Jin, Luchao (University of Oklahoma) | Budhathoki, Mahesh (University of Oklahoma) | Jamili, Ahmad (University of Oklahoma) | Li, Zhitao (The University of Texas at Austin) | Luo, Haishan (The University of Texas at Austin) | Delshad, Mojdeh (The University of Texas at Austin) | Shiau, Ben (University of Oklahoma) | Harwell, Jeffrey H. (University of Oklahoma)
The surfactant screening process to develop an optimum formulation under reservoir conditions is typically time consuming and expensive. Theories and correlations like HLB, R-ratio and packing parameters have been developed. But none of them can quantitatively consider both the effect of oil type, salinity, hardness and temperature, and model microemulsion phase behavior.
This paper uses the physics based Hydrophilic Lipophilic Difference (HLD) Net Average Curvature (NAC) model, and comprehensively demonstrated its capabilities in predicting the optimum formulation and microemulsion phase behavior based on the ambient conditions and surfactant structures. By using HLD equation and quantitatively characterized parameters, four optimum surfactant formulations are designed for target reservoir with high accuracy compared to experimental results. The microemulsion phase behavior is further predicted, and well matched the measured equilibrium interfacial tension. Its predictability is then reinforced by comparing to the empirical Hand's rule phase behavior model. Surfactant flooding sandpack laboratory tests are also interpreted by UTCHEM chemical flooding simulator coupled with the HLD-NAC phase behavior model.
The results indicate the significance of HLD-NAC equation of state in not only shorten the surfactant screening processes for formulators, but also predicting microemulsion phase behavior based on surfactant structure. A compositional reservoir simulator with such an equation of state will increase its predictability and hence help with the design of surfactant formulation.
Favorable microemulsion rheology is required for achieving low surfactant retention and economic viability of chemical EOR. Co-solvents play a pivotal role in obtaining favorable microemulsion rheology as well as many other aspects of chemical EOR. We measured the partitioning of co-solvents between phases to better understand their behavior and how to select the best co-solvent for chemical EOR. There is an optimal co-solvent partition coefficient for microemulsion systems. Commercial co-solvents used for chemical EOR are actually mixtures of different components. We used HPLC to measure the partitioning of the constitutive components of phenol ethoxylate co-solvents between oil and water phases and between microemulsion and excess oil and water phases. These measurements show that the components partition independently and the partitioning of individual components is often different from the average. The co-solvent partition coefficients between oil and water were systematically evaluated as functions of the number of ethylene oxide groups, number of propylene oxide groups, temperature, salinity, and the equivalent alkane carbon number (EACN) of the oil. Novel alkoxylate co-solvents were also evaluated for chemical EOR. The novel alkoxylate co-solvents can be more effectively tailored to match the characteristics of different crude oils. Coreflood experiments were conducted to investigate co-solvent transport and retention. Co-solvents were identified that showed excellent performance and low retention.
Davidson, Andrew (Chevron Energy Technology Company) | Nizamidin, Nabijan (Chevron Energy Technology Company) | Alexis, Dennis (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Unomah, Michael (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan
Low microemulsion viscosity is critical for the success of chemical EOR. Typical microemulsion viscosities are measured using a rheometer and are considered to be static measurements. Given that microemulsions have a propensity to show non-Newtonian behavior, static viscosity measurements are not scalable to dynamic viscosities observed in cores and hence difficult to scale-up to field designs using simulations. We present a technique to measure dynamic microemulsion viscosity using a modified two-phase steady state relative permeability setup. Such dynamic viscosities provide a more practical feel for microemulsion viscosity under reservoir conditions in the pores and allow for selection of low microemulsion viscosity formulations. A two-phase steady state relative permeability setup was used with continuous co-injection of oil and surfactant. A glass filled sand pack was used as a surrogate core and the injection fluids were allowed to equilibrate into the appropriate phases as determined by the phase behavior. For the rapidly equilibrating and low viscosity Winsor Type III formulations three phases are clearly observed in the sand packs. Using the phase cuts in the sand pack/effluent and the known oil and water viscosities, we can estimate the microemulsion viscosity. Both low and high viscosity formulations were tested in corefloods and oil recovery measured to illustrate the importance of low viscosity microemulsions for oil recovery. As expected, the low viscosity microemulsions correlated with higher oil recovery. In addition, the equilibration times to reach Winsor Type III microemulsions were also linked to better oil recovery. For the well behaved formulations that equilibrated in less than 2 days the static microemulsion viscosity correlated well with the dynamic viscosity. The modified steady state relative permeability setup can accurately estimate microemulsion viscosity and allow for better screening of surfactant formulations identified for field flooding. The dynamic microemulsion viscosities can also provide inputs for numerical simulation and better predict microemulsion behavior in the subsurface during field surfactant floods.
