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The research presented in this work is to identify high performance surfactant formulations for chemical enhanced oil recovery of a crude oil from a Kansas reservoir and provides guidance for its future field application. Phase behavior experiments are conducted to select optimal surfactant formulation and core floods are conducted to validate their oil recovery efficiency. This research focuses on phase behavior design methodology and core flood design strategy. In this chapter, research motivation and rationality are discussed in following sections.
Currently, waterflood as a conventional oil recovery means leaves more than half of the original oil in sandstone reservoirs, and even more in carbonate reservoirs. In order to recover the residual oil, interfacial tension needs to be reduced substantially to increase the capillary number to about ten thousand fold the capillary number of waterflood. Surfactants could solubilize water and oil in a microemulsion phase, which could reduce interfacial tension between microemulsion and water/oil to ultralow. Other chemicals such as co-surfactant, co-solvent, alkali, and electrolyte are usually blended with primary surfactant to produce clear, fluid, and stable surfactant formulation that has the highest solubilization ratio of water/oil, i.e. the lowest interfacial tension. In order to select the best surfactant formulation, a three stage method, developed by Levitt (2006), Jackson (2006) and Flaaten (2007) at the University of Texas at Austin, are adopted in my research. The first stage selects a list of surfactants based upon data and knowledge of surfactant structure and the target reservoir and crude oil properties. The second stage screens the surfactant formulation with crude oil in phase behavior experiments, which evaluates phase behavior performance through solubilization ratio (which is inversely proportional to interfacial tension), microemulsion viscosity, equilibration time, aqueous phase stability limit and optimal salinity among other characteristics. The third stage tests the optimal surfactant formulation in laboratory core flood experiments.
This research evaluates a crude oil in a limestone reservoir located in western Kansas. The reservoir has been water flooded for the last fifteen years and currently is at a stage of water flood with low oil cut. The formation brine is high salinity brine with moderate hardness. In order to select the right surfactant formulation, some commercially available and promising surfactants are selected based on studies of Levitt (2006), Jackson (2006) and Flaaten (2007) and tested with the crude oil firstly; then they are compared to and optimized with some other newly developed surfactants from other companies. After optimal surfactant formulation passes all criteria, core floods are then conducted to validate the oil recovery efficiency. In order to understand the chemical flood process well, soft brine with equivalent salinity to surfactant slug instead of high salinity hard formation brine is used to saturate and waterflood the core in the initial core flood experiments. Also, because chemical flooding in sandstone core is much more extensively studied than in limestone, sandstone is used for core flooding at first. After core floods in sandstone validate the high oil recovery efficiency of the surfactant formulation, formation brine and limestone are then used in subsequent experiments to evaluate formulation performance close to actual reservoir conditions.
Summary of Chapters
Chapter 2 discusses background and literature information, chemical component structure and principles of chemical mixture and core flood design for EOR applications. Chapter 3 provides an experimental description of the phase behavior and core flood experiments, and describes the equipment, methodology and data calculations used in the research. Chapter 4 summarizes phase behavior screening results and the optimal formulation design process. Chapter 5 presents results of different core flood designs for a crude oil and analysis of core flood pressure data and effluent properties. Chapter 6 presents a summary and conclusion of all experimental results and proposes future work and direction for further research.
Chapter 2: Literature Review
This chapter provides background and a literature review on the theory and methodology used in this research. It describes phase behavior screening experiments, including microemulsion characterization and its mechanism to mobilize oil, and the roles and effects of chemicals in phase behavior experiments. It then reviews the basic principles of core flood design and introduces the crude oil evaluated in this research.
Phase Behavior Screening
Bourrel and Schechlter (1988) define microemulsion phase as a thermodynamically stable phase under certain conditions and in theory it never separates into two phases unless conditions change. Microemulsion is different from "macroemulsion", which is thermodynamically unstable even though it may be kinetically stable. However, before Bourrel and Schechlter defined microemulsion, Winsor (1954) described the phase behavior for the mixture of an oil/water/surfactant system. He identified the three types of phase equilibria in microemulsion phase behavior as Type I, Type II and Type III. Type I microemulsion is an oil in water microemulsion with excess brine phase, also referred as Type II (-) because the phase diagram has a negative slope. Type II microemulsion is water in oil microemulsion with excess oil phase, also referred as Type II (+) as the phase diagram has positive slope. A Type III microemulsion phase exists as a distinct and bicontinuous third phase with excess oil and water phases. Type III is a transitional phase between Type I and Type II. The transition of phase behavior from Type I to Type III to Type II depends on surfactant type, electrolyte, temperature, oil properties etc. The surfactant structure could be characterized with hydrophilic-lipophilic balance (HLB), and the oil properties could be characterized by equivalent alkane carbon number (EACN), which could help to categorize the surfactants and select the right surfactants for target reservoirs and crude oils. The most common phase behavior transition from Type I->Type III->Type II is accomplished by changing electrolytes.
