bluuebunny/crossref_metadata_2025 huggingface dataset:
Numerical Simulation of Crossed-Linked Polymer Injection in Dina Cretaceous Field: A Real Field Case Study
Authors: Izadi Mehdi , Jimenez Jaime Alberto , Zapata Jose Francisco , Felipe Castillo Andres , Pinto John , Vicente Sebastian
Published: August 2020

The main objective of this work is to shed light on the mechanism of modeling crossed-linked polymer (CLP) technology, by incorporating real field pilot injection and production data in the Dina Cretaceous field located in the Upper Magdalena Valley (UMV) Basin in Colombia. The paper will highlight why original simulation model predictions differ from the actual observed field data and the predictability of numerical simulation of CEOR process would be discussed and presented. Despite successful application and positive field results in the literature, the propagation of CLP system in porous media has been challenged with conflicting opinions and reports and still remains debatable and uncertain.

This paper will use recent experimental laboratory data in conjunction with actual field data to properly explain the possible mechanism of CLP and offer practical modeling techniques to capture experimental and field data. Therefore a modeling methodology was developed and used to model the field data, this method is based on previous modeling mechanisms with incorporating a new grid-based residual resistance factor (RRF) and pore throat sizes. The model requires a proper understanding of rock typing and populate the permeability distribution based on pore throat sizes. The new modeling mechanism was able to reasonably predict the pilot performance in some of the offset producers.

To model delayed viscosification and adsorption of the CLP process, two approaches has been evaluated and used in the original simulation model, the use of multiple regions and chemical reaction. The chemical reaction rate is tuned to calibrate laboratory data and to model the delayed viscosification and RRF. However recent laboratory experiments explained the possible mechanisms of CLP formation through intra-molecular crosslinking and intra-inter-molecular crosslinking.

In conclusion, because of extensive and numerous laboratory experiments and the conduct of field pilot results, proposed numerical modeling demonstrate the complexity of modeling the CLP system and offers a practical solution to the field applications.
An Investigation into Fluid-Fluid Interaction Phenomenon During Low Salinity Waterflooding using a Reservoir-on-a-Chip Microfluidics Model
Authors: Tetteh Joel T. , Aryana Saman A. , Barati Ghahfaorkhi Reza
Published: August 2020

Injection of modified salinity brines modified salinity brines (MSB), i.e. brine with seawater-like salinity (SWS) and low salinity water (LSW) in oil-wet carbonate rocks is relevant to improved oil recovery operations. Many reports in the literature relate the underlying mechanisms to rock-fluid interactions such as ionic exchange and electrical double layer expansions, which cause wettability alterations at the rock surface. Little attention seems to have been placed on fluid-fluid interactions as a potential mechanism in displacement processes.

In this work, we investigate the role of fluid-fluid interactions in improved oil recovery using MSBs. Interfacial tension and surface elasticity calculations are correlated to visual observations of displacement processes to investigate the role of crude oil snap-off. A series of microfluidic chips featuring pore throats that are 50μm in diameter are used to observe snap-off as a function of salinity in the displacing fluid. The flow experiments suggest that, in a water-wet constricted pore throat, SWS brines suppress crude oil snap-off as compared to FWS brine. This behavior is correlated to the higher surface elasticity of oil-SWS interface than that of oil-FWS interface. Higher surface elasticity suppresses the expansion of the thin water film coating pore throat walls and hence increases the capillary number at which snap-off of the crude oil phase is expected to occur.

Moreover, water interacts with the polar components to form reverse micelles called microdispersions. These microdispersions are observed in the aged chip near the oil-brine interface in the pore-network of a microfluidic device. Similarly, in a vial test performed by Tetteh and Barati, (2019), microdispersion formation was only observed very close to the oil-brine interface, caused by the transport of water molecules into the oil phase. These microdispersions remobilize and redistribute the oil, and along with a slight change in wettability in the medium, they improve the observed recovery. In the pore-network flow experiments, the use of SWS brines resulted in the formation of relatively larger oil droplets, which is attributable to the suppression of crude oil snap-off and enhanced oil coalescence resulting from changes in oil-brine interfaces. The integrated experimental study presented in this work demonstrates the importance of fluid-fluid interactions in improved oil recovery using MSBs.
Pulser Model: Updated Framework and Lessons Learned from Applications in Forecasting CO2 Flood Performance
Authors: Kumar Deepanshu , Bandyopadhyay Parag
Published: August 2020