Tagavifar, Mohsen (The University of Texas at Austin) | Herath, Sumudu (The University of Texas at Austin) | Weerasooriya, Upali P. (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin) | Pope, Gary (The University of Texas at Austin)
We made measurements of microemulsion rheology with mixtures of oil, brine, surfactant, co-solvent, and in some cases polymer to systematically investigate the effects of salinity, co-solvents and polymers. A microemulsion rheology model was developed and used to interpret the experimental results. We show that the optimum microemulsion-to-oil viscosity ratio is roughly 5 to 6 without co-solvent, but it can be reduced to a more favorable ratio of ~2 by adding co-solvent. Even though the amount of co-solvent needed is case dependent, a clear trend of microemulsion viscosity reduction with increasing co-solvent concentration was observed. Limited evidence suggests that large hydrolyzed polyacrylamide molecules with a narrow molecular weight distribution have negligible partitioning to type II and III microemulsions.
Li, Yuxiang (The University of Texas at Austin) | Lu, Jun (The University of Texas at Austin) | Churchwell, Lauren (The University of Texas at Austin) | Tagavifar, Mohsen (The University of Texas at Austin) | Weerasooriya, Upali (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin)
Primary and secondary oil recovery from naturally fractured carbonate reservoirs with an oil-wet matrix is very low. Enhanced oil recovery from these reservoirs using surfactants to alter the wettability and reduce the interfacial tension have been extensively studied for many years, but there are still many questions about the process mechanisms, surfactant selection and testing, experimental design and most importantly how to scale up the lab results to the field. We have conducted a series of imbibition experiments using cores with different vertical and horizontal dimensions to better understand how to scale up the process. There was a particular need to perform experiments with larger horizontal dimensions since almost all previous experiments have been done in cores with a small diameter, typically 3.8 cm. We adapted and modified the experimental method used for traditional static imbibition experiments by flushing out fluids surrounding the cores periodically to better estimate the oil recovery, including the significant amount of oil produced as an emulsion. We used microemulsion phase behavior tests to develop high performance surfactant formulations for the oils used in this study. These surfactants gave ultra-low IFT at optimum salinity and good aqueous stability. Although we used ultra-low IFT formulations for most of the experiments, we also performed tests at higher IFT for comparison. Even for the higher IFT experiments, the capillary pressure is very small compared to gravity and viscous pressure gradients. We also developed a simple analytical model to predict the oil recovery as a function of vertical and horizontal fracture spacing, rock properties and fluid properties. The model and experimental data are in good agreement considering the many simplifications made to derive the model. The scaling implied by the model is significantly different than traditional scaling groups in the literature.
Rohilla, Neeraj (TIORCO, a Nalco Champion Company) | Ravikiran, Ravi (Stepan Company) | Carlisle, Charlie T. (Chemical Tracers Inc.) | Jones, Nick (University of Wyoming) | Davis, Marron B. (Sunshine Valley Petroleum Corporation) | Finch, Kenneth B. H. (TIORCO, a Nalco Champion Company)
Sandstone reservoirs containing significant amount of clays (30-40 wt%) with moderate permeability (20-50 mD) provide a unique challenge to surfactant based enhanced oil recovery (EOR) processes. A critical risk factor for these types of reservoirs is adsorption of surfactants due to greater surface area attributed to clays. Clays also have high cation exchange capacity (CEC) and can release significant amounts of di-valents that lead to increased retention of the surfactant. These factors could adversely affect the economics of a flood.
