Review on Surfactant Flooding - American Chemical Society

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Review on Surfactant Flooding: Phase Behavior, Retention, IFT and Field Applications Muhammad Shahzad Kamal, Ibnelwaleed A. Hussein, and Abdullah S Sultan Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b00353 • Publication Date (Web): 06 Jul 2017 Downloaded from http://pubs.acs.org on July 6, 2017

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Review on Surfactant Flooding: Phase Behavior, Retention, IFT and Field Applications Muhammad Shahzad Kamal1, Ibnelwaleed A. Hussein2*, Abdullah S. Sultan3 1

Center for Integrative Petroleum Research, King Fahd University of Petroleum & Minerals, 31261 Dhahran, Saudi Arabia

2

Gas Processing Center, College of Engineering, Qatar University, PO Box 2713, Doha, Qatar

3

Department of Petroleum Engineering, King Fahd University of Petroleum & Minerals, 31261 Dhahran, Saudi Arabia

*Corresponding Author: Ibnelwaleed A. Hussein, [email protected]

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Abstract Surfactant flooding is an important technique used in enhanced oil recovery to reduce the amount of oil in pore space of matrix rock. Surfactants are injected to mobilize residual oil by lowering the interfacial tension between oil and water and/or by the wettability alteration from oil-wet to water-wet. A large number of cationic, anionic, non-ionic, and amphoteric surfactants have been investigated on a laboratory scale under different conditions of temperature and salinity. Selection of the appropriate surfactant is a challenging task, and surfactants have to be evaluated by a series of screening techniques. Different types of surfactants along with their limitations are reviewed with particular emphasis on the phase behavior, adsorption, interfacial tension, and structure-property relationship. Factors affecting the phase behavior, interfacial tension, and wettability alteration are also discussed. Field applications of surfactants for chemical enhanced oil recovery in carbonate and sandstone reservoirs are also reviewed. Finally, some recent trends and future challenges in surfactant enhanced oil recovery are outlined. Field studies show that most of the surfactant flooding has been conducted in low-temperature and low-salinity sandstone reservoirs. However, high-temperature and high-salinity carbonate reservoirs are still challenging for implementation of surfactant flooding.

Keywords: Surfactant, Interfacial Tension, Adsorption, Chemical Enhanced Oil Recovery, Reservoir


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1 INTRODUCTION Oil has been the most important and significant source of energy so far, and it will contribute significantly in meeting the future energy demand as well 1. Thus, it is necessary to enhance the current production level in the next few decades, which can be achieved by either discovering new fields or increasing the production from existing oil fields. Only about one-third of the oil present in a reservoir can be recovered using primary and secondary recovery techniques 2-5. Oil is initially recovered from a reservoir using the inherent pressure of the reservoir (primary recovery). After the dissipation of the initial pressure, oil is recovered by applying external pressure using seawater injection into the reservoir (secondary recovery). Enhanced oil recovery (EOR) or tertiary recovery techniques are used to recover the remaining oil which cannot be recovered using water flooding 6. Although chemical EOR (cEOR) is one of the most promising methods available to recover residual and remaining oil, it was not very commonly employed in the past due to low oil prices and the high cost of chemicals. However, continuous rise in oil prices and the growing demand for oil have encouraged researchers to determine economical and low-cost cEOR technology to recover the maximum amount of the remaining oil. In cEOR, a range of chemicals such as surfactants, polymers, and/or alkalis are used to increase the microscopic efficiency (displacement efficiency) and the macroscopic efficiency (volumetric sweep efficiency) 7-16. Macroscopic efficiency is related to the effectiveness of the displacing fluid in sweeping out the reservoir volume both areally and vertically as well as moving the oil towards the production well 17. Macroscopic efficiency can be increased using mobility control methods. Polymers are used to increase the viscosity of the displacing fluid (water), which improves the oil/water mobility ratio 18-21. On the other hand, microscopic efficiency is related to the displacement of oil at the pore scale. It is not possible to displace all the oil that comes into contact with water during water flooding, due to trapping of oil by capillary forces. The relationship between the capillary forces and the viscous forces results in a dimensionless capillary number ( ), where µ is the viscosity of the aqueous phase, v is the velocity and γ is the interfacial tension between oil and water and θ is the contact angle 22, 23. Microscopic efficiency can be improved by decreasing the capillary forces and the oil/water interfacial tension. Capillary number is closely related to oil recovery and residual oil saturation (oil saturation is the volume fraction of oil within the pore volume), and is in the range of 10-7 to 10-6 for typical brine flooding. Increasing the capillary number to between 10-4 and 10-3 reduces the oil saturation to 90% 6 and residual oil saturation approaches zero if capillary number reaches 10-2 24. In order to reach this value, the interfacial tension (IFT) should be decreased from an initial value of 20-30 mN/m to values in the range of 10-2 to 10-3 25, which is achieved through the use of surfactants during flooding with brine 26-28. Surfactants also influence the amount of residual oil recovered via other mechanisms, including micro emulsification of trapped residual oil, changing the wettability of rock, and improving the interfacial rheological properties 29-36. Here wettability is defined as “the tendency of one fluid to adhere to a solid surface in the presence of another immiscible fluid”. 3 ACS Paragon Plus Environment

