bluuebunny/crossref_metadata_2025_split huggingface dataset:
Grain-Scale Modeling of Polymer-driven Fracture Initiation and Wellbore Injectivity
Authors: Li Zihao , Sun Zhuang , Espinoza D. Nicolas , Balhoff Matthew T. 
Published: August 2020

Abstract
Reservoir simulators often predict poor injectivity in polymer enhanced oil recovery (EOR) projects because of the high polymer viscosity, which is a deterrent for the project. However, field studies have shown much higher injectivity than predicted by the models. The objective of this work is to perform grain-scale, coupled fluid dynamics and geomechanics modeling to predict the injectivity of viscous, non-Newtonian polymers in wellbores. Fluid-rock interactions are modeled by coupling computational fluid dynamics (CFD) and the discrete element method (DEM). Fluid flow is determined using an open-source CFD software that solves the volume-averaged Navier-Stokes equation using the finite volume method on Eulerian grids. Grain-scale geomechanics (DEM) is used to explicitly solve the particle trajectories in a Lagrangian reference system. The simulation results confirm the hypothesis of fracture initiation and sand failure near the injector. The results show that the polymer-driven fracture initiation is associated with sand shear failure, while the fracture geometry is the result of the localization of sand shear failure and fluidization of unconsolidated sand at the fracture tip. The injection of a viscous fluid can create fractures in the direction perpendicular to the applied minimum principal stress. The presence of fractures increases the injectivity. The peak injection pressure is more than 3 times greater than the applied minimum principal stress. The viscosity increase of polymers promotes the initiation of fractures and results in a greater fracture aperture. The injection of polymer can promote the initiation of fractures, and therefore, increase the polymer injectivity. This work, for the first time, uses a grain-scale model to predict polymer-driven fracture initiation and demonstrates the improved injectivity observed in the field.
A Methodological Workflow for Assessment and Design of a Huff-N-Puff Hydrocarbon Gas Injection Pilot Test as an EOR Technique for Eagle Ford Shale Oil Reservoirs
Authors: Baldwin Amanda , Lasecki Leo , Mohrbacher David , Porter Lee , Tatarin Triffon , Nicoud Brian , Taylor Grant , Zaghloul Jose , Basbug Basar , Firincioglu Tuba , Barati Ghahfarokhi Reza 
Published: August 2020

Abstract
Implementation of miscible gas huff and puff (HnP) for Improved Oil Recovery (IOR) requires timely identification of prospective projects, a demonstration of economic feasibility through pilot testing, and efficient scale-up of HnP operations. HnP pilot design and execution of the pilot project requires a minimum of 9 to 12 months to procure, and another 8 to 12 months to construct and operate. A substantial capital investment, approximately $1 to $5 million per pilot well, is also required (Texas Railroad Commission & Industry Operators). The lead time for procuring specialized compression can require 9 to 15 months. These early purchases comprise a large proportion of project capital investment.
Collaboration by a variety of technical disciplines is required to efficiently design, construct, and operate a pilot with the goal of expanding IOR operations. An effective, collaborative approach allows for development of a HnP design that integrates both subsurface and surface design criteria.
A workflow for design of HnP pilot testing was developed to coordinate concurrent project efforts including completion of reservoir characterization, engineering, permitting, stakeholder review and approvals, gas contracting, construction, testing and full-scale execution. Effective coordination of these efforts will result in efficient project implementation with minimal impacts on project scope, schedule and cost. Use of the workflow also allows for timely identification and mitigation of multiple project risks associated with design, construction and operation of IOR.
Well executed pilot tests will accelerate the learning curve for application of HnP IOR in Eagle Ford wells; resulting in lower capital costs, lower operating costs, and increased operational reliability. Pilot test results will also be used to up-scale IOR operations in a cost-effective manner.
A Single-Parameter Approach for Upscaling Relative Permeabilities for Viscous Oil Simulations
Authors: Doorwar Shashvat , Ambastha Anil 
Published: August 2020

