Lu, Jun (University of Texas At Austin) | Goudarzi, Ali (University of Texas At Austin) | Chen, Peila (University of Texas At Austin) | Kim, Do Hoon (University of Texas At Austin) | Britton, Christopher (University of Texas At Austin) | Delshad, Mojdeh (University of Texas At Austin) | Mohanty, Kishore K. (University of Texas At Austin) | Weerasooriya, Upali Peter | Pope, Gary Arnold
Large volumes of oil remain in naturally fractured carbonate oil reservoirs and water floods are often very inefficient because many of these reservoirs are mixed-wet or oil-wet as well as extremely heterogeneous. Naturally fractured reservoirs are
challenging targets for chemical flooding because they typically have a high permeability contrast between the fractures and the matrix with low to extremely low matrix permeability. In addition, some of the world's largest oil reservoirs are fractured
carbonates with high reservoir temperature and high salinity formation brine and some of them also have low API gravity oils, which also increases the difficulty of recovering the oil. We have developed a stable surfactant that shows promising
results even when all of these conditions are present at the same time. Both static and dynamic imbibition experiments were done using a fractured carbonate core. These results were interpreted using a mechanistic chemical reservoir simulator.
Lu, Jun (University Of Texas At Austin) | Britton, Chris (U. of Texas at Austin) | Solairaj, Sriram (U Of Texas At Austin) | Liyanage, Pathma Jithendra (U Of Texas At Austin) | Kim, Do Hoon (U. of Texas at Austin) | Adkins, Stephanie (U. of Texas at Austin) | Pinnawala Arachchilage, Gayani (U. of Texas at Austin) | Weerasooriya, Upali (U. of Texas at Austin) | Pope, Gary Arnold (U. of Texas at Austin)
A new class of surfactants has been developed and tested for chemical enhanced oil recovery that shows excellent performance under harsh reservoir conditions. These novel Guerbet alkoxy carboxylate surfactants fulfill this need by providing large, branched hydrophobes, flexibility in the number of alkoxylate groups, and stability in both alkaline and non-alkaline environments at temperatures up to at least 120 °C. The new carboxylate surfactants perform better than previously available commercial surfactants, they can be used under harsh reservoir conditions, and they can be manufactured at a lower cost from widely available feedstocks. A formulation containing the combination of a carboxylate surfactant and a sulfonate co-surfactant resulted in a synergistic interaction that has the potential to further reduce the total chemical cost. Both ultra-low interfacial tension with the oils and a clear aqueous solution even under harsh conditions such as high salinity, high hardness and high temperature with or without alkali can be obtained using these new large-hydrophobe alkoxy carboxylate surfactants. Both sandstone and carbonate corefloods were conducted with excellent results. Formulations have been developed for both active oils (contains naturally occurring carboxylic acids) and inactive oils (oils that do not produce soap/carboxylic acid) with excellent results. The new class of surfactants is a major breakthrough that greatly increases the commercial potential of chemical enhanced oil recovery.
Liyanage, Pathma Jithendra (U Of Texas At Austin) | Solairaj, Sriram (U Of Texas At Austin) | Pinnawala Arachchilage, Gayani (U. of Texas at Austin) | Linnemeyer, Harold C. (The University of Texas at Austin) | Kim, Do Hoon (U. of Texas at Austin) | Weerasooriya, Upali (U. of Texas at Austin) | Pope, Gary Arnold (U. of Texas at Austin)
With recent advances in Alkaline-Surfactant-Polymer (ASP) flooding, the demand for high performance EOR surfactants is rapidly increasing. This is accompanied by the need for a diverse raw material base. We have successfully developed and tested a novel class of hydrophobes for anionic surfactants that satisfy this need at low cost. The hydrophobe for these novel surfactants is Tristyrylphenol (TSP), which is based on the petrochemical feed stocks, phenol and styrene. TSP based surfactants have unique structural features that can be exploited to fit many EOR surfactant needs. We illustrate the performance of this class of TSP surfactants for a waxy crude oil with a high acid number. Selecting a formulation proved difficult due to the high molecular weight of the crude. The TSP surfactant has four benzene rings that enhanced the solubility of the heavy components of the crude oil, including asphaltenes, making it an attractive choice. The dead crude oil was diluted with either decalin or cyclohexane to match the equivalent alkane carbon number (EACN) of the live crude oil. The TSP alkoxy sulfate molecules with varying lengths of propoxy (PO) and ethoxy (EO) chains were tested in microemulsion phase behavior experiments in order to obtain ultra-low IFT at optimum salinity with low microemulsion viscosities. The ASP formulation was successfully tested in reservoir core floods using both surrogate oil and live oil.
