Microemulsions have recently made advances in enhanced oil recovery process in which chemicals especially surfactants are used to recover the oil from natural oil reservoirs. This technique relies on the knowledge of interfacial properties among oil, water and solid rock reservoirs in occasional presence of natural gas under extreme conditions. Surfactant-based chemical systems have been reported in many academic studies and its technological implementation is a potential candidate in EOR activities. For instance, it was determined that a mobilized buffer (polymer) with viscosity either equal to or greater than the mobilized oil enhanced the recovery efficiency considerably. However, EOR based on chemicals like alkaline-surfactant-polymer (ASP), is a complex technology requiring high level of expertise for its industrial implementation. The surfactant-polymer interaction is a rapidly growing research area for efficient oil recovery by improving slug integrity, adsorption and mobility control. This review article evaluates the injecting fluid system to highlight some recent advances in the use of chemicals in EOR, especially with microemulsions. It further reveals the current status and future outlook for EOR technology in oil fields and describes the opportunities for strategic utilities and load growth in petroleum industry.
Keywords: Enhanced oil recovery; microemulsions; interfacial properties; alkaline-surfactant-polymer; mobility control, load growth
Introduction
Exploration of oil reservoirs and their exploitation is a rigorous activity in petroleum industry. Enhanced oil recovery (EOR) is carried out by applying some extrinsic energy on the pool; for instance pressuring, cycling, or injecting some substance into the pool, are the artificial means that are used to extract oil from the oil reservoirs. These artificial means used for primary oil recovery contemplate further for secondary or tertiary oil recovery programs. Primary oil recovery programs do not support the idea of using some mechanical, chemical, thermal or explosive materials for lifting up fluids from the well or stimulating the nearby fluid reservoir [1]. This is done by secondary or tertiary oil recovery programs. EOR projects are accomplished by using miscible or immiscible mixtures, chemical or thermal process and sometimes biological operation in order to displace the oil underneath the earth. The intrinsic or natural capacity of oil-fields for producing oil is, however, promoted via primary recovery techniques. But physical constraints such as reduced well pressure and extensive oil trapping lessen oil production and eventually it ceases at one stage. Infect original balance perturbs during the recovery process, it changes the composition of crude oil affecting the reservoir
wettability [2]. At this point, economical aspects are observed and fulfilled by implementing secondary and tertiary EOR methods especially in the locations of heavy or mature oilfields [3]. EOR has potential to increase oil yield extracted from mature filed significantly. If there is merely 1% increase in oil recovery from the existing reservoirs in the world, it would help deliver 20-30 barrels of additional oil. Experts estimate that chemical EOR method alone can potentially recover 750 barrel oil. Chilingar and Yen [4] thoroughly investigated several reservoir cores (i.e. limestone, dolomitic limestone, calcitic dolomite and dolomite) and concluded that 15% of them were strongly oil-wet, 65% were just oil-wet, 12% had moderate oil wettability and 8% cores were water-wet. Bearing in mind that majority of petroleum reserves currently detected, are accommodated in carbonate matrices [5], modification in wettability of these reservoirs is an important issue when further oil recovery is desired.
EOR methods are devised with purpose of overcoming the capillary forces responsible for retention of high amount of the residual oil in underground reservoirs. These capillary forces are normally quantified by the Young-Laplace equations in Interfacial Sciences [6]. In fact, capillary pressure (Pc) is rather useful parameter when classifying a rock sample as an either oil- or water-wet. Equation 1 gives the value of Pc in terms of the local interfacial tension, γ, and the curvature of the interface (C), that is determined by the pore radius (R), and the contact angle (θ).
Furthermore, surface wettability is intrinsically related to contact angle particularly in the oil reservoirs where often water, oil and gas phases are in contact. The spreading coefficient σSLG can be defined (equation 2) in terms of the interfacial tensions developed between each pair of contacting phases: solid-gas (γSG), solid-liquid (γSL) and liquid-gas (γLG) interfaces. It is used to describe the wetting properties of a rock matrix.
The spreading coefficient (γSG) is rather difficult to be measured directly. However, it can be measured directly (equation 3) when equilibrium is established at the contact point of all three phases (i.e. a finite contact angle θ between the two fluids and the rock).