Abstract
For very viscous oils (&gt;500cp), a stable polymer flood is not economical due to low processing rates. In such cases, a partially stable (mobility ratio &gt;1) polymer flood must be designed. Depending on the magnitude of viscosity ratio, these displacements will be influenced by viscous fingering. Typically, viscous fingers cannot be accurately captured with the grid sizes used in full-field simulations. To optimize and design a partially-stable polymer or water flood, it is critical to correctly upscale the laboratory-generated relative permeability curves for reservoir simulation. In recent years, such models have been published in SPE literature. Unfortunately, most of these models require multiple fitting parameters (3+). In this work, we present a simplified technique that requires systematic change in only one parameter to generate upscaled relative permeability curve for a given viscosity ratio.
Using fine-grid simulations, we show that due to small-scale random heterogeneities, the flow at high viscosity ratio is channelized even in a core perceived to be homogeneous at laboratory scale. Upscaling averages these fine variations in heterogeneities, causing the grids to be over-swept, and thus the recovery is over-predicted. To compensate for this over-prediction, relative permeability curves need to be upscaled.
The Theory Exploration and Practice Research of a Novel Particle Type Microgel Flooding Technology
Authors: Sun Zhe , Kang Xiaodong , Zhang Jian , Wei Zhijie , Hua Zhao 
Published: August 2020

Abstract
The theoretical basis of traditional polymer flooding technology is to improve the viscosity of displacement phase, in order to enhance oil recovery significantly. However, polymer solution is a continuous phase viscous fluid, and it cannot distinguish the large or small pore, which causes the damage in low permeability layer. Furthermore, it leads to the "entry profile inversion" phenomenon and the reduction of injection and liquid production capacity in the field application. Aiming at these problems, a novel particle type microgel (self-adaptive microgel) flooding technology has been developed in recent years.
The appearance of self-adaptive microgel is spherical. And it is dispersed in water when displacing oil. Firstly, in this paper its basic physical and chemical properties were studied. Then the pore scale mechanism model of reservoir is used to simulate the flooding process of traditional polymer and self-adaptive microgel, which proves the mechanism advancement of self-adaptive microgel flooding. On this basis, the oil displacement effect evaluation was carried out by the macro physical simulation experiments. Furthermore, this technology has been applied in 8 reservoirs with different conditions.
Results show that, self-adaptive microgels have good water swelling properties. They expand rapidly in the initial stage, and then gradually tend to be stable. Secondly, the pore scale simulation experiment shows that, microgel particles present the motion feature of "migration, trapping, deformation" in the porous media. Meanwhile, the particles gather in the larger pore to form the bridge block, and their carrier fluid displace oil in the small pore. So they work in cooperation, which can reduce the flow ability of water phase in the big pore and improve the flow ability of residual oil in small pore. Furthermore, the 3D macro physical simulation experiment shows that, self-adaptive microgel flooding can achieve better oil displacement effect than polymer flooding. Finally, this technology has been applied in 8 oilfields with different conditions, which contains the reservoir temperature from 24 to 126 °C, crude oil viscosity from 1.36 to 156 mPa.s, water cut from 81.4% to 97.5% and recovery degree from 9.55% to 64.4%. And they all obtain good technical and economic effect, with the lowest input-output ratio of 1.67 and the highest of 14.37.
Summing up the lab studies and field trial, the new particle-type microgel flooding technology is more efficient and progressiveness. Therefore, its mechanism and performance are further studied in this paper. Meanwhile, its field trial effects are explored and analyzed. The research results provide theoretical basis and technical support for the popularization and application of self-adaptive microgel flooding technology, which may also provide some reference for oil companies to make a wise investment decision in low oil price period.
Evaluation of Eagle Ford Cyclic Gas Injection EOR: Field Results and Economics
Authors: Grinestaff George , Barden Chris , Miller Jeff , Franklin Wes , Barden Christopher , Ding Eric 
Published: August 2020