Micro-emulsion and Interfacial Tension
Microemulsion can be characterized in several ways: the amount of water/oil solubilized in microemulsion, the time for microemulsion to coalesce, or microemulsion viscosity. Healy and Reed (1976) define water/oil solubilization ratio by dividing the amount of water/oil solubilized in microemulsion by total surfactant volume (Vw/Vs, Vo/Vs). Water solubilization ratio decreases as salinity increases while oil solubilization ratio increases as salinity increases. The intersection where the water/oil solubilization ratio curves meet corresponds to optimal salinity and optimal solubilization ratio, where water/oil is solubilized the same amount and to the greatest degree for both the water and oil in the microemulsion phase, i.e. lowest interfacial tension between oil/water and microemulsion. Healy and Reed also suggest a correlation between water/oil solubilization ratio and interfacial tension (IFT), which was theoretically derived by Chun Huh (1979). Chen Huh's equation shows that IFT is inversely proportional to the square of the water/oil solubilization ratio:
where C is approximately 0.3 dynes/cm for most crude oils. Because it is difficult and time consuming to measure the IFT between water/oil and microemulsion, by using this equation one could quickly screen out the surfactants giving low solubilization ratios. Surfactants forming complex phases, such as a liquid crystal phase and a gel phase, usually have lengthy equilibration time. It takes a very long time to obtain stabilized solubilization ratio for these surfactants and they usually have problems in propagating in the core or reservoir, and therefore they are also screened out.
Chemical Flood Oil Mobilization Mechanism
Residual oil in the reservoir is trapped by capillary forces and could be mobilized by increasing viscous forces and/or gravitational forces over capillary forces. The dimensionless terms referred to as capillary number Nc and Bond number NB are the ratios of viscous forces to capillary forces and gravitational forces to capillary forces:
Pope et al. (2000) defines trapping number which is the combination of both capillary number and Bond number to characterize the mechanism to recover residual oil. Because we can do little to increase rock permeability (k), reducing interfacial tension is an effective way to increase capillary number under a normal pressure gradient (sÎ¦). Chemical flooding with surfactants could reduce interfacial tension to as low as 10-4 dyne/cm, which usually could increase capillary number low enough to mobilize residual oil the surfactant contacts.
In order to mobilize the residual oil, capillary number usually needs to be increased by a factor of 100-1000 times above typical water flood (Abrams, 1975). Delshad et al. (1986) show capillary number needs to increase to be on the order of 10-5 before residual oil saturation will decrease and to be on the order of 10-3 to reduce residual oil saturation to near zero for sandstone. Kamath (2001) shows that due to different pore structures and wettability, a lower capillary number, on the order of 10-7 is required to start mobilizing residual oil, but requires a higher capillary number to reduce residual oil to near zero in carbonate than sandstone. Therefore, in a laboratory core flood scale, residual oil after water flood in carbonate is usually lower and tends to be more difficult to recover all residual oil than in sandstone.
A typical surfactant formulation as an aqueous phase to form a microemulsion phase with an oil phase usually contains primary surfactant, co-surfactant, co-solvent, alkali, polymers and electrolytes. The primary surfactant is the chemical mainly responsible for solubilizing oil in the microemulsion phase. The co-surfactant is used to improve the performance of primary surfactant (Nelson et al. 1984). The co-solvent is added to the surfactant formulation to reduce equilibration time and to prevent forming of the gel or crystal phases Another important role of co-solvent is to make surfactant formulation compatible with polymers (Pope et al. 1982) and to maintain surfactant slug as a stable one phase at reservoir conditions. Alkali could react with naphthenic components in crude oil and generate in-situ soap to improve the solubilizing of oil in the microemulsion phase. It could also accelerate microemulsion coalescence and reduce surfactant adsorption (Jackson 2006). Polymer is added to surfactant slug to increase its viscosity and maintain mobility control when displacing oil in reservoir. Electrolytes are adjusted to achieve optimal Type III phase to maximally reduce interfacial tension (increase capillary number) and therefore achieve high oil recovery.