The equilibrium pressure thus established can be altered by injecting appropriate fluids during the prospection of oil wells. The composition of such fluids depends on the mixtures of liquids and solids taken in various ratios according to their specific application. After choosing appropriate and effective fluid, the parameters such as pressure, temperature, chemical factors, economical factors and contamination levels are determined. It was, for example, determined that if the viscosity of injected fluid is lower than that of the fluid to be displaced under rock, the injected mixture of fluids flows more swiftly than the original fluid across the porous medium while finding preferred paths.
Phases of Oil Production:
Oil recovery process consists of three recovery phases: primary, secondary and, tertiary recovery [7]. In primary oil recovery phase, oil is driven out the well bore by the natural pressure of the reservoir and gravity. The natural movement of the oil is enhanced with artificial lift techniques such as pumps. Its oil extraction range is from 10 to 20% of the oil available in the field. Secondary recovery phase employees water known as water flooding technique to recover the oil from the field. In this technique the injected water or steam displaces the oil and sends it to well bore. An additional 10-30% recovery of oil from the available oil-field is made possible by secondary recovery phase. Tertiary oil recovery or enhanced oil recovery phase utilizes several additional methods that are sometimes expensive and unpredictable. Despite that their proper application can enhance oil recovery up to 30-60% of a total oil field.
In a typical oil field, conventional production methods extract, on average, about 1/3 of the total available oil. The rest of the oil remains under the earth and it is difficult to extract it because of high demand of cost and technology. Drilling oil well is not like tapping into a vast underground lake. Instead, oil is found within a variety of complex geological rock structures. As oil reserves decline, it becomes more and more difficult to extract the remaining oil and bring it on the surface.
EOR Techniques
Enhanced Oil Recovery also known as "tertiary oil recovery" is a set of methods that involves various injecting materials to extract oil from its reservoirs. EOR is rapidly growing technique in petroleum industry as far as its efficiency in oil growth is concerned. Many oil exploration and drilling companies are using EOR techniques to maximize the potential of both old and new oil fields. Figure 1 shows selective EOR methods normally used in petroleum exploitation activities.
Space for figure 1
Secondary methods cause perturbation of the unproductive reservoir via some physical modification (i.e. water, gas or steam flooding) that results in low final oil recovery. In particular, methods involving miscible gas and thermal energy can be useful to change viscosity and thereby mobility of oil trapped in rocks. This is due to interfacial effect mutually caused by capillary and viscous forces. As a result, more oil can be driven out of the pores. Thermal recovery method employs heat to improve oil flow rates [8] and steam is injected into the reservoir to lower the viscosity of heavy viscous oil, that allows the oil to flow easily through pores and thereafter it is extracted conveniently. Dolberry Oil and Gas Inc estimate that 52% steam, 31% CO2 and 17% N2 is employed in EOR techniques. The most popular and growing EOR technique is gas injection [1,9]; that is consistently successful technique for increasing oil production in various types of oil reservoirs. The ultimate goal of gas injection is to restore reservoir pressure, increase oil production, and lower operating costs. Nevertheless, high cost of gas-equipments and their accessories is a reason why small independent oil companies cannot execute gas injecting EOR.
A chemical EOR technique uses novel surfactant molecules and polymers as injecting material into the oil reservoirs. This surfactant-based EOR could provide solution to the global energy crisis by significantly increasing oil recovery rates [10]. In general, the positive effect of lowered interfacial tension (IFT) on the ultimate recovery is because of adding surfactant (i.e. heavy oil); whereas, adding surfactant (i.e. light oil) shows negative effect of lowered IFT on the recovery rate. Each reservoir has different characteristics in terms of temperature, permeability, porosity, crude oil type, and water composition; therefore, the surfactant has to be matched closely to the specific conditions in order to achieve the desired chemical interaction. Once mobilized, the oil is able to flow out of the reservoir analogous to soil shifting from clothing and its removal along with wastewater by conventional laundry detergents.
Chemical flooding involves the injection of a surfactant solution which causes the oil-aqueous interfacial tension to drop from ca.30mN m-1 to zero by the order of 10-3-10-4mN m-1. This decrease in interfacial tension allows spontaneous emulsification and displacement of the oil [11,12]. A small chemical slug (i.e. 5-40% pore volumes) is injected into oil reservoir during the process. This slug is displaced through the reservoir by a polymer bank, which in turn is displaced by drive water.