We present a case study where a robust formulation was designed and tested in lab/field for a reservoir located in Wyoming, USA and contains up to 35-40 wt% clays (predominately Kaolinite and Illite). The residual oil saturation is high (Sor=0.4) while the permeability of the formation is between 20-50 mD. The reservoir has been waterflooded historically with low salinity water which has led to formation permeability damage. Due to high levels of clays, adsorption of the surfactant on the rock surface was determined to be between 3-4 mg/g rock by static adsorption tests.
This publication demonstrates how the following challenges have been successfully addressed in the lab as well as in the field in the form of single well chemical tracer test (SWCTT).
Designed a robust alkaline-surfactant-polymer (ASP) formulation that showed ultra-low interfacial tension (IFT) values and aqueous solubility remains soluble in the aqueous solution over a broad range of salinity. Mitigated surfactant adsorption issues to make the cEOR solution economic. A sacrificial agent was identified that acted synergistically with alkali and also did not alter the optimum salinity of the formulation. Performed restored state core analysis using the available damaged core material. The main challenge being restoration of the coreplugs to current reservoir conditions for coreflood experiment without causing additional formation damage due to injection of low salinity formation brine. Designed a flood that utilized a pre-flush to provide a favorable salinity gradient and to inject sacrificial agent ahead of the surfactant front. Performed polymer screening to select right molecular weight of polymer so that the right balance of mobility control and injectivity in the reservoir can be obtained.
Designed a robust alkaline-surfactant-polymer (ASP) formulation that showed ultra-low interfacial tension (IFT) values and aqueous solubility remains soluble in the aqueous solution over a broad range of salinity.
Mitigated surfactant adsorption issues to make the cEOR solution economic. A sacrificial agent was identified that acted synergistically with alkali and also did not alter the optimum salinity of the formulation.
Performed restored state core analysis using the available damaged core material. The main challenge being restoration of the coreplugs to current reservoir conditions for coreflood experiment without causing additional formation damage due to injection of low salinity formation brine.
Designed a flood that utilized a pre-flush to provide a favorable salinity gradient and to inject sacrificial agent ahead of the surfactant front.
Performed polymer screening to select right molecular weight of polymer so that the right balance of mobility control and injectivity in the reservoir can be obtained.
During an Alkaline-Surfactant-Polymer (
In this study, steady-state (
For brine/oil systems some dependence of apparent viscosity on rock permeability was observed; for systems with surfactants no such trend was noticable. The addition of surfactants substantially reduced the apparent viscosities; the viscosity reducing impact of surfactants could be balanced by the addition of polymer. Fractional flow analysis showed that the addition of surfactants reduces the impact of capillary forces resulting in straightened relative permeability curves and higher aqueous phase relative permeability end points.
It is anticipated that this study leads to a fast and fit for purpose characterization method of
In the case of surfactant EOR, an optimum formulation of surfactant has to be injected in the reservoir. This so-called optimum formulation corresponds to a minimum in the interfacial tension and a maximum in oil recovery and may be obtained with an appropriate balance of the hydrophobic and hydrophilic affinities of the surfactant. Salinity—scan tests are generally used to screen phase behavior of surfactant formulations before conducting time-consuming coreflood tests. The objective of this study was to develop a high-throughput dynamic microfluidic tensiometer, with the aim of studying interfacial phenomena between EOR injected formulations and crude oils and of optimizing chemical EOR processes for pilot or field applications.
