 1973; Fisher and Oakenfull, 1977). To examine the effect of XP-0010 concentration on foam stability, Test 32 through 35 have been carried out. Fig. 9 illustrates the XP-0010 foam stability at different concentrations

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illustrates the Alpha Foamer foam stability at different concentrations as a function of time. Foam stability increased up to the concentration of 0.3 wt.% and then slightly decreased at higher concentrations.

3.1.2.1. Visual observations. The behaviour of the foam

Fig. 9 – Effect of XP-0010 concentrations on foam height versus time.

Fig. 10 – Effect of Alpha Foamer concentrations on foam height versus time. as a function of time. Foam stability increased up to the concentration of 0.1 wt.% and then decreases at higher concentrations. To investigate the effect of Alpha Foamer concentration on foam stability, Test 36 through 39 has been carried out. Fig. 10

observed during the bulk foam experiments can be divided into three regions. In the first region, the lamella thinning occurred through liquid drainage without any decay in the foam height. The foam height decay in the second region occurs simultaneously with liquid drainage. When liquid drainage is complete throughout lamellas (dry foam), foam height decay occurs in the third region. Fig. 11 shows these three stages for Bio-Terge foam decay experiment at concentration of 0.3 wt.%. The role of surfactant solution concentration on the foam stability is due to the relation between Gibbs elasticity and surfactant concentration. For surfactant concentrations below the CMC, the Gibbs elasticity increases with an increase in surfactant concentration until a maximum elasticity is reached. From this point onward, any further addition of surfactant decreases the Gibbs elasticity and surfactant concentrations above the CMC lie well beyond this maximum elasticity region. Based on this statement, anionic surfactants with lower CMC are good candidates for foam flood application in terms of achieving good foam stability. The results also show that the foam density increased when surfactant concentration increased. Fig. 12 compares the image of the foam column produced by CD-128 with a concentration of 0.14 wt.% (right) and 0.28% (left) at the start of the tests. As can be seen, the higher concentration has resulted in a smaller lamella size and hence denser foam. Foam texture can affect the foam–oil interaction in porous media. Fig. 13 shows a magnified image of the foam column produced by Neodol with a concentration of 0.3 wt.% (right) and foam produced by C1 with a concentration of 0.3 wt.% (left). As can be seen, the left image has smaller foam bubbles and smaller lamella sizes and hence a denser foam whereas

Fig. 11 – Sequence of foam stability test for Bio-Terge at (a) t = 164 min, (b) t = 300 min and (c) t = 500 min. Please cite this article in press as: Farzaneh, S.A., Sohrabi, M., Experimental investigation of CO2 -foam stability improvement by alkaline in the presence of crude oil. Chem. Eng. Res. Des. (2014), http://dx.doi.org/10.1016/j.cherd.2014.08.011

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Fig. 12 – Effect of surfactant concentrations on foam density (the produced foam in left picture is denser than the foam in right picture due to its higher surfactant concentration).

Fig. 13 – Effect of surfactant type on foam texture (left image has smaller foam bubbles and smaller lamella sizes and hence denser foam, as the right image has larger bubble and less dense foam). the right-hand image has larger bubble sizes and less dense foam.

3.1.3. Effect of gas type (comparison of N2 with CO2 ) on foam without crude oil The effect of gas type on foam stability has been studied by comparing Test 40 with Test 11. All parameters such as surfactant type (C1) and surfactant concentration (0.3 wt.%) was kept unchanged except the type of injected gas which was changed to N2 . The results indicate that the foam stability increased dramatically when N2 was used instead of CO2 (Fig. 14). The N2 foam half-life was 1950 min while the half-life of the CO2 -foam was around 210 min. Compared to the previous CO2 -foam test, in the test with nitrogen the aqueous phase had less spreading tendency and, as a result, the foam was stronger and more stable.

3.1.4.