Role of Capillary and Viscous Forces on Oil Recovery
Under ordinary flooding conditions (water or immiscible fluid), surface forces (capillary forces) dominate the macroscopic displacement process and are responsible for trapping a large portion of the oil within the pore structure of the reservoir rocks. Capillary forces arise from the interfacial tension (IFT) between the oil and water phases that resist applied viscous forces externally and cause the injected water to bypass the resident oil. The microscopic distribution of the trapped oil depends upon the hydrostatic equilibrium condition and is a function of factors such as wettability of the rock and pressure in the fluid phases. However, the viscous forces dominate the macroscopic displacement process if the flood rate is made sufficiently high, [13]. The predominant mechanism to recover this oil is lowering the IFT through the addition of suitable chemicals (surfactants). Lower interfacial forces recover additional oil by reducing these capillary forces. This trapping of the resident oil can be expressed as a competition between viscous forces mobilizing the oil, and capillary forces trapping the oil.
In order to determine whether viscous or capillary forces are dominating the displacement process, it is convenient to consider the dependence of the displacement efficiency on a suitable dimensionless parameter known as capillary number (Nca) defined in equation 4:
Where μw and Uw are the aqueous phase viscosity and flow rate per unit cross sectional area, whereas γow is the interfacial tension between oil and water and φ is the porosity of the reservoir rock structure [14]. Physically, the capillary number represents the ratio of viscous to capillary forces. The capillary number for an ordinary waterflooding process is in the order of 10-6 [14].
Evaluation of the Chemical Methods in EOR Activities
As far as surface properties are concerned, oil extraction activities are greatly optimized by EOR methods that employ some applicable chemical technique, especially after secondary methods have failed to improve reservoir productivity. Some of these techniques are cited in Figure 1, with particular emphasis on ASP methods (Alkaline- Surfactant-Polymer). The lowering of water-oil interfacial tension is the main driving force that enables the use of such methods. Changes in fluid viscosities upon addition of chemicals like polymer mixtures are observed and present some advantages. In conventional oil recovery activities via water flooding, normally low yields are observed. This is because of high oil viscosity and development of strong interfacial tensions when water is injected besides geological aspects involved in the oil extracting process. Phase behavior of brine-oil-surfactant formulation, is one of the key factors determining the enhanced oil recovery by surfactant flooding. Therefore, operations based on either surfactant or polymer or their combination, adsorption phenomena can be potentially advantageous mainly because of the interesting physicochemical properties of micellar solutions, emulsions, fracturing fluids and particularly microemulsions.
The surfactant and polymer flooding has become effective and competitive process to improve oil recovery under the current circumstances of high oil prices. Thus oil companies are considering the process more seriously to rejuvenate their mature fields [15]. The special ability of surfactant molecules to adsorb onto surfaces and modify their properties, and its further interaction with polymers and other chemical species, require assessing many physical parameters. Apart from that heterogeneous geological nature of the oil reservoir must always be considered while selecting a suitable chemical system in oil recovery. Different surfactant or polymer molecules or the appropriate combination of two, can serve this purpose in the best way recovering maximum oil yield. Compatibility among the different tested species in terms of chain length, hydrophilic-lipophilic balance (HLB) and chemical nature for example, is one aspect to devise a chemical recovery system [5,16,17]. Furthermore, very extreme conditions established by varying pH, temperature, pressure and composition (salt and inorganic compounds) are encountered in the reservoirs; thus, novel surfactants in EOR activities must support such conditions and interact favorably with other chemicals.
Biodegradability during oil recovery process, is also desirable as in alkylpolyglucosides and pyrolidones [18,19]. Scattering techniques, surface tension measurements and particularly calorimetric experiments can be successfully carried out giving valuable properties about interaction between surfactants and polymers when mixed together under specific conditions in EOR technique [20]. The readers are encouraged to consult some reports by Loh and co-workers for further explanation on such techniques and analyses of some experimental results with chemicals that can have potential applications in EOR [21-25].