Walker, Dustin (U. of Texas at Austin) | Britton, Chris (U. of Texas at Austin) | Kim, Do Hoon (U. of Texas at Austin) | Dufour, Sophie (YPF Argentina) | Weerasooriya, Upali (U. of Texas at Austin) | Pope, Gary Arnold (U. of Texas at Austin)
The physical structure of microemulsions and the degree to which ultra-low IFT is achieved is dependent on a number of parameters including the types and concentrations of surfactants, co-solvents and alkali, crude oil composition, brine composition, temperature and to a lesser extent, pressure. Modifying any one of these variables creates a microemulsion with different properties. The rheological properties of the microemulsion must be adjusted appropriately to achieve good performance under practical reservoir conditions. Two microemulsion properties of primary concern are undesirably high viscosity relative to oil viscosity and non-Newtonian behavior. The broader implications of injecting microemulsions with high viscosities or non-Newtonian behavior in the field include high surfactant retention, unsustainably high pressure gradients, reduced sweep efficiency and microemulsions that stagnate in the field due to high viscosity at low shear rates. The most common ways to reduce microemulsion viscosity are to optimize the surfactant formulation with a good co-solvent and/or by adding more branching to the surfactant hydrophobe. Adding co-solvent in appropriate concentrations makes a microemulsion much less viscous. However, co-solvents increase the cost and complexity and also tend to increase the IFT. A less conventional solution involves increasing the temperature of the injection water thereby lowering both the oil and microemulsion viscosity. This approach has been tested successfully in core floods using both surrogate and reservoir cores.
Kulawardana, Erandimala Udamini (U. of Texas at Austin) | Koh, Heesong (U. of Texas at Austin) | Kim, Do Hoon (U Of Texas At Austin) | Liyanage, Pathma Jithendra (U. of Texas at Austin) | Upamali, Karasinghe (U. of Texas at Austin) | Huh, Chun (U. of Texas at Austin) | Weerasooriya, Upali (U. of Texas at Austin) | Pope, Gary Arnold
New polymers that are stable in harsh environments (high salinity/hardness and high temperature) are in high demand because of the need for chemical EOR in oil reservoirs with these conditions. Commonly used partially hydrolyzed polyacrylamides (HPAM) have been successfully used in the field for decades, but they hydrolyze at high temperature and eventually precipitate in the presence of high concentrations of divalent cations. This paper mainly focuses on rheology and transport behavior of scleroglucan (non-ionic polysaccharide) and N-vinylpyrrolidone (NVP)-polyacrylamide (AM) co-polymer. The rigid, rod-like, triple helical structure of scleroglucan imparts exceptional stability and its non-ionic functionality makes it insensitivity to salinity and hardness. By a different mechanism, NVP in modified HPAM protects the polymer's amide group against thermal hydrolysis, i.e., by sterically hindering the amide group. This allows maintaining high viscosity even in high salinity brines at high temperature. Both scleroglucan and NVP co- or ter-polymers show good filterability and transport properties in sandstone and carbonate cores at high temperature and in brine with high salinity and hardness. Therefore, both polymers are promising candidates for polymer flooding, surfactant-polymer flooding and alkali-surfactant-polymer flooding in hard brine at high temperature, but must be evaluated under specific reservoir conditions.
Introduction and Background
A wide variety of polymers have been evaluated for their possible EOR application under high temperature and high salinity conditions (Askinsat, 1980). Incorporating monomer groups that are much resistant to hydrolysis, 2-Acrylamido-2-methylpropane sulfonic acid (AMPS), poly-vinylpyrrolidones (PVP), or N-vinylpyrrolidones (NVP), (Doe et al., 1987; Levitt and Pope, 2008; Vermolen et. al., 2011) significantly increased their tolerance to divalent ions and improved their resistance to precipitation. On the other hand, polysaccharides such as xanthan gum, scleroglucan, carboxymethylcellulose, and guar gum, have also been extensively investigated for EOR. These biopolymers are less sensitive towards high salinities, temperatures, and mechanical degradation due to their semi-rigid molecular structure (Kohler and Chauveteau, 1981). However, combinations of high temperature, high salinity and high divalent ion concentrations limit the performance of many of these polymers (Davison and Mentzor, 1982).
According to Davison and Mentzer (1982), polyacrylamides, cellulose-based polymers and guar gum showed limited thermal stability and poor sea water viscosification. PVP was a poor viscosifier when considering its molecular weight. Xanthan gum showed better performance but the content cell debris affected its thermal stability, filterability, and adsorption (Davison and Mentzor, 1982; Doe et. al., 1987). Also the upper limit of xanthan gum usefulness was identified as less than 70 oC (Ryles, 1983; Ash, et. al., 1983).
Surfactant retention is one of the most important variables affecting the economics of chemical flooding and varies widely depending on the surfactant structure, mineralogy, salinity, pH, Eh, microemulsion viscosity, crude oil, co-solvent and mobility control among other variables. We have done a large number of dynamic surfactant retention measurements over a wide range of conditions using a variety of new-generation surfactants to recover crude oils from both sandstone and
carbonate cores. Surfactant retention values for both surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) floods were measured and correlated with pH, total acid number (TAN) of the oil, temperature, co-solvent concentration, salinity of the polymer drive, mobility ratio, and molecular weight of the surfactant. Surfactant retention values ranged from about 0.01 to 0.37 mg/g of rock. SP and ASP formulations included mixtures of anionic and nonionic surfactants with and without cosolvents. The retention of anionic surfactants of all types was found to be similar on both sandstones and carbonate rocks.