Abstract
Eagle Ford Cyclic Gas Injection EOR (CGEOR) was started in late 2012, by EOG Resources, and has expanded to over 30 leases by 6 operators (266 wells) to date where produced gas is being injected. An extensive EOR evaluation was initiated by Shale IOR to understand results for these leases. This paper will provide a summary of EOR production evaluation results, pilot history match, and economics for two Eagle Ford projects through June 2019. All production, injection volumes, and other data were obtained from the Texas Railroad Commission. These pilots and commercial projects represent a range of outcomes.
We evaluate base decline EUR and incremental IOR oil production. Detailed compositional simulation is used to understand process PVT phase behavior and make accurate well and unit production profiles which guide our understanding of field results. We explain the process to predict project profiles and generate rigorous cash flows to understand economic drivers.
Results of this study show that CGEOR throughout the Eagle Ford volatile oil can yield an additional 30% to 90% increase in EUR with robust economics, depending on compressor utilization and field life. The CGEOR process appears to be working without any failures thus far in the Eagle Ford, however, phase behavior must be understood along with operational efficiency in order to achieve good economics. Eagle Ford field results show that compressor and well operations are key to production efficiency as oil production closely follows gas injection volumes. These results should also be helpful to build upon knowledge in other unconventional basins.
The CO2 Foam Stability Enhancement with Switchable Surfactant and Modified Silica Nanoparticles
Authors: Zhang Xuan , Wang Yanqing , Da Chang , Ge Jijiang , Zhang Guicai , Jiang Ping , Pei Haihua 
Published: August 2020

Abstract
When the silica nanoparticles (NPs) were modified with Glymo silane, the surface charge of NPs would change along with the silane coverage, which has an effect on the interaction with switchable surfactants. This study focused on the electrostatic force between the switchable surfactants and modified silica NPs with different coverage scale. At low pH 4.5, the ethoxylated amine surfactants switched to protonated state with quaternary ammonium group, that contains positive charge. However, when the silane coverage was higher than 1.0 µmol/m2, the mixing solution could keep stable at 80°C due to the fewer negative charge at the NPs surface even in DI water. With increasing the ethylated groups of the switchable surfactant, the solution was more stable, which could be interpreted that the quaternary ammonium with positive charge was hindered by long EO chain. The bulk foam half-life extended twice with adding NPs in the surfactant solution, which proved that the CO2 foam was more stable and when the solution was slightly cloudy, the foam stability enhancement was more obvious, since the NPs more likely adsorbed at the CO2-liquid interface and enhanced the lamella stability at this state. Moreover, after adding NPs, the foam viscosity in sand-pack increased 1.5-2 times, comparing with surfactant alone and depended on the silane coverage of NPs, where the NPs with lower silane coverage have more positive effect on the foam stability enhancement. The mixing formula makes it possible to enhance CO2 foam stability at low pH and given high salinity, which is important to reduce gas mobility in reservoir conditions and, eventually, enhance oil recovery.
Measurements of Three-Phase Relative Permeability as a Function of Fluid Composition
Authors: Churchwell Lauren , Radhakrishnan Anuradha , DiCarlo David 
Published: August 2020

Abstract
Accurately modeling three-phase relative permeability remains a great challenge to reservoir engineers, in part because of a lack of experimental data to use when verifying model results. This is especially true when the fluids are changing composition, such as for miscible gas injection, when many simulator models have difficulty identifying the phases and sometimes do so incorrectly, causing inaccurate results or even crashing the simulator. Recently, there has been a shift away from labeling phases as simply "oil" and "gas", and instead labeling them according to a physical property that is continuous and tied to composition, such as density or the Gibbs free energy (GFE) of the fluid. In this research, we measure three-phase oil and gas relative permeability as a function of the fluid's GFE. We see from our results that composition changes can cause big shifts in the relative permeability curves, however, the relative permeability parameters are non-monotonic with respect to the Gibbs free energy. More experimental data will be needed to further study the GFE model and the nature of the composition effects.
Novel Insights into Low Salinity Water Flooding Enhanced Oil Recovery in Sandstone: The Role of Calcite
Authors: Al-Saedi Hasan N. , Al-Jaberi Soura K. , Flori Ralph E. , Al-Bazzaz Waleed 
Published: August 2020