Surfactants are the key components in surfactant formulation used to solubilize oil and water in the microemulsion phase and hence reduce interfacial tension between the microemulsion and the oil/water phase. Surfactants generally contain a hydrophilic head, a hydrophobic tail and possible intermediate neutral groups. The structures of surfactant head and tail could be tailored for each specific crude oil for the highest oil recovery efficiency and are discussed in the following paragraphs. Surfactants can be classified into anionic surfactants, cationic surfactants, nonionic surfactants and amphoteric surfactants according to charge of their hydrophilic head groups.Â Anionic and nonionic surfactants are more commonly used EOR surfactants than others, therefore they are described in following paragraphs.
Anionic surfactantsÂ give rise to a negatively charged surfactant ion (hence anionic) and a positively charged counterion upon dissolution in water. They are the most commonly used and most promising surfactants in chemical EOR because of their excellent performance and low adsorption in rocks. Sandstone particles usually carry a net negative charge at reservoir conditions, which could prevent attracting anionic surfactants (Zhang and Hirasaki, 2004). The surface charges on carbonate rock particles are dependent on brine composition and pH (Churcher et al. 1991). Nevertheless, anionic surfactant adsorption could be reduced by increasing pH to above 8.5 to change the surface charge to negative. Examples of common anionic surfactants in recent advances of chemical EOR are alkylbenzene sulfonates (ABS), alcohol ethoxy sulfates (AES), alcohol propoxy sulfates (APS), internal olefin sulfonates (IOS) and Guerbet alkoxy sulfates (GAS).
ABS surfactants are conventional surfactants that were extensively used in the past. Their advantages are a high solubilization ratio of crude oil and low optimal salinity due to strong hydrophobicity from the benzene aromatic ring and alkyl chain. Their aqueous solubility, however, is low and they tolerate only low hardness (Jackson, 2006). Therefore, they can only be injected into the formation with fresh water or low salinity brine, or used as a co-surfactant to increase the hydrophobicity with a co-solvent to improve its solubility. IOS surfactants have proved to be excellent EOR surfactants (Levitt, 2006; Jackson, 2008; Flatten, 2008), particularly as co-surfactants that improve the compatibility between the primary surfactant and the aqueous phase through its structural heterogeneities of branched large carbon chains. AES/APS are sulfates containing ethylene oxide (EO) or propylene oxide (PO) groups. EO and PO groups are intermediate function groups that attach to the carbon chain and have opposite effects. For example, increasing EO groups will increase surfactant aqueous solubility, calcium tolerance and optimal salinity while increasing PO groups has the reverse effect. The number of EO/PO groups determines the hydrophilicity and hydrophobicity of surfactants and they can be tailored specifically for different crude oils. This flexibility of surfactants widens the range of their application in chemical EOR. GAS surfactants are anionic surfactants, which can be manufactured in a relatively inexpensive way that are produced by addition of ethylene oxide and/or propylene oxide to the blend of Guerbet alcohol and monomer alcohol rather than pure Guerbet alcohol. With very large hydrophobes and branched structures to obtain ultra-low interfacial tensions and low micro-emulsion viscosities (Liu et al. 2007), GAS can be used for crude oils with equivalent alkane carbon number higher than 12. The hydrolysis of GAS surfactants can be largely reduced at certain alkalinity range at high temperatures, which could enhance surfactant stability, and therefore make GAS surfactants able to be used in high temperature reservoirs (Adkins, et al. 2010).
Nonionic surfactants do not ionize in aqueous solution because their hydrophilic group is of a non-dissociable type, such as alcohol, phenol, ether, ester or amide. The advantages of nonionic surfactantsÂ are that they are usually easily blended with other types of surfactants and are relatively insensitive to the salinity of the solution. A large proportion of these nonionic surfactants are alcohol ethoxylates, which are made by the polycondensation of ethylene oxide. Alcohol ethoxylates could be used as co-solvents that could replace conventional solvents in greatly diminished amounts (Sahni et al., 2010). Nonionic surfactants, such as alcohol ethoxylates, however, usually have high optimal salinity and their usage is limited due to relatively low cloud point, i.e., aqueous solubility (Milton, 2004).