Enhanced Oil Recovery by Means of Microemulsions
Microemulsions are also potential candidates in enhanced oil recovery, especially because of the ultra-low interfacial tension values attained between the contacting oil and water microphases that compose them. Microemulsion flooding can be applied over a wide range of reservoir conditions [26]. The use of microemulsions for oil recovery is not a recent development in petroleum technology. In 1959 Holm and Bernard [27] filed for a patent in which the surfactant dissolved in low-viscosity hydrocarbon solvent was proposed. Another patent was filed by Gogarty and Olson [28] in 1962 that described the use of microemulsions in a new miscible-type recovery process known as Maraflood®. Similarly the first microemulsion-assisted EOR injection was tried in 1963 by Marathon Oil Company. In the late 1960s, more patents were issued to Jones, Cooke and Holm involving microemu1sions for improved oil recovery [29]. Gogarty reviewed the status and current appraisal of the microemulsion flooding process [30]. Later, in early 1970s, Healy and Reed reported on some fundamentals of microemulsion flooding, especially viscosity, interfacial tension and salinity, relating the results of phase behavior of self-assembled systems to the Winsor's concepts [31-33].
For a given chemical system, any of these phase behaviors will generally be observed when salt or alcohol compositions are varied. The effect of pressure and temperature on phase behavior of such systems has a similar effect [34-39]. Hence, precise phase knowledge and its modeling are essential for engineering purposes. This is, nevertheless, a difficult task because the number and nature of the equilibrium phases are very sensitive to the overall composition, temperature, and pressure. Rossen et al. [40] and Kilpatrick et al. [41] have shown that this complex behavior could be modeled as conventional liquid-liquid equilibrium by using a simple expression of the excess Gibbs energy derived from the Flory theory. But these authors did not compare their simulations with experimental data. Negahban et al [42] modeled quantitatively the phase equilibrium of some simple ternary systems exhibiting a phase behavior of the same type using the UNIQUAC activity coefficient model. Garcia-Sanchez et al. [43] gave a thermodynamic analytical representation of the phase diagram of microemulsion systems similar to those used in enhanced oil recovery. The methods for the estimation of "excess Gibbs energy model's interaction parameters" were successfully assessed for the representation of experimental multiphase liquid equilibrium data of an oil-brine-surfactant-alcohol model system. In addition, for effective representation of phase diagram of this system, an empirical expression was introduced in the selected excess Gibbs energy model to account for the specific role of the surfactant in these complex systems. The British Petroleum (BP) Oil Company devised a method whereby co-injection of a low-concentration mixture of surfactant and biopolymer affected; and denominated Low-Tension Polymer Flood (LTPF). Austad et al. [44,45] discussed on the physicochemical aspects involved in this method, particularly the interactions existing within specific polymer-surfactant and microemulsion systems applied in EOR.
Austad and co-workers [5, 46-51] during 1990s studied about chemical flooding of oil reservoirs with detailed reports on positive and negative effects of chemicals in oil recovery. In these reports, Austad and co-workers compared cationic, anionic and nonionic surfactants, showing that cationic surfactants were more efficient. Reports also highlighted the important role of spontaneous imbibition whereby capillary forces draw a wetting fluid into a porous medium in EOR surfactant-polymer mixtures. This is contrary to forced imbibition phenomena, which occur mainly due to viscous displacement [52]. The occurrence of imbibition via spontaneous mechanisms is especially interesting in fractured reservoirs. With better reservoir characterization and properly designed chemicals, some pilot tests have been reported successful technically with 50% oil recovery at initial flooding and thereafter recovering two-thirds of the residual oil [53,54]. Further information about both oil recovery from reservoir by chemical flooding and environmental soil remediation can be found in reference [55].
In microemulsion technique, the oil reservoir is flooded with water containing a small percentage of surfactant and other additives. This solution reacts with natural acids in the trapped oil making a microemulsion similar to soap lather. The surfactant plays a key role to form exact type of microemulsion that breaks down the interfacial tension of target oil, explains Robert Moene from Shell Global Solutions. This is critical to both mobilize oil and enable it escaping from the rock. Generally speaking, wherever a water flood has been successful, microemulsion flooding will be applicable; while, in many cases where water flooding has failed owing to its poor mobility relationships, microemu1sion flooding can still be successful mainly due to required mobility control.