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A large number of surfactants have been evaluated on a laboratory scale and tested in the field 3739 . Appropriate surfactants for a set of particular reservoir conditions are selected after a series of evaluation steps. Evaluation is based on the surfactant structure, reservoir temperature, reservoir salinity, pH, permeability of rock, formation type, cost of the surfactant, adsorption of the surfactant on the matrix rock, and finally, the oil recovery. The results of several experimental investigations covering different aspects of surfactant flooding have been published 40-43. There are several reviews that cover various aspects of surfactant and surfactant-polymer flooding. Seright et al. summarized the polymer requirement in previous and current polymer floods owing to their different viscosities and bank sizes 44, 45. Saboorian et al. established a complete data set of laboratory experiments, pilot tests, and field applications of polymer flood for heavy oil reservoirs 21, 46. Olajire 17 reviewed alkaline-surfactant-polymer (ASP) flooding in general, discussing the mechanism, prospects, and challenges of ASP flooding. Hirasaki et al. reviewed mainly role of alcohol, alkali, and chain branching on phase behavior 4. Sheng reviewed the current status of surfactant EOR technology and summarized experimental and simulation work in carbonate and shale reservoirs 47. Raffa et al. reviewed the polymeric surfactants that have been utilized in EOR 48. They collected the relevant work done in last decade with a particular emphasis on patent literature and bio-based systems 48. This review covers different aspects of surfactant flooding that are not covered in previous studies. Surfactant flooding is a complex process and there is a lack of understanding that how particular surfactant will behave in typical reservoir conditions. Due to different types of interactions of surfactant with brine and other oilfield chemicals, conflicting results have been reported in the literature on different aspects of surfactant flooding such as IFT. In this review, the phase behavior, IFT, and adsorption of surfactants is discussed in relation to surfactant structure. The review highlights chemical nature of various surfactants that was ignored in previous reviews. Field implementation of various surfactants in carbonate and sandstone reservoirs is also part of this review. In addition, recent trends, current challenges, and future directions of surfactant EOR are also addressed. The review is divided into different sections to explain different aspects of surfactant flooding. The first section discusses the fundamentals of surfactant EOR that can introduce the readers with different types of surfactants, oil reservoirs, and screening criteria of surfactants. The second section discusses the potential surfactant systems for EOR that include but not limited to anionic surfactants, cationic surfactants, zwitterionic surfactants, viscoelastic surfactants, and fluorinated surfactants. Subsequent sections discuss the various factors affecting phase behavior, IFT, adsorption and wettability alteration during surfactant flooding. Finally, field applications and challenges of surfactant EOR are addressed.

2 FUNDAMENTALS OF SURFACTANT EOR 2.1 Surfactants A surfactant is a long-chain molecule which has a hydrophilic (water soluble) head group and a hydrophobic (oil soluble) tail group 49. The hydrophobic group may be a long chain hydrocarbon, 4 ACS Paragon Plus Environment

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fluorocarbon, a siloxane chain, or a short polymer chain. The hydrophilic group may be anionic, cationic, amphoteric, or non-ionic. Surfactant classification is mainly based on the nature of the hydrophilic head group. In anionic and cationic surfactants the hydrophilic group is negatively and positively charged, respectively. Non-ionic surfactants do not ionize in aqueous solution as the hydrophilic group is of non-dissociative nature. Water solubility of non-ionic surfactants is due to the hydrogen bonding between the hydrophilic group, typically an ethylene oxide chain or a similar group, and water 50. Hydrophilic group is both negatively and positively charged in amphoteric surfactants. Some common hydrophilic groups are summarized in Table 1. The properties of surfactants change considerably above and below the critical micelle concentration (CMC). At the CMC, the surface active ions or molecules in solution associate to form larger aggregates known as micelles. At a given temperature and electrolyte concentration, each surfactant has a unique CMC value. For all surfactants, CMC depends on the chain length of the hydrophobic tail, temperature, and salinity. CMC decreases by a factor of 2 for ionic surfactants and a factor of 3 for non-ionic surfactants for each addition of a methylene group 51. As the surfactant must be present at a concentration higher than the CMC to obtain a lower IFT and better foam stability, CMC is an important criterion to be considered in EOR applications. Also, the maximum adsorption of a surfactant on the reservoir rock surface occurs at the CMC, above which adsorption do not increase significantly. CMC is typically determined by plotting a physicochemical property against the surfactant concentration. CMC can be determined by surface tension and conductivity measurement, voltammetry, IR spectroscopy, and nuclear magnetic resonance spectroscopy. Another important criterion for the characterization of a single-component surfactant or a mixture of surfactants is the hydrophilic-lipophilic balance (HLB). It is a measure of the degree to which a particular surfactant is hydrophilic or lipophilic. HLB can be adjusted either by varying external parameters, such as the electrolyte concentration and the solution temperature or manipulating the structure of the surfactant, such as varying the hydrophobic chain length and employing a more or less hydrophilic head group 52. A low HLB value (11) indicate that the surfactant is hydrophilic 53. Another important surfactant property is the Krafft point, which is the minimum temperature at which surfactant form micelles. If temperature is < Krafft point, there is no value for critical micelle concentration; and micelles cannot form 53, 54. The solubility of a material undergoes a sharp increase at Krafft point55.