Effect of oil and its saturation

In order to investigate the effect of crude oil and its saturation on foam stability, Test 41 through Test 48 were carried out. The heavy crude oil samples were injected into the foam

Fig. 14 – Comparison of N2 -foam height with CO2 -foam height at different times. column after injection of surfactant solution. Then, CO2 was flowed through the column and foam was generated by passing CO2 over mixture of oil and surfactant solution. Fig. 15 shows the results of a series of foam stability tests carried out using 0.3 wt.% XP-0010 and CO2 versus saturation of the crude

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Fig. 15 – Effect of crude oil ‘J’ on CO2 -foam stability generated by 0.3 wt.% XP-0010 versus different oil saturations at different times.

Fig. 17 – Effect of crude oil ‘J’ on CO2 -foam stability generated by 0.3 wt.% C1 versus different oil saturations at different times.

oil ‘J’. As can be seen, the presence of crude oil reduced the stability of the foam but the reduction was more pronounced when the oil saturation increased to 40%. Fig. 16 shows the visual results of XP-0010 foam decay experiment at surfactant concentration of 0.3 wt.% XP-0010 and 10% oil saturation. Fig. 17 summarizes the results of the CO2 -foam stability tests carried out using surfactant C1 and crude ‘J’. As can be seen, foam stability decreased when oil saturation increased. While the change in the oil spreading behaviour of the foam–oil system is not fully understood and requires further investigation, a direct relationship between the oil saturation and its spreading behaviour was noticed. In other words, as the oil saturation increased, the system became more spreading (i.e., oil layers spread around gas bubbles in the foam) and resulted in lower foam stability at higher oil saturation. Fig. 18 shows four images taken during the C1 foam stability test carried out in presence of 10% oil saturation.

Fig. 19 compares the impact of crude oil on the stability of XP-0010 and C1 foams by showing the foams half-life. The performance of C1 foam was reduced significantly compared to its oil-free performance. The results show that the C1 foam stability dramatically reduced in presence of oil at 10% oil saturation and higher. As can be seen, the XP-0010 foam is much more resilient and its half-life remained constant when the oil saturation increased from 10% to 30% and only fell at oil saturations higher than 40%. This is a promising performance for XP-0010 because for many surfactants oil becomes detrimental to foam at lower oil saturations of above 5–20% (Schramm Laurier and Wassmuth, 1994; Wassmuth et al., 2000; Mannhardt et al., 2000).

3.1.4.1. Microscopic observations of foam–oil interactions. In this section, the impact of crude oil on foam stability is further discussed. Oil can stabilize or destabilize foam. Here, we have

Fig. 16 – Different sequences of 0.3 wt.% of XP-0010 foam decay experiment in presence of 10% oil at (a) t = 0 min, (b) t = 115 min, (c) t = 290 min and (d) t = 605 min. Please cite this article in press as: Farzaneh, S.A., Sohrabi, M., Experimental investigation of CO2 -foam stability improvement by alkaline in the presence of crude oil. Chem. Eng. Res. Des. (2014), http://dx.doi.org/10.1016/j.cherd.2014.08.011

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Fig. 18 – Different sequences of 0.3 wt.% of C1 foam decay experiment in presence of 10% oil at (a) t = 0 min, (b) t = 5 min, (c) t = 10 min and (d) t = 16 min.

Fig. 19 – Dependence of foam half-life time on oil saturation. used the results of our foam stability tests to investigate the impact of oil on foam stability. Foam-oil interactions have been investigated by several authors (Ross and McBain, 1944; Tsuge et al., 1984; Kuhlman, 1990) who found that several factors can affect the foam stability in the presence of oil. First, and one of the most effective factors on foam stability, is the Pseudoemulsion film which is defined as aqueous films between the gas and oil phases in the foam. Nikolov et al. (1986) identified the importance of Pseudoemulsion films on the foam stability. Schramm and Novosad (1990) also found that Pseudoemulsion film is a controlling factor in stability of foam in the presence of oil. A stable Pseudoemulsion film can stabilize foam and this stability increases with increasing oil saturation while unstable Pseudoemulsion films have destabilizing effects on foam. This mechanism (increasing foam stability by increasing stable Pseudoemulsion saturation) is stronger when the sizes of Pseudoemulsion droplets are larger. Fig. 20 shows unstable Pseudoemulsion drops which have been formed due to interactions between Bio-Terge foam and crude oil ‘J’ at oil

