bluuebunny/crossref_metadata_2025_split huggingface dataset:
Polymer Oil Recovery Experiments in Different Geometries for Improved Upscaling of Viscous Oil Reservoirs
Authors: Lee Vincent , Doorwar Shashvat , Dwarakanath Varadarajan , Isbell J. Taylor , Malik Taimur , Slaughter Will 
Published: March 2018

Abstract
Upscaling the simulation of unstable displacement of heavy oil is challenging because accurately modeling the development and propagation of viscous instabilities within a simulation grid-block is next to impossible. Various models have been developed that are capable of history matching oil recovery results, however, there is little lab data to allow for validated scale-up of these viscous fingering model. We present experimental results from different geometries, i.e. cylindrical corefloods, 2D slabs and 3D blocks, where a viscous oil is displaced by water and polymer solutions, under pressure-constrained injection.
Waterflood and polymer flood oil recovery experiments were performed in ‘2-Dimensional’ (2D) sandstone slabs (12" by 12" by 1") and ‘3-Dimensional’ (3D) blocks (12" by 12" by 4") of sandstone and compared with oil recovery experiments through linear ‘1-Dimensional’ (1D) cylindrical cores. Experiments were performed with a high viscosity (540 cP) mineral oil at room temperature. UTCHEM (a software product from The University of Texas at Austin) with viscous fingering model was used to model the experiments and identify parameters for scaling the process to a field scale.
As expected, water breakthrough was accelerated as we moved from cylindrical cores to 2D slabs to 3D blocks. For the experiments conducted, gravity instability had a minimal effect compared to viscosity instability, even for the 3D blocks. Pseudo relative permeability curves based on the modified viscous fingering model were developed to match the 1D experiment. The same pseudo parameters showed excellent scalability across the varying experimental geometries (1D, 2D and 3D). These results indicated that the effective finger width did not vary for the different geometries.
EOR Potential in the Post Steam Injection Era: Current and Future Trends
Authors: Dong Xiaohu , Liu Huiqing , Wu Keliu , Chen Zhangxin 
Published: March 2018

Abstract
The in-situ steam based technology is still the main exploitation method for bitumen and heavy oil resources all over the world. But most of the steam-based processes (e.g., cyclic steam stimulation, steam drive and steam assisted gravity drainage) in heavy oilfields have entered into anexhaustion stage. Considering the long-lasting steam-rock interaction, how to further enhance the heavy oil recovery in the post-steam injection era is currently challenging the EOR (enhanced oil recovery) techniques. In this paper, we present a comprehensive review of the EOR processes in the post steam injection era both in experimental and field cases. Specifically, the paper presents an overview on the recovery mechanisms and field performance of thermal EOR processes by reservoir lithology (sandstone and carbonate formations) and offshore versus onshore oilfields. Typical processes include thein-situ combustion process, the thermal/-solvent process, the thermal-NCG (non-condensable gas, e.g., N2, flue gas and air) process, and the thermal-chemical (e.g., polymer, surfactant, gel and foam) process. Some new in-situ upgrading processes are also involved in this work. Furthermore, this review also presents the current operations and future trends on some heavy oil EOR projects in Canada, Venezuela, USA and China.
This review showsthat the offshore heavy oilfields will be the future exploitation focus. Moreover, currently several steam-based projects and thermal-NCG projects have been operated in Emeraude Field in Congo and Bohai Bay in China. A growing trend is also found for the in-situ combustion technique and solvent assisted process both in offshore and onshore heavy oil fields, such as the EOR projects in North America, North Sea, Bohai Bay and Xinjiang. The multicomponent thermal fluids injection process in offshore and the thermal-CO2and thermal-chemical (surfactant, foam) processes in onshore heavy oil reservoirs are some of the opportunities identified for the next decade based on preliminary evaluations and proposed or ongoing pilot projects. Furthermore, the new processes of in-situ catalytic upgrading (e.g., addition of catalyst, steam-nanoparticles), electromagnetic heating and electro-thermal dynamic stripping (ETDSP) and some improvement processes on a wellbore configuration (FCD) have also gained more and more attention. In addition, there are some newly proposed recovery techniques that are still limitedto the laboratory scale with needs for further investigations. In such a time of low oil prices, cost optimization will be the top concerns of all the oil companies in the world. This critical review will help to identify the next challenges and opportunities in the EOR potential of bitumen and heavy oil production in the post steam injection era.
Modeling of CoSolvent Assisted Chemical Flooding for Enhanced Oil Recovery in Heavy Oil Reservoirs
Authors: Dang Cuong , Nghiem Long , Nguyen Ngoc , Yang Chaodong , Mirzabozorg Arash , Li Heng , Chen Zhangxin 
Published: March 2018