Co-solvents are generally used in surfactant formulation to increase the compatibility between surfactants and the aqueous phase, and therefore increase its thermal stability. Achieving a clear and stable surfactant slug is important to ensure the injected solution will transport in the reservoir over long distances with low retention (Sahni et al., 2010). Co-solvent also helps to reduce or eliminate the viscous phase and accelerate microemulsion equilibration (Sanz and Pope, 1995). Co-solvents are usually amphiles and have the ability to partition into aqueous phases, and oleic and microemulsion phases, which allows co-solvents to change phase behavior (Dwarakanath et al., 2008). For example, hydrophilic co-solvent increases optimal salinity and lipophilic co-solvent reduces optimal salinity while both increase aqueous stability. Alcohols are one of the widely used conventional solvents. Branched structure alcohols incline to provide better hydrophilicity than linear structure alcohols for the same molecular weight (Hsieh and Shah, 1977). Common alcohols used in EOR include iso-propanol (IPA), iso-butanol (IBA), sec-butonal (SBA) and so on. Glycol ether alcohols are promising co-solvents because of their excellent ability to make surfactants compatible with the aqueous phase at high salinity (Sahni et al. 2010) and their higher flash point.
The disadvantage of using co-solvents is that it reduces the solubilization ratio of water/oil and consequently increases interfacial tension (Salter, 1977), and it also certainly increases chemical cost. It is possible to achieve high oil recovery with alcohol free surfactant formulation (Sanz and Pope, 1995). Alcohol can also be replaced by other chemicals, for example alcohol ethoxylates, which can give better aqueous stability and higher optimum salinity at low concentrations. For active oil, which contains sufficient naphthenic acid to produce soap with alkali, a hydrophilic surfactant is sufficiently soluble in brine at optimal salinity without the need for any co-solvent or only a small amount of co-solvent. For inactive oil, surfactants with large hydrophobes are often needed to achieve a high oil solubilization ratio and low IFT. These surfactants are less soluble in brine, and hence they need a relatively large amount of co-solvents to obtain aqueously stable surfactant slug. In sum, alcohol concentration needs to be determined in such a way to balance the microemulsion viscosity, equilibration time and the solubilization ratio for maximum formulation performance and highest oil recovery.
Alkali has been observed to improve surfactant phase behavior and oil recovery in core flood experiments (Nelson et al., 1984; Wellington and Richardson, 1997). The mechanisms behind this are:
(1) Alkali reacts with naphthenic acids in crude oil in-situ and produces natural surfactant. Natural surfactant usually is not enough to reduce interfacial tension and needs to work together with synthetic surfactant in chemical flood. Also, natural surfactant has relatively low optimal salinity (alkali concentration) and synthetic surfactant could be added to raise optimal salinity to adjust surfactant formulation to the appropriate alkali concentration needed to propagate in the reservoir (Nelson et al., 1984). In phase behavior experiments, the natural surfactant from saponification naphthenic acid increases optimal solubilization ratio with even mildly or weakly reactive crude oils. Conventionally the total acid number, which is the amount of potassium hydroxide in milligrams that is needed to neutralize the acids in one gram of oil, is a good indicator of naphthenic acids that can be saponified. Saponification number, however, should be measured to determine the total amount of soap that could be generated by an alkali reaction (Yang et al., 2010). Heave oil tends to have higher total acid number than light oil and can benefit more from alkali.
(2) Elevating pH by adding alkali could reduce surfactant adsorption by increasing negative charges on sandstone rock (Nelson et al., 1984; Wessen and Harwell 2000; Zhang and Somasundaran, 2006). Low surfactant adsorption promotes surfactant slug propagation (Nelson and Pope, 1977) and enables low surfactant concentration chemical flooding.
Alkali in surfactant formulation also improves the coalescence time of microemulsion in phase behavior experiments (Castor, 1981), which indicates low viscosity of the microemulsion phase (Nelson et al., 1984) and facilitates rapidly mobilizing oil and development of the oil bank in-situ. The reduction of microemulsion phase viscosity and consequent improvement of fluidity can reduce the amount of alcohol needed.