Microemulsions are stable emulsions of hydrocarbons and water in the presence of either surfactants or co-surfactants. They are characterized by spontaneous formation, ultra-low interfacial tension, and thermodynamic stability. The widespread interest in microemulsions and its usage in industrial applications are based mainly on their high solubilization capacity for both hydrophilic and lipophilic compounds, their large interfacial areas, and ultra-low interfacial tensions when they coexist with excess aqueous as well as oil phases. The properties of microemulsions have extensively been reviewed elsewhere [56-62]. The ultra-low interfacial tension property exclusively achieved in microemulsion systems, has many applications in oil recovery and other extraction processes (i.e., soil decontamination and detergency). Microemulsion, for instance, formulated by alkali-surfactant-polymer, is injected into reservoirs in EOR process that lowers interfacial tension to mobilize the residual oil left trapped in the reservoirs after water flooding.
Microemulsions are prepared from the mixture of oil, water or brine, and a surfactant (an amphiphilic molecule). In several cases, the addition of a co-surfactant (alcohol) is required to ensure the stability of the microemulsion. For a given overall composition, oil in water (O/W) microemulsion in equilibrium with oil excess phase (Winsor I); water in oil (W/O) microemulsion in equilibrium with water excess phase (Winsor II); and microemulsion in equilibrium with both water and oil excess phases (Winsor III), are prepared. Middle-phase microemulsions are, nevertheless, often favorable for a surfactant flooding process [63] whose even microscopic amount (fewer mol) remains effective for EOR. Hence it is fundamental to maintain middle microemulsion phase as long as possible during the process in surfactant flooding. The optimum surfactant formulation for a microemulsion system is dependent on many variables such as pH, salinity, temperature etc. Some of the components in a typical formulation are listed in reference [64]. Common surfactants used in EOR, are petroleum sulfonates and ethoxylated alcohol sulfates [65-67].
The tertiary oil recovery by means of microemulsions have been mainly focused firstly, for its ability to dissolve oil and water simultaneously; and secondly, the attainment of very low interfacial tension of the system. Therefore, the design and analysis of chemical flooding processes for EOR depend on calculations of phase equilibria for these systems that are composed of water or brine, oil, surfactant and co-surfactant (usually an alcohol). Consequently, the understanding of phase behavior of these systems is of fundamental importance to the development of any surfactant-based chemical flooding process.
Microemulsion flooding is a miscible type displacement process decreasing capillary forces on oil droplets in the reservoir and thus improving oil recovery. Microemulsion slug is injected into the reservoir that is followed by a polymer solution and water injection for mobility control (Figure 2). Oil and water are displaced ahead of the microemulsion slug resulting stabilized oil-water bank. The displacement mechanism is the same under secondary and tertiary recovery conditions. In the secondary case, water is a primary produced fluid until the oil bank reaches the well.
Space for figure 2
Microemulsions are optically transparent isotropic oil-water spontaneously formed by appropriate combination of emulsifiers. Most of them are composed of hydrocarbons, surfactants, water and other organic liquids (alcohols) and they are generally miscible with the reservoir oil and water. Microemulsions employed in EOR may be either oil external (also called soluble oil) or water external; mostly, they contain crude oil from the reservoir in which they are injected. The design of a microemulsion for a specific reservoir is basically a trial and error procedure; for example, the formulation of the microemulsion slug for a particular reservoir depends upon the reservoir condition after the secondary recovery process and the properties of the microemulsion slug itself.
Besides that mobility control is important for the success of the process. The mobility of the microemulsion is matched to stabilized water-oil bank by controlling the microemulsion viscosity. The mobility buffer (polymer) incorporated by microemulsion slug, prevents rapid slug deterioration from the rear side and thus minimizes the slug size up to the level required for efficient oil displacement. Water external emulsions and aqueous solutions of high molecular weight polymers have been used as mobility buffers. Microemulsion flooding can be applied over a wide range of reservoir conditions. In microemulsion flooding, the slug must be designed for specific reservoir conditions such as temperature, resident water salinity, and crude oil type. If the temperature is very high, a fluid-handling problem may erupt in the field because of the increased vapor pressure of the hydrocarbon in microemulsion.