Abstract
Many attempts have been made to understand, design, and optimize a chemical flooding process; however, the current low oil price environment makes its implementation very challenging from an economics point of view. Recently, CoSolvent Assisted Chemical Flooding (CACF) has been considered as a promising approach to reduce the cost of surfactant-based recovery methods, especially in heavy oil reservoirs. More importantly, recent studies indicated that CACF can be efficiently applied at relatively low temperature, i.e., without the need of steam injection. This helps reduce for the cost of steam generation and injection, and the associated greenhouse gas effects. This paper presents a new development in modeling CACF using an Equation-of-State (EOS) compositional reservoir simulator.
We used a new approach to model the behavior of the oil-water-microemulsion system based on solubility data without modeling type III microemulsion explicitly. The results showed an excellent agreement with numerous chemical coreflooding data and are in agreement with a chemical floodingresearch simulator. The new development presented includes the effects of cosolvent on rheological properties and phase behavior of microemulsion in the CACF process, particularly microemulsion viscosity and interfacial tension.
The proposed model showed good agreement with four published CACF coreflood experiments in which surfactant was not used in alkali and polymer chemical slugs. This model efficiently captures the complex chemical reactionsoccurring in the CACF process, i.e., generation of in-situ soap based on reactions between alkali and a rich acid component in heavy crude oil. The model provides consistent results with laboratory coreflood data at different operating temperatures, which is very important for heavy oil reservoirs. The ultimate recovery factor by CACF coreflooding is about 97%, similar to ASP (Alkali, Surfactant and Polymer) coreflooding, but without the need of surfactant injection.
A New Thermally Stable Synthetic Polymer for Harsh Conditions of Middle East Reservoirs: Part II. NMR and Size Exclusion Chromatography to Assess Chemical and Structural Changes During Thermal Stability Tests
Authors: Rodriguez L. , Antignard S. , Giovannetti B. , Dupuis G. , Gaillard N. , Jouenne S. , Bourdarot G. , Morel D. , Zaitoun A. , Grassl B. 
Published: March 2018

