bluuebunny/crossref_metadata_2025_split huggingface dataset:
Observations of Microemulsion Viscosity for Surfactant EOR Processes
Authors: Suniga P. T. , Fortenberry R. , Delshad M. 
Published: March 2016

Abstract
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 &gt;30°) to heavy oils (API&lt;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.
Fast-Slim Tube: A Reliable and Rapid Technique for the Laboratory Determination of MMP in CO2 - Light Crude Oil Systems
Authors: Adel Imad A. , Tovar Francisco D. , Schechter David S. 
Published: March 2016

Abstract
We present a technique that enables the determination of the minimum miscibility pressure (MMP) of a CO2 – oil system using a short 20 ft slim tube in less than two weeks, about a third of what it normally takes using the conventional 80 ft slim tube. MMP is a crucial parameter in designing a CO2 enhanced oil recovery project and its value needs to be known with a degree of accuracy that cannot be provided by the use of equations of state or correlations, and therefore, needs to be determined experimentally. The slim tube technique is recognized to be the most accurate experimental method for determining the MMP, however its use has not been favored because it is time consuming.
We determined the MMP for five CO2 – crude oil systems from the North Burbank Unit and the Oklahoma/Texas Panhandle. The reduction in the length of the slim tube from 80 ft to 20 ft resulted in a decrease in the total time of the experiment. The validity of our technique was proven with performing recovery factor measurements using a conventional 80 ft long slim tube. The MMP values obtained are valid when the length of the slim tube is sufficient to host the mixing zone and the velocity of the displacement is slow enough to enable the transverse dispersion to eliminate viscous fingering. In the case of light oil, the use of the 20 ft slim tube is justified as the length of the mixing zone is shorter. We support our results with the use of numerical simulation.
The reduction in the time required for slim tube experiments results in a fast, economic and accurate technique for the determination of MMP in CO2 – light crude oil systems. Taking into account that CO2 flooding is the most applied EOR technique in the US and that it is mainly applied to light oil reservoirs, this work can be of great impact by providing a rapid and reliable method to determine the MMP for designing a CO2 enhanced oil recovery project.
Co-solvent Partitioning and Retention
Authors: Chang Leonard Y. , Lansakara-P Dharmika S. , Jang Sung Hyun , Weerasooriya Upali P. , Pope Gary A. 
Published: March 2016

Abstract
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.
Application of Nanofluids for Improving Oil Mobility in Heavy Oil and Extra-Heavy Oil: A Field Test
Authors: Zabala R. , Franco C. A. , Cortés F. B. 
Published: March 2016

Abstract
An important factor during the life of a heavy crude reservoir is the oil mobility. It depends on two factors, oil viscosity and oil relative permeability. Two characteristics of nanoparticles that make them attractive for assisting IOR and EOR processes are their size (1 to 100 nm) and ability to manipulate their behavior. Due to their nano-sized structure, nanomaterials have large tunable specific surface areas that lead to an increase in the proportion of atoms on the surface of the particle, indicating an increasing in surface energy. Nanoparticles are also able to flow through typical reservoir pore spaces with sizes at or below 1 micron without the risk to block the pore space. Nanofluids or "smart fluids" can be designed by tuning nanoparticle properties, and are prepared by adding small concentrations of nanoparticles to a liquid phase in order to enhance or improve some of the fluid properties. However the use of nanoparticles and nanofluids for oil mobility has been poorly studied. Hence, the scope of this work is to present the field evaluation of nanofluids for improving oil mobility and mitigate alteration of wettability in two Colombian heavy oil fields; Castilla and Chichimene. Asphaltenes sorption tests with two different types of nanomaterials were performed for selecting the best nanoparticle for each type of oil. An oil based nanofluid (OBN) containing these nanoparticles was evaluated as viscosity reducer under static conditions. Displacement tests through a porous media in core plugs from Castilla and Chichimene at reservoir conditions were also performed. OBN was evaluated to reduce oil viscosity varying oil temperature and water content. Maximum change in oil viscosity is achieved at 122°F and 2% of nanofluid dosage. The use of the nanofluid increased oil recovery in the core flooding tests, caused by the removal of asphaltenes from the aggregation system, reduction of oil viscosity, and the effective restoration of original core wettability. Two field trials were performed in Castilla (CNA and CNB wells), by forcing 200 bbl and 150 bbl of nanofluid respectively as main treatment within a radius of penetration of ~3 ft. Instantaneous oil rate increases of 270 bopd in CNA and 280 bopd in CNB and BSW reductions of ~11% were observed. In Chichimene also two trials were performed (CHA and CHB), by forcing 86 bbl of and 107 bbl of nanofluid as main treatment within a radius of penetration of ~3 ft. Instantaneous oil rate increases of 310 bopd in CHA and 87 bopd in CHB were achieved not BSW reduction has been observed yet. Interventions were performed few months ago and long term effects are still under evaluation. Results look promising making possible to think extending application of nanofluid in other wells in these fields.
Design of a Robust ASP Formulation for Clay Rich and Moderate Permeability Sandstone Reservoir: From Laboratory to Single Well Chemical Tracer Test in the Field
Authors: Rohilla Neeraj , Ravikiran Ravi , Carlisle Charlie T. , Jones Nick , Davis Marron B. , Finch Kenneth B. 
Published: March 2016