Microemulsion Salinity Scan Tests
The surfactants are able to solubilize an increasing amount of oil and decreasing amount of water as salinity is increased. The "optimal salinity" determined from phase behavior, is the salinity at which the microemulsion solubilizes equal amounts of oil and water. Salinity scan tests are routinely used to screen phase behavior of surfactant formulations before conducting time-consuming core-flood tests [68,69]. The minimum interfacial tension is correlated with the solubilization parameters at the optimal salinity and eventually the presence of viscous, structured or birefringent phases and stable macroemulsions, is easily monitored. When salinity scan test is conducted at low surfactant concentrations (i.e. 0.05%), the equilibrium phase behavior appears to go from a lower-phase microemulsion to an upper-phase microemulsion over a narrow salinity range [70,71].
6.2 Microemulsion Slug Mobility
The first step in a mobility design procedure is effective mobility control of microemulsion slug. The mobility of a microemulsion is a function of its composition that is controlled according to specific application. The parameters that can be changed to control the mobility of the microemulsion slug, are the amount of water, the electrolyte concentration, the type of hydrocarbon, amount of surfactant and the use of co-surfactants. Care must be taken not to bring a change in mobility control that adversely affects the other properties of the microemulsion and consequently its ability to displace the oil.
6.3 Mobility of Buffer (Polymer) Slug
For an efficient microemulsion flooding, mobility of buffer (polymer) displacing the microemulsion slug is one of the important factors in designing the process. The mobility of the buffer solution must be either equal to or less than the mobility of the microemulsion slug for a stable system [72]. Higher mobility of buffer solution causes the "fingering" of polymer solution into the microemulsion slug. Water thickened by the polymer serves as an effective mobility buffer solution. Many polymers have been reported as effective mobility control agents [73]; whereas, polyacrylamides are the only polymers that have been used as mobility control agents on a large scale. Mobility control with polyacrylamides is achieved by reduction in both viscosity and permeability [74]. Both molecular weight and degree of hydrolysis of the polymer are important characteristics in mobility design control solution [74].
6.4 Economical Aspects of the Process
The cost of buffer solution mobility and microemulsion slug depends upon their respective compositions. The microemulsion slug mobility can be reduced to virtually any value by changing the composition of microemulsion and normally the cost variation entailed in changing the composition of microemulsion, is insignificant. However, a low value of microemulsion slug mobility requires higher concentration of polymer in the buffer solution that ensures adequate mobility control at the buffer-microemulsion slug interface. The cost or economical feasibility is evaluated at the time of process requiring both microemulsion formulations in flooding and oil saturation in reservoir. However the cost of microemulsion can be decreased considerably by developing a new formulation that uses low surfactant and co-surfactant concentration along with crude oil in stead of refined hydrocarbons. Therefore, economic success or failure of microemulsion flooding process depends largely upon the proper choice of a microemulsion slug size. Jones [75] describes a simple technique for estimating "optimum slug" size that is defined in terms of maximum profit generation. It may also be concluded that oil recovery is maximum near the optimal salinity of the system and thus, in high salinity reservoirs, mixed surfactants are promising for EOR. Although this technique is rapid and convenient to determine the optimum slug size for an economically feasible process, yet other factors such as time value make the process sometimes uneconomical.
7. Conclusion
Over the past 30 years, chemical EOR technology using microemuslsions has dramatically been suitable for its greater industrial experience, comprehensive understanding, magnificent modeling, and cost effective chemicals adjusted for inflation. Despite the fact, chemical EOR, especially alkaline-surfactant-polymer (ASP), is a complex technology requiring high level of expertise and experience for its successful execution in the oil fields. Operators can increase both oil recovery and make more profit by using scientific research based technologies; appropriate geological survey and characterization; exact reservoir modeling and engineering designs. Apart from that effective monitoring and control system of the oil filed may increase oil recovery.
A plentiful research area in EOR is attributed to design and implementation of novel chemical methods. Mixtures particularly of surface-active chemical substances incorporate the injection formulations in this technology. This aims at oil displacement that takes place due to attaining ultra-low interfacial tensions and reduced fluid viscosity in the oil reservoirs. Knowledge about interfacial science, physico-chemical properties of chemical systems and geological characteristics of the rock matrices is central subject in order to devise high oil recovery process.