The mechanism of surfactant retention is complicated and it depends on several factors such as surfactant structure, mineralogy, salinity, clay content, pH, Eh, microemulsion viscosity, crude oil, co-solvent and mobility control among other variables. A few of the vast number of papers written on surfactant adsorption are briefly reviewed below.
Effect of Surfactant Type and pH. It is well known that surfactant structure affects adsorption on rock surfaces. Traditionally, anionic surfactants were not considered for carbonates because of concerns about high adsorption. However, increasing the pH greatly reduces the adsorption of anionic surfactants on carbonate surfaces. Zhang et al. (2006) observed that using sodium carbonate as an alkali reverses the charge of the calcite surface from positive to negative, leading to less adsorption of anionic surfactants. Interestingly, the same was not observed when sodium hydroxide was used as an alkali.
They proposed that the reason could be the carbonate is a potential determining ion (for carbonate surfaces) whereas a hydroxide is not. However, alkali cannot be used in all cases, so in such cases the most effective SP formulation without alkali must be developed and evaluated. Some anionic surfactants have shown low surfactant retention in carbonates even without alkali that are comparable to the retention in sandstones at typical reservoir pH values. This surprise finding implies that the surfactant retention due to phase trapping and unfavorable phase behavior contributes as much or more than the
Effect of Clay Content. For sandstones, surfactant adsorption depends more on the clay surfaces than on the quartz surface. Silica is negatively charged at reservoir conditions and exhibits negligible adsorption of anionic surfactants at high pH (Hirasaki et al., 2008). At neutral pH, clays have a negative charge on the faces and a positive charge at the edges. The edges exhibit pH dependent charge characteristics, and thus are expected to reverse their charge at a pH of about 9 (Somasundaran and Hanna, 1977; Hirasaki et al., 2008; Sheng, 2011). Wang (1993) also observed similar behavior and concluded that surfactant adsorption on Loudon and Berea sandstones results primarily from the presence of clays. He also showed that preserving the core in reduced conditions (by dithionite treatment) significantly reduced the surfactant adsorption.
Solairaj, Sriram (U Of Texas At Austin) | Britton, Christopher (U Of Texas At Austin) | Lu, Jun (University Of Texas At Austin) | Kim, Do Hoon (U. of Texas at Austin) | Weerasooriya, Upali (U. of Texas at Austin) | Pope, Gary Arnold (U. of Texas at Austin)
It is well known that the oil recovery efficiency of chemical EOR depends on microemulsion phase behavior and interfacial tension (IFT). The surfactants needed to obtain good phase behavior and ultra-low IFT vary greatly with oil characteristics and reservoir conditions. Hence, it is often necessary to test many surfactant formulations before finding a highly effective one. Based on both sound principles and extensive experience, one would expect to find a relationship between the optimum surfactant structure, the oil characteristics, the brine, and the temperature. Salager's equation (Salager et al., 1979, Anton et al., 2008) shows it is possible to correlate some of these variables to classical surfactant structure. We now have many new surfactants with widely different structures and many more good formulations with a wider range of oils, temperature and so forth. Thus, it becomes imperative to study the underlying trend and to identify the most important variables affecting the optimum surfactant structure. A new correlation has been developed using an extensive data set taking into account the effect of propylene oxide number (PON), ethylene oxide number (EON), temperature, brine salinity and the equivalent alkane carbon number (EACN) of the oil. The new correlation will help in identifying the most important variables and also to improve our understanding of the relationship among variables affecting optimum surfactant structure. In particular, the new equation can be used to predict the optimum carbon number of the surfactant hydrophobe. Results show that larger hydrophobes are needed as either the temperature or the equivalent alkane carbon number (EACN) of the oil increases. The surfactant formulations used for this study include mixtures of sulfate, sulfonate, carboxylate and non-ionic surfactants. This is a new and highly significant advance in the optimization of chemical EOR processes that will greatly reduce the time and cost of the effort required to develop a good formulation as well as to improve its performance.
Griffin (1949) first introduced the concept of hydrophilic-lipophilic balance (HLB) to quantify for the relative affinity of surfactant for water and oil. According to this empirical relation, each oil is characterized by "required HLB?? (HLBreq), corresponding to the HLB of the surfactant resulting in the most stable emulsion. However, this method doesn't take into account the effect of other formulation variables such as salinity, hardness, temperature, alkali, alcohol (co-solvent) type and concentration and co-surfactant type and concentration. Winsor (1954) introduced the R-ratio that relates the relative energies of interaction between the surfactant adsorbed at the interface and the aqueous and oil phases surrounding it. It takes into account the molecular effects at the interface, but is still limited by the fact that energies of interaction cannot be measured experimentally. Shinoda (1964) proposed a method based on the determination of phase inversion temperature (PIT) - equivalent to cloud point phenomenon (decrease in hydrophilicity of ethylene oxide moiety of surfactants upon heating). It takes into account the effect of formulation variables (salinity, oil, additives), but in practice this technique can be applied only to ethoxylated nonionic surfactants, since ionic surfactants show opposite sensitivity to temperature.