Abstract
Most Middle East fieds present harsh reservoir conditions (high temperature, high salinity, low permeability carbonates) for polymers used as EOR mobility control agents. Traditional synthetic polymers such as partially hydrolyzed polyacrylamide (HPAM) are not thermally stable. At temperatures above 60°C, acrylamide moieties hydrolyze to sodium acrylate which ultimately leads to precipitation and total viscosity loss. Thermal stability can be improved by incorporating monomers such as ATBS or NVP.
In a previous paper, we reported the development of terpolymers where incorporation of NVP was shown to provide improved stability up to 120°C. Unfortunately, NVP increases the cost of the polymer and limits its molecular weight. Additionally, NVP also causes drifts in the polymers composition, thereby impairing injectivity in low permeability carbonate rocks. The price of the final product, to achieve a given viscosity, is approximately 3 times higher compared to conventional HPAM polymers and 2 to 2.5 times higher than SPAM polymers (sulfonated polyacrylamide). More recently, we reported the synthesis of NVP-free polymers incorporating different mol precentages of ATBS. The ATBS containing polymers are cheaper than the NVP polymers and enable dosage reductions of up to 50%, to obtain the same viscosity. Additionally, they outperformed the NVP polymers in terms of injectivity and thermal stability, as well as pushed the stability limits from 105-110°C up to 130°C and 140°C in brines withTDS of 230 g/L and 100 g/L respectively.
In this study, we present new data for viscosity and thermal stability of NVP-free polymers optimized in terms of process and molecular weight. In particular, the thermal stability study was completed with NMR spectroscopy and Size Exclusion Chromatography (SEC) analysis to obtain information on the evolution of the chemistry and the molecular weight distribution of the polymers during long-term aging. NMR and SEC analysis reveal that the reduction of the viscosity during aging is due to an evolution of the polymer chemistry (conversion of acrylamide and ATBS units in acrylates) as well as chain scission. The incorporation of ATBS, into the polymer backbone, appears to slow down hydrolysis and limits the viscosity loss. There was no modification of the chemistry observed for the polymer having the highest level of ATBS and any viscosity loss observed is directly related to a decrease in molecular weight.
The optimization of the NVP-free polymers redues the dosage by one third, making them very attractive from an economic standpoint. Both NMR and SEC techniques, have been shown to be efficient tools to understand the mechanism involved in viscosity changes for polymer solutions during long-term thermal aging.
Understanding the Oil Recovery Mechanism in Mixed-Wet Unconventional Reservoirs: Uniqueness and Challenges of Developing Chemical Formulations
Authors: B. Alamdari Baharak , Hsu Tzu-Ping , Nguyen Duy , Kiani Mojtaba , Salehi Mehdi 
Published: March 2018

Abstract
Several surfactant formulations that had been tested successfully in oil-wet unconventional reservoirs were tested in mixed-wet to oil-wet unconventional reservoir cores and did not generate the expected results. To study the mechanisms of oil recovery and understand the uniqueness of these shale reservoirs, a series of studies were performed utilizing Eagle Ford (EF) and Canadian Bakken shale rocks and fluids.
In this study customized chemical formulations for improving production from the EF and the Canadian Bakken were developed. Previously related formulation development for the Bakken and Permian basins relied upon wettability alteration as the oil recovery mechanism; however, no significant oil recovery compared to brine was seen from wettability-altering formulations using EF and Canadian Bakken shale rock and fluids. Several imbibition tests showed that baseline oil recovery by brine was 20-30% of original oil in place (OOIP) for both formations. High oil recovery by brine was attributed to the mixed to water-wet nature of the pore surface. A well-connected fracture system may have also contributed. Further, there was no correlation between oil recovery and contact angle measurements.
Failure of wettability alteration as an oil recovery mechanism led to investigation of interfacial tension (IFT) reduction as an alternative mechanism. Testing this hypothesis, a change in the EF formulation reduced IFT to 0.03 dyne/cm and had oil recoveries above 60% OOIP. However, these formulations were not stable at 320 °F. Formulation KPIs were set as lowering IFT and being stable up to 320 °F. Out of many formulations tested, two containing multiple actives in a specific mixture of solvents passed the KPIs and were tested for imbibition oil recovery. A synergistic mixture had a final oil recovery above 56% OOIP as compared to 20-25% OOIP for brine alone. The imbibition oil recovery results indicate that although the ultimate oil recovery by brine alone is significant, the early oil production is significantly slower than by surfactant solutions. Upscaling the laboratory time to the field time emphasizes the value of implementing customized surfactant formulation in both early and late oil production.
Similarly, there was no correlation between wettability contact angle measurements and oil recovery for the Canadian Bakken shale. Surfactant formulations which exhibited low IFT (~0.01 dyne/cm) significantly accelerated the oil production and recovered an additional 30-45% OOIP in the tertiary mode from the imbibition tests. Further laboratory studies via the Washburn method, imbibition tests, and zeta potential measurements validated lowering IFT, not altering the wettability, as a primary oil recovery mechanism in the mixed-wet EF and Canadian Bakken.
Optimal formulations for EF and Canadian Bakken will be tested in the field by mid-2018.
An Integrated CO2 Foam EOR Pilot Program with Combined CCUS in an Onshore Texas Heterogeneous Carbonate Field
Authors: Alcorn Z. P. , Fredriksen S. B. , Sharma M. , Rognmo A. U. , Føyen T. L. , Fernø M. A. , Graue A. 
Published: March 2018