Fig. 20 – Unstable Pseudoemulsion drops which has been formed due to interaction of 0.3 wt.% of Bio-Terge and crude oil ‘J’ at oil saturation of 30%.

saturation of 30%. The instability of Pseudoemulsion film is related to weak emulsification of Bio-Terge and crude ‘J’. Because the buoyancy force of the oil droplets and the resistance to their movement within the plateau borders (the region of liquid situated at the junction of liquid lamella), the oil droplets drain slower in the plateau borders than the surrounding aqueous phase. The difference in drainage rate results in an increase in the oil fraction in plateau borders. Plateau borders trap oil by increasing oil fraction, thus slowing down the liquid drainage (Fig. 21). On the other hand, in presence of stable Pseudoemulsion, the plateau borders are relatively thick and slow down the liquid drainage. The entrapment of stable Pseudoemulsion at the junction of liquid lamella which has been formed by C1 foam and crude oil ‘J’ at 10% oil saturation is shown in Fig. 21.

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Fig. 23 – Effect of 10% of crude oil ‘J’ on CO2 -foam stability versus N2 -foam stability (0.3 wt.% C1).

Fig. 21 – Slowing down the liquid drainage by trapping oil in plateau borders in 0.3 wt.% of C1 foam in presence of 10% oil (red dotted circles show the oil trapping mechanisms in plateau borders). (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)

Also the emulsion droplets influence the foam stability. When the oil droplets are trapped in plateau borders, the droplets compress and form emulsion films. If these films are stable, emulsion droplets do not coalesce and the foam stability is not adversely affected. However, when emulsion films are unstable, the oil droplets coalesce on plateau borders and result in formation of large oil drops due to further foam drainage. These large oil drops drain by capillary pressure and join other oil drops at junctions of plateau borders and form tetrahedron shapes. These tetrahedrons are highlighted by the red circles in Fig. 21. We also observed that in the case of unstable Pseudoemulsion films, the large drops can bridge easier and break the foam lamella faster. This phenomenon was observed at oil saturation of 40% and C1 foam (Fig. 22). As we will explain

later, the concentration of 0.3 wt.% is insufficient for creating stable Pseudoemulsion film at oil saturation of 40% and the liquid bridges can break the foam lamella due to gravity forces. Further research is required to better understanding the mechanisms by which foam stability is affected in the presence of oil.

3.1.4.2. Effect of crude oil on foam with different gas type (N2 versus CO2 ). As shown in previous section, the stability of N2 foam was much higher than CO2 -foam in the absence of crude oil. In order to investigate the N2 -foam stability in the presence of crude oil, Test 49 was performed and the results were compared with those of Test 45. All pertinent parameters such as surfactant type (C1), surfactant concentration (0.3 wt.%) and crude oil ‘J’ saturation (10%) was kept unchanged except the type of gas which was changed to N2 . Fig. 23 shows that the CO2 -foam stability was higher than N2 foam in presence of 10% of crude oil ‘J’. In other word, crude oil ‘J’ has more de-stabilization effect on N2 foam. It is expected to observe more stable N2 foam in presence of crude oil ‘J’ due to its non-spreading behaviour of N2 /crude oil/surfactant oil system over CO2 /crude oil/surfactant. But in the range of oil saturation used in our tests, for both N2 and CO2 foams the oil showed spreading behaviour. However, CO2 -foam injection performed much better compared to and N2 -foam injection. This is due to oil viscosity reduction and better displacement efficiency in case of CO2 -foam injection (Emadi et al., 2011).