2.2 Types of Oil Reservoirs Depending on the formation rocks, oil reservoirs are classified either as carbonate reservoirs or sandstone reservoirs. Sandstone reservoir rock consists of a large amount of silica with silicate minerals, and carbonates are only a minor fraction. Some clay minerals, such as kaolinite and illite, are also present in sandstone formations 56. Sandstone reservoirs, which are homogeneous, are the most appropriate for cEOR 57. Carbonate reservoirs, which are estimated to contain 60% 5 ACS Paragon Plus Environment

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of the remaining oil, are composed of calcite (CaCO3), dolomite (CaMg(CO3)2), anhydrite (CaSO4), gypsum (CaSO4.H2O), and magnesite (MgCO3) rocks. Carbonate reservoirs have been estimated to contain about 3000 billion barrels of the remaining oil and 3000 trillion SCF gas 58. Some carbonate reservoirs are characterized by fractures with a high conductivity, which are surrounded by a low permeability matrix. Most of these reservoirs have oil-wet to mixed-wet conditions. Although carbonate reservoirs have a great potential for the application of tertiary recovery techniques, EOR research associated with carbonate reservoirs is limited due to many technical challenges. Only a few reports on the application of cEOR in carbonate reservoirs are available, mainly due to the high clay content which results in significant adsorption of surfactants 57. Also, carbonate reservoirs are complex and heterogeneous and cEOR is less effective with carbonates 59, 60. Precipitation of calcium carbonate and calcium hydroxide occurs as a result of the reaction of injected surfactants with divalent ions, particularly Ca++ and Mg++. Oil recovery from fractured reservoirs is even lower due to poor imbibition of water. In fractured carbonate reservoirs, surfactants are normally injected to change the wettability from oil-wet to water-wet. Wettability alteration results in the spontaneous imbibition of water into the oil containing matrix, and driving the oil out 58.

2.3

Screening Methodology and Evaluation Criteria

A candidate surfactant for cEOR should have the following properties: good thermal stability (at reservoir temperature), ability to lower the oil/water IFT to 10-3 mN/m, low retention on reservoir rock (1 mN/m) the process will be capillary driven 143

6.1 Factors Affecting Interfacial Tension Most of the surfactants showed dynamic IFT behavior between crude oil and water. IFT decreases with time to a transient minimum value and increases after achieving transient minimum value 40, 144, 145. Dynamic IFT can be used as a test to determine whether the crude oil is free from surface-active species or not. A change of IFT between crude oil and brine with time indicates that there are surface-active species in the oil, which diffuse slowly and result in a decrease in IFT with time. These surface active species may include emulsion breakers, scale inhibitors, or rust inhibitors 112. 6.1.1

Addition of Polymer

Varying results have been reported on the effect of polymers on the minimum IFT value. Hongyan 146 obtained similar IFT values with and without a polymer and concluded that the addition of a polymer has no effect on the ability of the surfactant to reduce IFT. Similar observations have been made by other groups for HPAM and xanthan gum 147, 148. However, Li et al. 139 found that a polymer can decrease the minimum IFT value and attributed it to the decrease in the dissociation rate of surface active species owing to the high viscosity of the aqueous phase. Taylor 149 reported that the addition of a polymer reduces IFT down to a specific concentration of the surfactant. If the surfactant concentration is above this minimum concentration the IFT of the SP solution will be lower than that of the surfactant solution alone. However, a polymer may increase the time required to attain the minimum IFT value due to the decrease in the diffusion rate of the surfactant to the oil-water interface 146. Enhanced viscosity due to the addition of a polymer increases the mass transfer resistance and decreases the mass transfer rate at the interface.


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6.1.2

Surfactant Concentration

IFT displays three types of behavior in different concentration ranges. At low concentrations of the surfactant, IFT normally decreases with the increasing surfactant concentration up to an optimum value. At intermediate concentrations, a further increase in the surfactant concentration above the optimum value increases the IFT 116, 150, 151 and at high concentrations, IFT decreases again. The dependence of IFT on the surfactant concentration is due to the adsorption/desorption of the surfactant at the oil/water interface and the formation of a stable emulsion. The surfactant concentration at which the rate of adsorption and desorption is equal will result in the minimum IFT. IFT decreases with increasing surfactant concentration up to this optimum surfactant concentration. Further increase in the surfactant concentration above the optimum value increases the IFT due to the high desorption rate of the surfactant from the interface. Continued increase in the surfactant concentration results in the formation of a stable emulsion and IFT starts decreasing again 152. The increase in the IFT at intermediate concentrations of the surfactant is also due to the formation of micelles. At low concentrations, the surfactant is in the monomer form and a further increase of the concentration reduces the IFT due to a large number of monomer units. The maximum number of monomer units in solution will be at the critical micelle concentration (CMC). As the concentration of the monomer decreases due to the formation of micelles, IFT increases above CMC 152, 153. Further increase in the surfactant concentration results in the formation of a stable emulsion, which decreases IFT again 152. This type of behavior is not characteristic of all surfactants. 6.1.3