Abstract
A CO2 foam enhanced oil recovery (EOR) field pilot research program has been initiated to advance the technology of CO2 foam for mobility control in a heterogeneous carbonate reservoir. Increased oil recovery with associated anthropogenic CO2 storage is a promising technology for mitigating global warming as part of carbon capture, utilization, and storage (CCUS). Previous field tests with CO2 foam report various results due to injectivity problems and the difficulty of attributing fluid displacement specifically to CO2 foam. Thus, a more integrated multiscale methodology is required for project design to further understand the connection between laboratory and field scale displacement mechanisms. Foam is frequently generated in a reservoir through the injection of alternating slugs of surfactant solution and gas (SAG). To reduce costs and increase the success of in-situ foam generation, SAG operations must be optimized for field implementation. This study presents an integrated upscaling approach for designing a CO2 foam field trial, including pilot well selection criteria, comprehensive laboratory coreflood experiments combined with reservoir scale simulation to offer recommendations for a SAG injection schedule while assessing CO2 storage potential.
Laboratory investigations include dynamic aging, foam stability scans, CO2 foam EOR corefloods with associated CO2 storage, and unsteady state CO2/water endpoint relative permeability measurements. Wettability tests of restored reservoir core material yield Amott-Harvey index values of −0.04 and −0.79, indicating weakly oil wet to oil wet conditions. Foam scans demonstrate highest foam quality at gas fraction (fg) of 0.70. CO2 foam EOR corefloods after completed waterfloods, at optimal foam quality, result in a total recovery factor of 80% OOIP with an incremental recovery of 35% OOIP by CO2 foam.
A negligible difference is observed in incremental CO2 foam recoveries and apparent viscosities when using 1 wt% and 0.5wt% surfactant solution. High differential pressures during CO2 foam suggest generation of stable foam with mobility reduction factors by CO2 foam up to 340, over CO2 at reservoir conditions. CO2 storage potential was assessed during displacement to investigate the carbon footprint of CO2 foam injection.
Relative permeability endpoints and foam stability scan parameters are input into a validated field scale numerical simulation model to recommend design parameters for SAG injection. The numerical model investigates foam's impacts on oil recovery, gas mobility reduction, producing gas oil ratio (GOR), and CO2 utilization. Simulation studies show the effectiveness of foam to reduce gas mobility, improve CO2 utilization, and decrease GOR.
Longitudinal Fracturing in a Mature Permian Waterflood: A Case Study
Authors: Wagia-Alla Ahmed , Roach Riley , El-Azzi Joseph 
Published: March 2018

Abstract
Horizontal drilling was successfully applied in a mature waterflood at Occidental's North Wasson Clearfork Unit (NWCFU) as the first waterflooded longitudinal fractured horizontal in the Permian Basin Leonardian Series. The field is located on the northwestern shelf of the Permian Basin, where the Middle Clearfork (MCF) reservoir had been developed with 20-acre vertical well spacing. Recent geological models revealed a series of relatively thin, discontinuous lenticular extensions of "pay" quality porosity in areas of poor areal sweep efficiency. Although horizontal development is typically used for greenfield tight unconventional resources, this concept was evaluated as an alternative to traditional vertical infill drilling in this conventional, heterogeneous, waterflooded reservoir.
Because the widely accepted practice of maximizing stimulated rock volume with closely spaced, transverse fractures would jeopardize the waterflood sweep efficiency, the horizontal well was drilled parallel to the in-situ maximum horizontal stress (SHmax), rather than perpendicular.
A horizontal pilot well was drilled with the following objectives: 1) to prove the effectiveness of multistage, longitudinal fractures to increase oil production from a heterogeneous reservoir, thereby improving recovery efficiency in a mature waterflood, and 2) to investigate the ability to manage the well's decline with waterflood support from offset vertical injection wells.
Initial results have shown that the pilot was successful in meeting both objectives. Furthermore, this horizontal well, which cost five times as much as a vertical well, had an initial peak rate that was seven times as much as a typical vertical well in the field, and in the first year, it produced about seven times as much as a typical vertical well. In this paper, we will discuss the successes and challenges of the pilot project and share the lessons learned.
Foam Generation by Capillary Snap-Off in Flow Across a Sharp Permeability Transition
Authors: Shah Swej Y. , Wolf Karl-Heinz , Pilus Rashidah M. , Rossen William R. 
Published: March 2018