Sodium carbonate is a conventional alkali in chemical flood. In the presence of gypsum or anhydrite, which is often the case with dolomite rocks, however, carbonate ions and calcium ions precipitate as calcium carbonate (Labrid, 1991). Sodium metaborate is an alternative alkali that prevents precipitation of calcium carbonate by forming soluble complexes with dissolved calcium ions and borate ions (Flaaten et al., 2006).Tetrasodium ethylenrdiamine tetraacetate (EDTA-4Na+) is another promising alkali which acts as a chelating agent to sequester metal ions such as calcium and magnesium ions with its two amines and four carboxylates (Yang et al., 2010).
Polymer is mainly used to increase the viscosity of surfactant slug and to therefore provide enough mobility for stable displacement of the oil bank by surfactant slug in chemical flooding (Sorbie, 1991; Willhite and Green, 1998). Increasing the viscosity of the surfactant slug increases sweep efficiency by reducing or eliminating fingering, particularly in heterogeneous reservoirs. Polymer is often needed in both surfactant slug and polymer drive, which protects the integrity of surfactant slug. The viscosity of slug/drive (depends on amount/molecular weight of polymer) of stable displacement is determined in such a way that mobility ratio is maintained to be less than one (Gogarty et al., 1968).
Partially hydrolyzed polyacrylamides (HPAMs) are conventional polymers which are susceptible to degradation by shearing as well as thermal degradation. The effects on stability of HPAM by various factors such as temperature, initial degree of hydrolysis, amount of divalent cations, pH, and dissolved oxygen are examined by Shupe (1981) and Moradi-Araghi (1987).
Xanthan gum, a bacterial polysaccharide, has a rigid structure, which yields significant resistance to shear degradation compared to HPAMs. It has the advantage of being insensitive to salinity and divalent cations due to its rigid structure and lack of an anionic group. It, however, is susceptible to bacterial degradation. Although xanthan gum was broadly used in early chemical floods, HPAMs are more commonly used in recent chemical floods.
Core Flood Design
Laboratory core floods are efficient ways to validate the performance of surfactant formulation that shows good phase behavior results before field application. Residual oil trapped in the core after water flooding is the target of chemical flooding. The highest capillary number corresponds to the lowest IFT for both oil-microemulsion and water-emulsion phases, which is achieved at the optimal salinity of surfactant formulation. Therefore, surfactant slug with optimal salinity is usually injected into the core. Surfactant slug with over optimal salinity drives surfactant into the oil phase causing surfactant loss and leaves oil trapped again even though the oil is mobilized by microemulsion due to low oil-microemulsion IFT. Surfactant slug with under optimal salinity still has relatively high oil-microemulsion IFT and therefore cannot mobilize oil. For coreflooding, the brine salinity in the core could be well controlled to achieve optimal salinity in order to broaden the surfactant Type III region with low IFT. In the field, however, reservoir salinity usually is not optimal salinity, and it is difficult to achieve optimal salinity everywhere because of (1) surfactant slug dispersion with reservoir brine; and (2) optimal salinity is a function of changing surfactant concentration. Pre-flush of optimal salinity brine is frequently un-necessary, and even detrimental to oil recovery (Pope et al., 1979). A robust chemical flood design which uses a salinity gradient is proposed by Pope et al. (1979), where the salinity downstream of the slug is higher than optimal salinity, at the slug is equal to optimal salinity and upstream of the slug is lower than optimal salinity. This salinity gradient design greatly increases the chances of surfactant slug passing by optimal salinity and promoting low IFT at least somewhere in the mixing zone. Over optimal salinity downstream also helps mobilize oil and under-optimal salinity upstream helps prevent surfactant or mobilized-oil from being trapped.
Crude Oil Evaluated
The crude oil used in this study is Wahrman crude oil, from a limestone reservoir located in the northwest part of Kansas. Reservoir temperature is about 43.3 Â°C (110 Â°F). It has low viscosity, 7.5 cP (filtered) at reservoir temperature and is light (API gravity: 37.9 at reservoir temperature). It has low acid number, about 0.014 g KOH/g; therefore there is little naphthenic acid in Wahrman crude oil to produce natural surfactants with reaction of sodium carbonate. The formation brine contains 12 wt% TDS including 2500ppm divalent ions.