We have selected a method based on the Rayleigh-Plateau instability and the analysis of the droplets to jetting transition in a coaxial flow of two fluids. In fact, in coaxial flows, the transition between a droplet and a jetting regime depends on the velocities of each phase, the viscosity ratio, the confinement and the interfacial tension (IFT). As the three first parameters are known, the dynamic interfacial tension can be calculated. This microfluidic device has been specifically designed to support high temperatures (up to 150°C), high pressures (up to 150 bars) and is compatible with complex fluids such as crude oils and solutions of surfactants and polymers.
The method was first developed and validated on a microfluidic device on model fluids at ambient temperature and atmospheric pressure for IFTs higher than 1 mN/m. It was then successfully applied for the measurement of IFTs over more than four decades. Measurements were also performed with a crude oil and a typical surfactant formulation. The validation of the HP/HT assembly, which has been designed with the aim to work in reservoir conditions, is currently under progress. By using this tensiometer, it would be quite easy to perform in short time numerous salinity scans on real systems in order to get the evolution of IFT and determine the optimal salinity S*.
Microemulsion properties significantly impact any EOR process that relies on surfactants or soaps to generate ultralow interfacial tension to displace trapped oil. Unfavorable microemulsion viscosity can lead to high chemical retention, low oil recovery, and overall unfavorable performance across all modes. Controlling microemulsion properties is important in conventional approaches like surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) flooding, in addition to new applications like gravity stable displacements, spontaneous imbibition in fractured carbonates and unstable floods of viscous oil. Despite the central importance, microemulsion viscosity and rheology remain poorly understood.
This paper describes the results of an extensive experimental microemulsion study. We evaluated the effect of polymer on microemulsion viscosity in different microemulsion phase types (i.e. oil in water, bi-continuous, water in oil emulsions). We measured microemulsion viscosities across a broad salinity range for several crudes from light (API >30°) to heavy oils (API<14°) and observed Newtonian rheology for all phase types. The effect of cosolvents on microemulsion viscosity was also evaluated. Finally, we evaluated microemulsions with and without alkali to help understand potential differences between ASP and SP microemulsions.
We include many observations consistent with earlier literature using recently developed surfactants and report the microemulsion viscosity details for many high performance surfactant formulations across a wide range of conditions. We have also describe several observations, including polymer decreasing the required time to achieve equilibrium in microemulsion pipettes and the qualitative change in microemulsion behavior with and without polymer in Windsor Type III microemulsions.
Aminzadeh, Behdad (Chevron Energy Technology Company) | Hoang, Viet (Chevron Energy Technology Company) | Inouye, Art (Chevron Energy Technology Company) | Izgec, Omer (Chevron Energy Technology Company) | Walker, Dustin (Chevron Energy Technology Company) | Chung, Doo (Chevron Energy Technology Company) | Nizamidin, Nabijan (Chevron Energy Technology Company) | Tang, Tom (Chevron Energy Technology Company) | Lolley, Chris (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Alkali flooding in heavy oil reservoirs is known to stabilize emulsion in-situ and improve the recovery beyond that of conventional waterflood under certain boundary and initial conditions. The overarching goal of this study is to develop a systematic approach to optimize this process and capture underlying recovery mechanisms. Therefore, we experimentally evaluated the performance of alkali flood as a function of emulsion type and viscosity. Phase behavior and viscosity of the microemulsion are modified by introducing seven different surfactants. Microscope imaging techniques are employed to measure the droplet size distribution for type I and II emulsions. Viscosities of generated emulsions are measured with a rotational rheometer at low temperatures and with an electromagnetic viscometer at reservoir conditions. Finally, corefloods are conducted at different conditions to evaluate the performance of displacement as a function of emulsion type and viscosity. Enhanced alkali floods showed an incremental recovery of 8 – 50% beyond that of waterflood. Formation of higher viscosity emulsion has a large contribution on the sweep efficiency and therefore improved oil recovery during alkali flood; however, other mechanisms (e.g. entrainment and entrapment) also have contribute to the incremental recovery. Results of our experiments indicated that the incremental recovery is a strong function of emulsion type, emulsion viscosity, and the droplet size distribution.