Molecular Structure of Surfactant

As the interfacial energy is higher for the CH2 group compared to the CH3 group, the presence of more CH3 groups in the outermost layer will result in a low interfacial tension 154, 155. Surfactants with larger hydrophobes are more efficient in lowering IFT as compared to the surfactants with shorter hydrophobes 156. Although the number of PO groups has no effect on the IFT for the ALFOTERRA® 3n series at various salinities 109, 111, IFT decreases with increasing number of PO groups for the ALFOTERRA® 2n series 109 and ALFOTERRA® 6n series 111. Even though more hydrophilic surfactants have higher aqueous stability even under high salinity conditions, the high hydrophilicity reduces their ability to lower the IFT. Increasing the hydrocarbon chain length makes surfactants more lipophilic 87 and favors their movement from the bulk aqueous phase to the oil-water interface. Thus, increasing the hydrophobic tail length lowers the IFT. 6.1.4

Presence of Alkali

Alkalis react with the acidic components of crude oil at the oil/water interface and generate an in-situ surfactant according to following reaction 139:

where HA is an organic acid and A- is the ionized acid. The ratio of ionized to un-ionized acid is the main factor that determines the IFT and the concentration of the ionized species depends on their adsorption and desorption rate at the interface. If the rate of adsorption is high the ionized species accumulate at the interface resulting in the decrease in IFT. However, if the rate of 19 ACS Paragon Plus Environment

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desorption of the active species is high due to the large concentration gradient, then IFT increases. Alkalis affect both the minimum IFT and the time required to achieve the minimum IFT. As it will take some time for the acid at the interface to diffuse and react with the alkali, the minimum IFT is normally achieved after a time lapse and it is a dynamic process. The concentration of ionized acid at the interface increases with time causing the reduction of the IFT. The minimum IFT will be at the time when the ratio of ionized acid to un-ionized acid is equal to 1139, 157. As increasing concentration of the alkali increases the rate of diffusion and reaction, the time required to reach the minimum IFT decreases with increasing alkali concentration 139. However, an opposite trend has been reported by Nasr-El-Din 158. Although increasing concentration of the alkali can reduce the IFT, after a critical concentration IFT may increase 98, 111, 139, 158-160. This behavior has been observed for alkyl aryl sulfonate, sodium lauryl ether sulphate, and propoxylated sulphate surfactant, which is related to the concentration of the ionized acid and pH at the interface. The initial decrease in the IFT is due to the increase in the pH and the concentration of ionized species at the interface. After a critical value, the concentration of the ionized acid decreases due to shifting of the equilibrium or due to the salting-out effect 139. Mingzhe et al. proposed another mechanism for the increase of the IFT at higher alkaline concentration 161. They proposed that the decrease in the ionic species at high alkali concentration is due to the formation of micelles and the compression of the electric double layer at high ionic strength. 6.1.5

Co-surfactant

In certain cases, the addition of a co-surfactant helps achieve low IFT values, which depends on the synergism between the two surfactants. An extensive amount of literature on the impact of adding a co-surfactant on the IFT is available 116, 151, 162, 163. For example, the combination of alkyl alcohol amide (co-surfactant) and naturally mixed carboxylate (surfactant) gives a much lower IFT compared to naturally mixed carboxylate alone 139. A similar synergism has been reported for a bio-surfactant and alkyl benzene sulfonate116 and other systems 151. The synergic effect depends on the interactions between the surfactants and their interactions with the aqueous and oleic phases. If the surfactant is lipophilic then the hydrophilic surfactant may be required to balance the hydrophilic-lipophilic interactions 151. The ratio of the surfactant to co-surfactant is also important. When the interactions between the surfactants are not strong, equimolar concentrations will give the minimum IFT 164. In another study, it was reported that the combination of a non-ionic surfactant (Tx-100) and an anionic surfactant (sodium dodecyl benzene sulfonate) has lower IFT as compared to the IFT of the anionic surfactant 146. This reduction in the IFT is attributed to the aromatic groups present in the surfactant interacting with the aromatic hydrocarbons of crude oil to lower the interfacial tension. An optimum amount of alcohol can be used to obtain an ultra-low IFT. At low alcohol concentrations, the IFT decreases with increasing alcohol concentration, but IFT increases after reaching a minimum with further increase 165. This behavior is attributed to the competitive adsorption of the alcohol and the surfactant at the oil/water interface.


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6.1.6

Salinity

Under high salinity conditions, extremely hydrophilic surfactants are required for aqueous stability 63. Surfactants with long carbon chains phase separate under high salinity conditions 63. Therefore, short chain surfactants are preferred in high salinity conditions, but they have poor oil solubilization 63. Salts can significantly change the interfacial properties and can result in a change in IFT for various types of surfactants. At low salt concentration, most of the surfactants dissolve in the aqueous phase, while at high salt concentration surfactants stay in the oleic phase. However, at the optimum salinity, the surfactant dissolves equally in the oil and aqueous phases resulting in the minimum IFT 164. For the Shengli crude oil/naturally mixed carboxylate system, IFT decreases as the divalent ion concentration is increased to 300 mg/dm3, but further increase of the divalent ion concentration increases the IFT 139. Similarly, for various ALFOTERRA® surfactants, IFT decreases dramatically to a minimum value when the NaCl concentration is increased and a further increase in NaCl concentration increases the IFT 109. Similar behavior has been reported for other surfactant systems 166. Liu observed that IFT increases in the presence of divalent cations, but the tests were conducted only at a fixed divalent concentration 167. The decrease in the IFT with the addition of salt can be attributed to the decreased hydrophilicity of the surfactant and its movement to the oil/water interface 87. However, adding more salt will result in moving the surfactant from the oil/water interface to the oleic phase resulting in an increase in IFT. 6.1.7