Abstract
In recent years, many researchers reported that water flooding recovery factor increased by injecting low salinity (LS) water into sandstone reservoirs, but the mechanism of improved recovery using LS water is still a topic of debate. Recently we studied the role of clays and their impact on oil recovery during LS water flooding into sandstone. This paper qualifies the calcite role and the vital role of pH in the water flooding of LS water in sandstone with and without calcite as a function of temperature.
Four chromatography columns composed dissimilar amount of quartz and calcite (100% quartz; 100% calcite; 10% calcite + 90% sand; 20% calcite + 80% sand) were water flooded with high salinity (HS) water followed with LS water at two different temperatures 25 and 90°C and measuring the effluent Ca2+ and CH3COO- and pH. The columns with the minerals inside were then aged for a week at 70°C with 0.01 molar (M) sodium acetate to mimic the bonding of oil-bound carboxylic acids with the reservoir. To qualify the calcite impact, a 100% calcite and calcite-free samples were investigated; the detected acetate and Ca2+ in the effluent were, approximately, in the same range of other columns.
Characteristically, a higher calcite content saw a considerable upsurge in pH. Still, the calcite-free samples also saw an increase in pH, as high as that of the calcite-containing cores. There was a general decrease in calcite dissolution, ion exchange, and pH increment when the test temperature increased for all experiments. The positively charged –COOCa+ group released from SiO– when LS water injected into sand only column, and as the calcite concentration increases, the calcite dissolution increases, and the carboxylic acid releasement increases too.
The approach of this work is that it allows us to isolate the interplay between ion exchange, pH, and carboxylate release, which should allow us to better decode the chemical mechanisms that control LS water flooding.
Thermo-Sensitive Nanogels for Targeted Tracer Release in Push and Pull Operations
Authors: Panneer Selvam Arun Kumar , Ould Metidji Mahmoud , Silva Mario , Krivokapic Alexander , Bjørnstad Tor 
Published: August 2020

Abstract
The single-well chemical tracer test (SWCTT) is widely used in the determination of residual oil saturation (SOR) in the near-well region. SWCTTs typically require large amounts of chemicals and some days of well shut-down. In the present paper, we propose using thermo-sensitive nanogel carriers for targeted release of tracers for SWCTTs. This approach has the potential to significantly reduce the time and amount of chemicals required by a SWCTT.
The targeted tracer release method was inspired by previously developed drug delivery applications using stimuli-sensitive nano-capsules. Nanoparticles loaded with medical cargo were synthesised to target specific sites. The release of the active principles would then be triggered by an in-situ (temperature, pH) or ex-situ (magnetic field, light) stimuli. A novative approach to address the current limitation of classical SWCTT is based on the biomedical background. It consists in using a poly-N-isopropylacrylamide (pNIPAm) based nanogel, known for its thermo-sensitive nature, to ensure the in-situ delivery of tracer molecules. This effect is explored as a mechanism to both load and release the tracers for a SWCTT.
PNIPAm nanogels or hydrogels are highly hydrophilic, cross-linked polymeric networks. When the temperature of the solution is increased above the lower critical solution temperature (LCST) of PNIPAm molecule, the capsules exhibit a reversible collapse effect, causing the release of the tracer molecules. The hydrodynamic diameters of capsules were measured using Dynamic Light Scattering (DLS) and were found to be 195 nm at 25 °C and 73 nm at 45 °C. The nanogels exhibit a reduction in volume to 8 times when the temperature is increased from 25 °C to 45 °C. This change in volume acts as a lock-in mechanism once the tracer is loaded and open-up to release loaded tracers. The study of the encapsulation and release of tracer compounds was achieved using passive and partitioning tracers loaded into the structures. The capsules showed a significant tracer loading efficiency. For studying the release rate and mechanism, increase in temperature was used to trigger the release of tracers.
Although the SWCTTs are the most used tracer tests by the oil industry, their development have been relatively slow since it was originally introduced in 1973 (Deans 1971). The present study aims at presenting a novel approach on how nanotechnology can be used to reduce the large amounts of chemicals and time required by classical SWCTTs. Concepts and results about the synthesis of the nano-carriers, loading and releasing of the tracers are presented and discussed.
Thermally Induced Microfractures and Improved Recovery from Shale
Authors: Griffin Don P. , Rietz Dean C. , Palke Miles R. 
Published: August 2020