Fig. 22 – Demonstration of breaking foam lamella by liquid bridge in case of unstable Pseudoemulsion film that it drained due to gravity forces. Please cite this article in press as: Farzaneh, S.A., Sohrabi, M., Experimental investigation of CO2 -foam stability improvement by alkaline in the presence of crude oil. Chem. Eng. Res. Des. (2014), http://dx.doi.org/10.1016/j.cherd.2014.08.011

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Fig. 24 – Effect of different oil types on C1 foam height at different times.

Fig. 25 – Effect of alkaline type on foam half-life time at different concentrations (0.3 wt.% C1 and 10% crude oil ‘J’).

3.1.4.3. Effect of oil type. In order to examine the effect of different oil types on the C1 foam stability, Tests 50 and 51 were performed and the results were compared with those obtained in Test 45. All parameters were kept constant except the type of crude oil which was changed to crude oil ‘A’ and crude oil ‘E’. Fig. 24 shows the results of C1 foam stability against 10% saturation of different crude oils. The results clearly demonstrate that as the oil became lighter, the system became more (oil) spreading and hence, which results in less stable foam. This observation means that foam injection for EOR favours heavy oil reservoirs compared to light oil reservoirs, as far as foam stability is concerned.

3.1.5.

Effect of alkaline on foam stability

The results of the foam stability experiments have been used to rank a number of leading surfactants for their ability in generating foam with and without crude oil. From the results, it is clear that crude oil effect on stability of foam is one of the most important parameters to be considered when assessing the ability of foam for mobility control. Presence of oil becomes detrimental to foam at different oil saturations for different systems. As shown in Fig. 19, foam half-life dropped from 222.5 min (without oil) to only 7 min in case of CO2 -foam generated by 0.3 wt.% of C1 in presence of 10% crude oil. Alkaline solutions were tested with the aim of producing more stable foams in presence of crude oil in particular for the system of subcritical CO2 and extra heavy crude oils. It is well known that addition of alkali can significantly decrease oil–water IFT (interfacial tension) which would be expected to help with stability of foam. To examine this idea, three types of alkalis were used to evaluate their impact on foam stability. The results show that alkalis with lower pH (mild) result in better foam stability and longer foam half-life, whereas strong alkalis (NaOH) have poor foam stability. NaOH showed the lowest foam stability between the alkaline solutions tested. Fig. 25 compares the impact of alkaline on CO2 -foam stability for the three alkaline solutions used with various concentrations. The concentration of the surfactant (C1) used for the tests was 0.3% with a fixed 10% oil saturation. The results in Fig. 8 clearly show that Neobor (Borate) results in higher foam stability. Na2 CO3 also resulted in a relatively effective improvement on foam stability.

3.1.5.1. Effect of alkaline concentration. A number of tests were performed to examine the effect of concentration of NaOH on the stability of CO2 -foam generated with 0.3 wt.% of C1 in presence of 10% crude oil at 0.1 wt.%, 0.2 wt.%, 0.5 wt.% and 1 wt.%

Fig. 26 – Effect of NaOH concentrations on foam height at different times (0.3 wt.% and 10% crude oil ‘J’).

Fig. 27 – Effect of Na2 CO3 concentrations on foam height at different times (0.3 wt.% C1 and 10% crude ‘J’). of NaOH concentrations. As can be seen in Fig. 26, CO2 -foam became more unstable by adding NaOH. The likely reason for this adverse effect of NaOH on CO2 -foam stability is the reactions between NaOH and CO2 which neutralizes the added NaOH. Similar tests were performed to test the impact of addition of Na2 CO3 on CO2 -foam stability which had been generated with 0.3 wt.% of C1 and 10% of crude oil. As can be seen from Fig. 27, the results clearly demonstrate that the CO2 -foam stability increases with increasing Na2 CO3 concentrations. However, the results show that the CO2 -foam stability first increased by increasing the concentration of Na2 CO3 and then decreased when Na2 CO3 concentration increased further

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Conclusions

In the first part of the paper, parameters affecting CO2 -foam stability including: surfactant types, surfactant concentration, gas type, different crude oil, and interactions between foam and oil were investigated. The objective of this part was to systematically screen surfactants based on their ability to generate stable foam in foam column experiments. The following conclusions can be drawn from the first part:

Fig. 28 – Effect of Borate concentrations on foam height at different times (0.3 wt.% C1 and 10% crude ‘J’).