Temperature

Temperature affects the solubility of surfactants in water and brine solution and changes the interaction energy of the head and tail groups. The increase of the temperature can increase the solubility of the hydrophobic tail in the water and move the surfactant to the oil/water interface resulting in a decrease in the IFT 87. IFT typically increases with temperature for most of the reported surfactant systems 144. For ALFOTERRA® 35 series, a decrease of IFT between ndecane and distilled water (DW) with temperature has been reported 109. For various ether sulfonate surfactants decrease in the IFT with temperature was observed up to a certain temperature, and a further increase in the temperature resulted in an increase of the IFT 40. The decrease of the IFT with increasing temperature is due to the decrease in the viscosity of the oil, which enhances the surfactant migration to the interface 40. Effect of temperature on the IFT also depends on the type of the crude oil. Varying IFT-temperature behavior was reported for standard, paraffinic, aromatic, and naphthenic oils. For aromatic oil, IFT was constant up to 50 o C and increases after 50 oC, while for naphthenic oil a decrease in IFT with temperature was observed. Paraffinic oil showed exactly the opposite IFT-temperature behavior to that of aromatic oil 40.

6.2 Measuring Techniques IFT is measured using the spinning drop technique, which is useful when the surfactant is available in small quantities. This method is a non-equilibrium measurement method and results obtained may be influenced by the time taken for the temperature to stabilize and the variability 21 ACS Paragon Plus Environment

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of the oil drop in different experiments and the duNouy ring method 168.

130

. Other methods include the pendant drop method

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51

7 WETTABILITY ALTERATION Oil reservoirs can be water-wet, mixed-wet, or oil-wet. Most of the carbonate reservoirs are fractured, oil-wet, and mixed-wet in nature 169-171. Wettability concept can be understood by measuring the contact angle (θ) between the rock surface and an oil droplet placed on it (contact angle is the angle of macroscopic meniscus when extrapolated to zero thickness 172). If θ > 90o the rock is more oil-wet and if θ < 90o the rock is more water-wet. In the case of oil-wet rock, oil is retained by the matrix rock due to capillarity and the oil flow is reduced due to trapping of water globules as the non-wetting phase 170. In the case of water-wet and mixed-wet carbonate reservoirs, injected water imbibe into matrix block and displace the crude oil (Imbibition is defined as the process in which water is displacing oil 173). Fractures act as the transport zone for both water and displaced oil. However, in case of oil-wet reservoirs, spontaneous imbibition of water cannot take place and the injected water will move towards the production well through the fractures 168 (Spontaneous imbibition is defined as the imbibition that takes place by the action of capillary pressure and/or buoyancy when matrix block is surrounded by formation brine 173 ). Therefore wettability is altered from oil-wet to water-wet to recover additional oil. Use of surfactants to change wettability is one of the techniques adopted by many researchers to recover oil from oil-wet fractured carbonate and sandstone reservoirs 174. Cationic, non-ionic, and ionic surfactants have been reported to alter the wettability of initially oil-wet rock.

7.1 Wettability Alteration by Cationic Surfactants Organic components of crude oil containing negatively charged groups are normally adsorbed on the positively charged mineral surfaces of carbonates 175. Interactions occur between the cationic surfactant monomer and the anionic material (mostly carboxylate) adsorbed on the rock surfaces from crude oil. Due to ion pair formation between the cationic monomer and anionic groups, adsorbed material at oil, water, and rock interface will be desorbed from the rock. The ion pair is not soluble in the aqueous phase but soluble in the oleic phase. Thus, water will penetrate and oil will be expelled from the core material. When the adsorbed material is desorbed from the surface, it becomes more water-wet and oil can be expelled 168. Mechanism of wettability alteration by cationic surfactants is shown in Figure 8. Austad et al. showed that cationic surfactants can recover additional oil by spontaneous counter-current imbibition from chalk core 168, 176

7.2 Wettability Alteration by Anionic Surfactants Anionic surfactants are not able to desorb negatively charged groups of carboxylate from the rock surface. Anionic surfactants generate weak capillary forces through hydrophobic interaction between the tail of the surfactant and the negatively charged adsorbed groups 168. Minor oil 22 ACS Paragon Plus Environment

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displacement by ethoxylated sulfonates from carbonate cores is associated with the formation of a water-wet bilayer between the carbonate surface and oil. Mechanism of the formation of the bilayer is shown in Figure 9. Alkyl propoxylated sulfates and alkyl aryl sulfonate change the wettability of calcite from water-wet to oil-wet 177, 178. Wettability can be measured by calculating the Amott–Harvey index of a core before and after spontaneous imbibition 168, 179, and the contact angle measurement of a water droplet placed on the planar surface before and after exposing to the surfactant solution. Wettability alteration depends on the aging time, surfactant type and concentration, temperature, crude oil composition, brine composition, nature of the rock, and water saturation 173, 180. The increase of the temperature changes the solubility of adsorbed components, leading to desorption from the matrix rock making it more water-wet 181-183. A decrease in the contact angle with temperature was observed, which confirms the formation of a more water-wet state 183.