Abstract
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.
Scaling of Low IFT Imbibition in Oil-Wet Carbonates
Authors: Li Yuxiang , Lu Jun , Churchwell Lauren , Tagavifar Mohsen , Weerasooriya Upali , Pope Gary A. 
Published: March 2016

Abstract
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.
A Microfluidic Investigation of the Synergistic Effect of Nanoparticles and Surfactants in Macro-Emulsion Based EOR
Authors: XU Ke , Zhu Peixi , Tatiana Colon , Huh Chun , Balhoff Matthew 
Published: March 2016

Abstract
Injecting oil-in-water (O/W) emulsions stabilized with nanoparticles or surfactants is a promising option for enhanced oil recovery (EOR) in harsh-condition reservoirs. Stability and rheology of flowing emulsion in porous media are key factors for the effectiveness of the EOR method. The objective of this study is to use microfluidics to (1) quantitatively evaluate the synergistic effect of surfactants and nanoparticles on emulsion's dynamic stability and how nanoparticles affects the emulsion properties, and (2) investigate how emulsion properties affect the sweep performance in emulsion flooding.
A microfluidic device with well-defined channel geometry of a high-permeability pathway and multiple parallel low-permeability pathways was created to represent a fracture – matrix dual-permeability system. Measurement of droplets’ coalescence frequency during flow is used to quantify the dynamic stability of emulsions. A nanoparticle aqueous suspension (2 wt%) shows excellent ability to stabilize macro-emulsion when mixed with trace amount of surfactant (0.05 wt%), revealing a synergic effect between nanoparticles and surfactant.
For a stable emulsion, it was observed that flowing emulsion droplets compress each other and then block the high-permeability pathway at a throat structure, which forces the wetting phase into low-permeability pathways. Droplet size shows little correlation with this blocking effect. Water content was observed much higher in the low-permeability pathways than in the high-permeability pathway, indicating different emulsion texture and viscosity in channels of different sizes. Consequently, the assumption of bulk emulsion viscosity in the porous medium is not applicable in the description and modeling of emulsion flooding process.
Flow of emulsions stabilized by the nanoparticle-surfactant synergy shows droplet packing mode different from those stabilized by surfactant only at high local oil saturation region, which is attributed to the interaction among nanoparticles in the thin liquid film between neighboring oil-water interfaces. This effect is believed to be an important contributing mechanism for sweep efficiency attainable from nanoparticle-stabilized emulsion EOR process.
Successful Field Application of Microgel Treatment in High Temperature High Salinity Reservoir in China
Authors: Qiu Yue , Wei Mingzhen , Geng Jiaming , Wu Fengxiang 
Published: March 2016

Abstract
This paper presents the detailed descriptions of successful field application for a high-temperature and high-salinity resistance microgel in a mature reservoir in the northwest part of China. The reservoir with low permeability (230 md) experienced serious vertical and lateral heterogeneity problems, which caused low sweep efficiency and high water-cut (more than 95%). The treatment was designed based on laboratory experiments and experience from previous field application, providing detailed information of mechanism of microgel treatment and project execution. Thermal stability test showed that the microgel could resist the salt concentration up to 230,000 ppm at 125 °C for more than 1 year. From the core analysis, permeability of the long-term water-flooded zone was measured around 1,489 md, proving the evidence that high-permeability zones existed. Pilot test has been done before field application and valuable experience about how to design the injection parameters was provided. According to the information from laboratory experiments and the pilot test, four injection wells associated with nine offset production wells were selected for microgel treatment. For about 10 months treatment, 169 t of microgel was injected by five slugs.
Gradually increased injection pressure suggested that microgel could be placed deeply into the reservoir. The ultimate incremental oil production was approximately 29,635.8 t with the water cut decreasing from 95.3% to 93.1%. Microgel can be successfully used in relative low permeability (230 md) reservoir with harsh conditions for conformance control.
Displacement Efficiency for Low Salinity Polymer Flooding Including Wettability Alteration
Authors: Khorsandi Saeid , Qiao Changhe , Johns Russell T. 
Published: March 2016