Abstract
The feasibility of creating thermally induced microfractures in shale is investigated. The Ideal Gas Law with modification for real gases and the Heat Transfer Equation in one-dimension are utilized to determine times, distances and temperature requirements needed to generate microfractures. Geologic and experimental data are gathered from the literature in support of our results. Heat sources are examined; operational problems are identified; and various applications are suggested. Emphasis is placed on creating zones of microfractures (soft spots) which can be exploited by hydraulic fracturing, potentially increasing the hydrocarbon recovery of the shale formation.
Hydraulic Fracturing Test Site HFTS Phase-2 EOR Pilot: Huff-and-Puff Pilot in the Permian-Midland Basin
Authors: Salahshoor Shadi , Ciezobka Jordan 
Published: August 2020

Abstract
The Hydraulic Fracturing Test Site (HFTS) in the Permian-Midland basin has bridged the gap between inferred and actual properties of in-situ hydraulic fractures by recovering almost 600 feet of the whole core through recently hydraulically fractured upper and middle Wolfcamp formations. In total, over 700 hydraulically induced fractures were encountered in the core and described, thus providing indisputable evidence of fractures and their attributes, including orientation, propagation direction, and composite proppant concentration. This fracture data, along with the collected diagnostics, support testing and calibration of the next generation fracture models for optimizing initial completion designs and well spacing. In addition, with a massive number of existing horizontal wells in the Permian, the collected data is also useful for designing and implementing enhanced oil recovery (EOR) pilots to improve resource recovery from the existing wells. It is known from the literature that the primary recovery from the shale wells is typically about 5-10% of the original oil in place. Therefore, tremendous potential exists in the Permian to recover additional hydrocarbons by implementing appropriate EOR techniques on the existing wells. To explore this concept, Laredo Petroleum and GTI have agreed to perform HFTS Phase-2 EOR field pilot near the original HFTS, supported by funding from the U.S. Department of Energy and industry sponsors. The Phase-2 EOR field pilot involves injecting field gas into a previously fracture stimulated well in order to produce additional oil using huff-and-puff technique. During the course of the EOR experiment, a second slant core well was drilled near the injection/production well to capture and describe some of the fractures which served as a conduit for the injected gas field during the injection or "huff" period and the produced fluids during the production or "puff" period. The overreaching goals of the HFTS Phase-2 EOR experiment is to determine the effectiveness of cycling gas injection in increasing the oil and gas recovery from the Wolfcamp shale. Specific objectives included: 1. Drill, core, and instrument a second slant core well to describe the fracture network in the vicinity of an EOR injector/producer well 2. Perform laboratory experiments to determine the phase behavior, including black oil study, slim tube analysis, swell testing, etc. 3. Demonstrate how natural gas and/or CO2 increases the oil recovery from Wolfcamp shale through core flooding experiments 4. Determine if pre-existing stimulated horizontal wells can be re-pressurized above the miscibility pressure using the field gas 5. Perform numerical 3D reservoir simulations to predict EOR injection/production performance 6. Instrument offset wells and collect diagnostic data during the cyclic gas injection and production test. This paper describes the EOR field pilot along with the collected data and performed analyses noted above.