8 FIELD APPLICATIONS AND FUTURE CHALLENGES OF SURFACTANT EOR 8.1 Comparison of Field and Lab data Some important surfactants that have been reported for EOR applications in different oil fields are listed in Table 2. Data indicates that surfactant flooding has been utilized in a number of oil fields around the world. Most of these oil reservoirs are sandstone reservoirs, and sulfonate surfactants are the most widely used surfactant. Field applications on chemical EOR show incremental oil recovery of ~ 12-30% of the original oil in place 184. However, most of the laboratory reports are showing 20-30% incremental oil recovery 20.

8.2 Economic Overview of Surfactant-Polymer Flooding No recent update on the cost of chemical EOR are available in the literature especially at current oil prices that are in the range of $50/bbl. However, the cost of polymers and surfactants is dropping and their consumption is low. An incremental barrel of oil is produced by ~ 1-2 lbs of polymer, which costs about $1.5/lb. With current oil prices in the range of $50/bbl chemical EOR is still economical 184.

8.3 Challenges and Future Alternate Challenges for surfactant flooding are in the high-temperature, high-salinity, fractured carbonate reservoirs. From the foregoing discussion, it is evident that for mild conditions (low temperature, low salinity) most of the surfactant formulations perform very well. In the case of hightemperature and low-salinity conditions, sulfonate surfactants can do the job. However, in hightemperature and high-salinity sandstone and carbonate reservoirs, many problems arise including the surfactant precipitation, high adsorption of surfactants, and chemical degradation. Many 23 ACS Paragon Plus Environment

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attempts have been made to develop surfactants that can tolerate a high-temperature, highsalinity environment. A recent trend in surfactant EOR is the use of a chelating agent or a sequestration agent together with the surfactant in high salinity environments to sequester divalent cations 185. Some commonly used chelating agents are ethylenediaminetetraacetic acid (EDTA), tetrasodium EDTA, and sodium acetate 186, 187. Recently acrylic acid has been used in a high salinity environment to avoid precipitation 57. The acrylic acid reacts with sodium ions and forms the precipitation inhibitor sodium acrylate, which reacts with mineral divalent ions and prevents the formation of precipitates 188. Alkalis are used to lower the adsorption on mineral surfaces in soft brines. In the case of hard brines, conventional alkalis precipitate and there is a risk of maintaining the reservoir integrity. Novel alkalis such as sodium metaborate are recommended for hard brines 189, 190. However, a complimentary evaluation has shown that high pH generated by the addition of alkali will eventually lead to the reaction of calcium ions with dissolved carbonate ions and result in precipitation 191. The alternative solution to prevent precipitation is the use of a chelating agent that makes the economics of the process questionable 192 . Proprietary adsorption inhibitors have also been proposed as an alternative to alkalis191. The combination of other chemicals like polymers and alkalis is not a new idea. It has been used in the field and laboratories for decades to achieve better mobility and oil recovery. Now the synergetic effect of the surfactant and chemicals other than alkalis and polymers has received attention. In addition, the focus is on the combined injection of the surfactant and gas to generate foam as a mobility control agent. Recently, encouraging results were obtained in using nanoparticles in EOR applications. Nanoparticles such as polysilicon, iron oxide, and silica nanoparticles have been reported to alter the wettability, to stabilize oil-in-water and water-in-oil emulsions, to stabilize CO2 foam, to reduce the IFT between oil and water, and finally, to increase oil recovery 193-201. Based on these results, attempts were made to investigate combined effects of the surfactant and nanoparticles 202-204 . A surfactant solution with nanoparticles has a lower IFT compared to the surfactant solution without nanoparticles. Adsorption of the surfactant also decreases in presence of nanoparticles. Moreover, oil recovery is better as compared to the surfactant alone. Similarly using non-ferrous metal particles with an anionic surfactant resulted in higher oil recovery and lower surface tension 205. Other nanoparticles which are investigated in nanoparticles-surfactant systems are alumina, zirconia, and silica 203, 206, 207. Oil recovery efficiency is higher for slightly hydrophobic nanoparticles as compared to hydrophilic nanoparticles. Zirconia particles also increase the viscosity of the surfactant solution and change the flow characteristics from Newtonian to non-Newtonian 203. Surfactant alternating gas (SAG) injection is now being used in heterogeneous formations to prevent early breakthrough due to overriding and fingering 208. The generated foam increases the viscosity of the gas, and better mobility control is obtained using SAG injection.