Abstract
Foam reduces gas mobility and can improve sweep efficiency in an enhanced-oil-recovery process. Previous studies show that foam can be generated in porous media by exceeding a critical velocity or pressure gradient. Such pressure gradients are typically encountered only near a well and therefore, it is uncertain whether foam can propagate far from wells. Theoretical studies show that foam can be generated independent of pressure gradient during flow across an abrupt increase in permeability. In subsurface flow, such sharp permeability changes occur across different length scales. Laminations and cross-laminations, for example, are commonly found small-scale features, whereas unconformities, including layer boundaries and erosional surfaces, are field-scale features that are associated with sharp permeability contrasts across them. In this study, we validate theoretical predictions of foam generation through a variety of experimental evidence. We perform coreflood experiments involving simultaneous injection of gas and surfactant solution at field-like velocities into a model consolidated porous medium made of sintered glass. The core has a well-characterized, sharp permeability transition achieved by sintering glass of different grain sizes. Pressure gradient is measured across several sections of the core to identify foam-generation events and the subsequent propagation of foam. X-ray computerized tomography (CT) provides dynamic images of the coreflood in the form of phase saturations as they develop through the experiment. We investigate the effects of the magnitude of the permeability change and injected gas fractional flow on foam generation and mobilization.
Creation of Insitu EOR Foams by the Injection of Surfactant in Gas Dispersions - Lab Confirmation and Field Application
Authors: Ocampo Alonso , Restrepo Alejandro , Lopera Sergio H. , Mejia Juan M. 
Published: March 2018

Abstract
This work presents the conceptual development and experimental evaluation for a new technique to create blocking foams in matrix rock systems by the injection of the foaming agent dispersed in the hydrocarbon gas stream. This new technique aims at simplifying the operation and reducing costs for the deployment of EOR foams in gas injection based projects, and overcoming the disadvantage of limited reservoir volume of influence obtained in the SAG technique.
A systematic experimental work is implemented to investigate the effect of the dispersed chemical (surfactant) concentration and the gas velocity on the ability to create blocking foams at high pressure and temperature, and using representative consolidated porous medium and fluids coming from the Piedemonte fields in Colombia. The concept behind this new technique is the transfer of chemical foamer from the gas dispersion into the connate or residual waters present in the hydrocarbon reservoirs under exploitation, due mainly to the chemical potential derived from the contrast in chemical concentration between the dispersed phase and the in-situ water.
Results herein confirm that it is possible to create blocking foam by this technique in a consolidated sandstone core at residual oil and water conditions, after being submitted to a gas flooding displacement. This condition is obtained as far as the gas velocity is above a minimum threshold, and the concentration of the active chemical is above certain limit (138 ppm for this case). Successful experiments with foams created by gas dispersed surfactant showed much longer stability periods when compared with results from foams created by the SAG technique at much higher chemical concentration (2,000 ppm). Application of this foams technique was done in a field pilot. About 600 Bbls of foaming solution were dispersed in the hydrocarbon gas stream in one gas injector of a Piedemonte field (Colombia, South America). Gas injectivity in the well was impaired after two weeks of injection, and the oil production well influenced by this injector changed its performance showing incremental oil production and flattening of the gas oil ratio (GOR) shortly after the dispersed chemical injection period. This innovative foams technique could also be extended to other non-condensable gases at field operating conditions like CO2, Nitrogen, Air, and Flue Gas.