Abstract
Polymer flooding can significantly improve sweep and delay breakthrough of injected water, thereby increasing oil recovery. Polymer viscosity degrades in reservoirs with high salinity brines, so it is advantageous to inject low salinity water as a preflush. Low salinity water flooding (LSW) can also improve local displacement efficiency by changing the wettability of the reservoir rock from oil wet to more water wet. The mechanism for wettability alteration for low salinity waterflooding in sandstones is not very well understood, however experiments and field studies strongly support that cation exchange (CE) reactions are the key element in wettability alteration. The complex coupled effects of CE reactions, polymer properties, and multiphase flow and transport has not been explained to date.
This paper presents the first analytical solutions for the coupled synergistic behavior of low salinity waterflooding and polymer flooding considering cation exchange reactions, wettability alteration, adsorption, inaccessible pore volume (IPV), and salinity effects on polymer viscosity. A mechanistic approach that includes the cation exchange of Ca2+, Mg2+ and Na+ is used to model the wettability alteration. The aqueous phase viscosity is a function of polymer and salt concentrations. Then, the coupled multiphase flow and reactive transport model is decoupled into three simpler sub-problems, one where cation exchange reactions are solved, the second where a variable polymer concentration can be added to the reaction path and the third where fractional flows can be mapped onto the fixed cation and polymer concentration paths. The solutions are used to develop a front tracking algorithm, which can solve the slug injection problem where low salinity water is injected as a preflush followed by polymer. The results are verified with experimental data and PennSim, a general purpose compositional simulator.
The analytical solutions show that decoupling allows for estimation of key modeling parameters from experimental data, without considering the chemical reactions. Recovery can be significantly enhanced by a low salinity pre-flush prior to polymer injection. For the cases studied, the improved oil recovery (IOR) for a chemically tuned LSP flood can be as much as 10% OOIP greater than with considering polymer alone. The results show the structure of the solutions, and in particular the velocity of multiple shocks that develop. These shocks can interact, changing recovery. For example, poor recoveries obtained in core floods for small low salinity slug sizes are explained with intersection of shocks without considering mixing. The solutions can also be used to benchmark numerical solutions and for experimental design. We demonstrate the potential of LSP as a cheaper and more effective way for performing polymer flooding when the reservoir wettability can be altered using chemically-tuned low salinity brine.
New Surfactants and Co-Solvents Increase Oil Recovery and Reduce Cost
Authors: A. Nadeeka Upamali Karasinghe , Liyanage Pathma Jith , Cai Jiajia , Lu Jun , Jang Sung Hyun , Weerasooriya Upali P. , Pope Gary A. 
Published: March 2016

Abstract
The ability to develop high performance, low cost chemical formulations for chemical EOR involves the use of not only highly efficient surfactants tailored to specific crude oil and reservoir conditions, but also the technical know-how for combining the surfactants and other chemicals to create the best formulation as a complete package. Scientific understanding of how the molecular structures of surfactants and co-solvents affect microemulsion properties greatly speeds up the process of arriving at optimal formulations for enhanced recovery of a specific crude oil in a specific oil reservoir. With the main emphasis on reducing the chemical cost of the formulations, a new slate of novel chemicals, both surfactants and co-solvents, has been developed and shown to have superior performance. We have synthesized and tested new classes of surfactants with different hydrophobe sizes and structures varying from large-medium-short-ultrashort in order to meet the needs of a variety of crude oil requirements. We have also developed ultra-short hydrophobe surfactants (with 2-ethylhexanol hydrophobe) possessing dual surfactant / co-solvent properties. Such duality in performance helps, in some cases, to minimize or altogether offset the use of co-solvents while maintaining low microemulsion viscosities, faster equilibration, and other desirable behavior. Thus, 2-ethylhexanol-propoxy-sulfate was developed as a surfactant that also encompasses co-solvent properties. The novel Gemini surfactants have also been incorporated in formulations and core flood experiments with excellent results. The new co-solvents offer advantages such as short equilibration time for the microemulsion formation and lower microemulsion viscosity. Systematic studies using these new surfactants and co-solvents clearly show that we now have the capability of developing highly robust formulations to meet the needs of a variety of reservoirs, resulting in high oil recoveries with low surfactant retention, which is the key to lowering the chemical costs and improving the economics of chemical enhanced oil recovery.