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9 CONCLUDING REMARKS A range of surfactant systems is reviewed for EOR applications. Mainly these surfactants are sulfonates, sulfates, carboxylates, cationic surfactants, non-ionic surfactants, and amphoteric surfactants. Some special classes of surfactants including Gemini surfactants, surfactants based on Guerbet alcohol, fluorinated surfactants, and viscoelastic surfactants are also discussed. Phase behavior, interfacial tension, adsorption, wettability alteration, and field applications are discussed as well. Reservoir conditions such as the temperature, salinity, type of rock, charges on rock, pH, and heterogeneity are main parameters that should be considered before the selection of a surfactant. Surfactants for EOR applications are screened using a series of evaluation criteria based on the compatibility, phase behavior, thermal stability, interfacial tension measurement, adsorption, and core flooding. Field studies show that most of the surfactant flooding has been conducted in low-temperature and low-salinity sandstone reservoirs, and sulfonate surfactants are the most widely used surfactants in these applications. However, sulfonate surfactants do not tolerate high salinity and hard brines, and most of the remaining oil is in high-temperature and high-salinity carbonate reservoirs. To extend surfactant flooding to high-temperature and highsalinity reservoirs, work on different strategies is underway. For carbonate reservoirs, amphoteric surfactants can be a better option due to good thermal stability and aqueous stability. Polymeric surfactants are a possible alternative to surfactant-polymer and alkali-surfactant-polymer flooding.

10 ACKNOWLEDGMENT This research is supported by Saudi Aramco through project # CPM 2297. Authors would like to thank Center for Petroleum & Minerals, King Fahd University of Petroleum & Minerals (KFUPM) for supporting this research.

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222. Jay, V.; Jim, T.; Bob, V.; Pitts, M.; Kon, W.; Harry, S.; David, P., Alkaline-SurfactantPolymer Flooding of the Cambridge Minnelusa Field. SPE Reservoir Evaluation & Engineering 2000, 3, (6), 1-6. 223. Chang, H. L.; Zhang, Z. Q.; Wang, Q. M.; Xu, Z. S.; Guo, Z. D.; Sun, H. Q.; Cao, X. L.; Qiao, Q., Advances in Polymer Flooding and Alkaline/Surfactant/Polymer Processes as Developed and Applied in the People? s Republic of China. Journal of Petroleum Technology 2006, 58, (2), 84-89. 224. Demin, W.; Jiecheng, C.; Junzheng, W.; Zhenyu, Y.; Yuming, Y. In Summary of ASP pilots in Daqing oil field, SPE Asia Pacific Improved Oil Recovery Conference, 1999; Society of Petroleum Engineers: 1999. 225. Li, H.; Liao, G.; Han, P.; Yang, Z.; Wu, X.; Chen, G.; Xu, D.; Jin, P. In Alkline/Surfactant/Polymer (ASP) Commercial Flooding Test In Central Xing2 Area of Daqing Oilfield, SPE International Improved Oil Recovery Conference in Asia Pacific, 2003; Society of Petroleum Engineers: 2003. 226. Li, D.; Shi, M.-y.; Wang, D.; Li, Z. In Chromatographic separation of chemicals in alkaline surfactant polymer flooding in reservoir rocks in the Daqing oil field, SPE International Symposium on Oilfield Chemistry, 2009; Society of Petroleum Engineers: 2009. 227. Pu, H. In An Update and Perspective on Field-Scale Chemical Floods in Daqing Oilfield China, SPE Middle East Oil and Gas Show and Conference, 2009; Society of Petroleum Engineers: 2009. 228. Zhijian, Q.; Yigen, Z.; Xiansong, Z.; Jialin, D. In A successful ASP flooding pilot in Gudong Oilfield, Symposium on improved oil recovery, 1998; 1998; pp 107-121. 229. Qi, Q.; Gu, H.; Li, D.; Dong, L. In The pilot test of ASP combination flooding in Karamay oil field, International Oil and Gas Conference and Exhibition in China, 2000; Society of Petroleum Engineers: 2000. 230. Gu, H.; Yang, R.; Guo, S.; Guan, W.; Yue, X.; Pan, Q. In Study on reservoir engineering: ASP flooding pilot test in Karamay Oilfield, SPE International Oil and Gas Conference and Exhibition in China, 1998; Society of Petroleum Engineers: 1998. 231. Zhang, J.; Wang, K.; He, F.; Zhang, F. In Ultimate Evaluation of the Alkali/Polymer Combination Flooding Pilot Test in XingLongTai Oil Field, SPE Asia Pacific Improved Oil Recovery Conference, 1999; 1999. 232. Pratap, M.; Gauma, M. In Field Implementation of Alkaline-Surfactant-Polymer (ASP) Flooding: A maiden effort in India, SPE Asia Pacific Oil and Gas Conference and Exhibition, 18-20 October, Perth, Australia, 2004; Society of Petroleum Engineers: 2004. 233. Meyers, J. J.; Pitts, M. J.; Wyatt, K. In Alkaline-Surfactant-Polymer Flood of the West Kiehl, Minnelusa Unit, 1992, Society of Petroleum Engineers: pp 423-435. 234. Bou-Mikael, S.; Asmadi, F.; Marwoto, D.; Cease, C. In Minas surfactant field trial tests two newly designed surfactants with high EOR potential, SPE Asia Pacific Oil and Gas Conference and Exhibition, 16-18 October, Brisbane, Australia, 2000; Society of Petroleum Engineers: 2000. 41 ACS Paragon Plus Environment