Fig. 29 – Measured pH of NaOH, Na2 CO3 and Borate at different concentration. (Fig. 27). This behaviour suggests that there is an optimum Na2 CO3 concentration which corresponds to maximum foam stability and foam half-life. The effect of Borate (the third alkaline tested) on foam stability was also investigated. Fig. 28 illustrates the results of this investigation. CO2 -foam stability increased up to a Borate concentration of 1 wt.% and then decreased at higher concentrations. The results indicate that Borate makes the oil more non-spreading and, therefore, increases the strength and stability of CO2 -foam.

3.1.6.

Compatibility of CO2 and Borate

The question here is that since dissolution of CO2 in water results in formation of carbonic acid and a subsequent reduction of pH, co-injection of CO2 and Borate may lead to neutralization of the effect of Borate (alkaline). While this would be a concern in injection of traditional alkaline (e.g., NaOH), it was not observed in our experiments where Borate was used, most probably due to strong buffering effect of Borate. There are no direct reactions between CO2 and Borate other than what is pH driven. Borate is a mild alkaline with natural pH of 9–11.9 and addition of carbonic acid (due to dissolution of CO2 in water) will bring the pH down converting it into other Borates, such as borax (natural pH about 9.2–9.3). This produces a buffered system containing sodium carbonate, sodium bicarbonate, borax with compositions governed by the Borate concentration and CO2 partial pressure. The measured pH values of NaOH, Na2 CO3 and Borate at different concentrations are shown in Fig. 29 which clearly shows the excellent buffering ability of Borate.

• For the conditions of our tests, anionic surfactants demonstrated better foam stability and longer half-life compared to non-anionic surfactants. Also, in the range of our foam stability tests, XP-0010 generated the highest foam stability. • The foam half-life increased with increasing surfactant solution concentration but there is an optimum concentration beyond which foam stability decreases with increasing surfactant concentration. • Higher surfactant concentration produced smaller lamella size and hence denser foam. Also, foam texture changes with surfactant type. • N2 -foam has higher stability in comparison with CO2 -foam. • The presence of crude oil reduced the stability of the foam but the reduction was more pronounced when the oil concentration increased to 40% and XP-0010 foam is much more resilient to crude oil. • CO2 -foam stability increased when crude oil viscosity increased. Therefore, foam is expected to be more stable in heavy oil reservoirs compared to light oil reservoirs.

In the second part of the paper, we investigated the potential of using alkaline as a CO2 -foam stabilizing agent through a systematic testing of the foam height and stability in a series of foam column tests using a number of different alkalis.

• Using an appropriate alkaline-surfactant solution can lead to generating more stable foam than surfactant solution alone. • We report for, the first time, the successful application of Borate for increasing CO2 -foam stability. • Stability of CO2 -foam decreased by NaOH in presence of crude oil while, stability of CO2 -foam increased by Na2 CO3 in presence of crude oil. But the highest increase in foam stability was achieved by addition of Borate. • This study focused on experimental investigation by means of bulk foam method to systematically screen surfactant(s) based on their ability to generate stable foam in foam column as well as examining the potential of using alkaline as a CO2 -foam stabilizing agent. Providing experimental data in porous media and at reservoir conditions is required to confirm that the results are applicable to porous media. This part of the study is currently on-going and will be reported in a subsequent paper.

Acknowledgment This work was carried out as part of the Enhanced Heavy Oil Recovery joint industry project (JIP) at the Institute of Petroleum Engineering of Heriot-Watt University which is equally supported by: Total E&P, ConocoPhillips, Pemex, and Wintershall which is gratefully acknowledged.

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