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235. Rilian, N. A.; Sumestry, M.; Wahyuningsih, W. In Surfactant Stimulation to Increase Reserves in Carbonate Reservoir" A Case Study in Semoga Field", SPE EUROPEC/EAGE Annual Conference and Exhibition, 2010; Society of Petroleum Engineers: 2010. 236. Zaitoun, A.; Fonseca, C.; Berger, P.; Bazin, B.; Monin, N. In New surfactant for chemical flood in high-salinity reservoir, nternational Symposium on Oilfield Chemistry, 5-7 February, Houston, Texas, 2003; Society of Petroleum Engineers: 2003. 237. Tabary, R.; Douarche, F. In Design of a surfactant/polymer process in a hard brine context: a case study applied to Bramberge reservoir, SPE EOR Conference at Oil and Gas West Asia, 16-18 April, Muscat, Oman, 2012, 2012; 2012; pp 1-13.


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List of Figures Figure 1: Flow chart of the surfactant screening procedure for cEOR applications Figure 2: Typical example of a sulfonate surfactant (sodium dodecyl benzene sulfonate) 209 Figure 3: Typical structure of a phosphate surfactant (phosphate ester) 73 Figure 4: Typical example of a non-ionic surfactant (polyethoxylated octyl phenol) 209 Figure 5: Typical example of an amphoteric surfactant (Dodecyl betaine) 209 Figure 6: Structure of TPM: R’ and R” are hydrophobic groups and R is a long chain hydrophilic group (R) 2 Figure 7: A typical surfactant adsorption isotherm on Berea sandstone

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Figure 8: Mechanism of wettability alteration for cationic surfactants. Circles represent the cationic surfactant molecules and squares represent the anionic surface active material present in the oil 210 Figure 9: Mechanism of the formation of the bilayer with ethoxylated sulfonate. Ellipses represent the anionic surfactant and squares represent the carboxylate material present in the oil 210

List of Tables Table 1: Some common hydrophilic groups of surfactants Table 2: Reported fields where surfactants have been used in EOR either as a surfactant flood or SP flood


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Select Surfactant

Compatibility & phase behavior

No Is it compatible

Surfactant is not suitable

Yes Thermal Stability at reservoir conditions

No Surfactant is not suitable

Is it stable? Yes

Adsorption

IFT

Core flooding

Decision

Figure 1: Flow chart of the surfactant screening procedure for cEOR applications


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Figure 2: Typical example of a sulfonate surfactant (sodium dodecyl benzene sulfonate) 209

Figure 3: Typical structure of a phosphate surfactant (phosphate ester) 73

Figure 4: Typical example of a non-ionic surfactant (polyethoxylated octyl phenol) 209

Figure 5: Typical example of an amphoteric surfactant (Dodecyl betaine) 209


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Figure 6: Structure of TPM: R’ and R” are hydrophobic groups and R is a long chain hydrophilic group (R) 2

Figure 7: A typical surfactant adsorption isotherm on Berea sandstone


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Figure 8: Mechanism of wettability alteration for cationic surfactants. Circles represent the cationic surfactant molecules and squares represent the anionic surface active material present in the oil 210

Figure 9: Mechanism of the formation of the bilayer with ethoxylated sulfonate. Ellipses represent the anionic surfactant and squares represent the carboxylate material present in the oil 210


Energy & Fuels

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Table 1: Some common hydrophilic groups of surfactants Type of SurfactantS Cationic

Hydrophilic Group Ammonium quaternary ammonium halides (R4N+X-)

Non-ionic

Polyoxyethylene, polyols, Sucrose esters, polyglycidyl esters carboxyl (RCOO-M+), sulfonate (RSO3M+), sulfate (ROSO3-M+), phosphate (ROPO3-M+). Betaine, Sulfobetaine RN+ (CH3)2CH2CH2SO3Imidazoline Derivatives

Anionic

Amphoteric


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Table 2: Reported fields where surfactants have been used in EOR either as a surfactant flood or SP flood Country

Field

Formation type

Surfactant

Ref.

Louden

sulfonate

211,

Borregos

sulfonate

213

Benton

Sulfonate

214

Bradford field

sulfonate

215

carbonate

petrostep-B100

216

carbonate

polyoxyethylene alcohol

217,

219

Yates fields

carbonate

mixture of petroleum sulfonate and alkylaryl ether sulphate non-ionic ethoxy alcohol

Tanner

sandstone

ORS-41

220

Sho-vel-tum

-

-

221

Cambridge minnelusa Daging

sandstone

-

222

sandstone

petroleum sulfonate, lignosulfonate, alkyl benzene sulfonate, petroleum carboxylate, bio-surfactant

223-

Gudong

sandstone

Karamay

sandstone

petroleum Sulfonate

229,

Xing long tai

sandstone

-

231

Viraj

sandstone

petroleum Sulfonate

232

West kiehl Minas

sandstone sandstone

petrostep B-100 petroleum Sulfonate

233

Baturaja

carbonates

-

235

SS-6066

236

olefin sulfonate

237

Cretaceous upper Edwards The cottonwood creek USA

China

India Indonesia Argentina Germany

Bob slaughter block

Chihuido de la sierra negra Bramberge

sandstone


212

218

217

227

228

230

234

Review on Surfactant Flooding - American Chemical Society

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