Reservoir management of Carbon Dioxide-Enhanced Oil Recovery (CO2-EOR) floods is essentially an optimization problem-maximizing the oil recovery while simultaneously minimizing the CO2 injection volumes. Liu et al. (2014) proposed a parametric model of recovery factor as a function of miscible CO2 injected in dimensionless form. Incorporating the lessons learned from application of the model for production forecasting of multiple CO2 floods across the Permian basin, the updated model has better predictive power over the life of the flood. Results from applications to actual field data are also presented.

The Pulser Model is linearized, which allows for faster solution and robust convergence. Algorithmic nuances for regression are described. A physical interpretation of the model parameters is explored so as to facilitate physics-constrained optimization. This allows calibration of parameters to data such as heterogeneity (from core) and CO2 storage capacity of the rock. Sensitivity analysis of model parameters is conducted on field data sets to evaluate relative and physical significance of the model parameters.
Development of Surfactant Formulation for Harsh Environment
Authors: Pinnawala Gayani , Nizamidin Nabijan , Spilker Kerry , Linnemeyer Harold , Malik Taimur , Dwarakanath Varadarajan
Published: August 2020

Good phase behavior is critical for identifying high performance surfactant formulations for coreflood recovery. For conventional CEOR projects, good phase behavior entails high solubilization parameters, rapid equilibration to low viscosity microemulsions and aqueous stability of aqueous surfactant mixtures. For reservoirs with harsh conditions, i.e high temperature (> 90°C), high salinity (>50,000 ppm TDS), high divalent ions (> 1500 ppm TDS), high GOR (>150) and presence of H2S, developing formulations with good phase behavior is challenging. Several carbonate reservoirs have conditions as outlined above and the scarcity of formulations that are stable in the above-described conditions makes surfactant applications challenging. We present results that show the development of surfactant formulations that show good behavior under harsh conditions. We validate the performance with a combination of phase behavior, thermal stability, and coreflood experiments and show that high-performance surfactants can be developed for harsh reservoir conditions.
Improving CO2 Vertical Sweep Efficiency in Tinsley Field with Dedicated Injectors
Authors: Sheikha Hussain , Blackmer Scott Mitchell , Sharaf Essam , Marks Dustin
Published: August 2020

Lower oil production rate, conformance, and poor sweep efficiency are major concerns in an enhanced oil recovery (EOR) flood when implemented across multiple intervals. Oil recovery and flood performance in reservoirs with multiple lobes characterized by heterogeneous rock properties suffer greatly when the lobes are commingled. Tinsley Field is a reservoir with two distinct lobes. Initial development of the EOR flood commenced by commingling injection in the same wellbore and production from the two lobes to decrease the capital cost and boost oil production. Reservoir management of the CO2 flood indicated good sweep was taking place in one lobe. Concerns about the possibility of early breakthrough of CO2 in the dominate lobe, leaving stranded oil in the other lobe, prompted the initiation of a dedicated injection program. Early breakthrough could lead to filling up our compressors more quickly than anticipated, which could increase our capital requirements. Dedicated injection into individual lobes was initiated to improve the sweep efficiency.

The team devised a methodology to select prospective wells and quantify the feasibility of adding new dedicated injectors in some of the existing patterns at Tinsley field. The methodology utilized a combination of geological cross sections to identify areas that are characterized by two lobes separated by a shale barrier or baffle, injection profiles to identify the current CO2 allocation, and an estimation of remaining oil in place. A sector model was constructed to simulate the recovery process and aid in understanding the impact of dedicated injection on oil production rate and recovery from individual lobes.

The study revealed that only two of the three fault blocks can be characterized with an upper and lower lobe. Within those two fault blocks, several producers were identified as having poor conformance with a high remaining oil in place. Numerical results of the simulation model show that without dedicated injectors, the two lobes will be flooded at two different injection rates leaving substantial oil unrecovered because of the different injectivity of each zone. Candidate dedicated injectors were selected and ranked for execution based on our methodology. The early results from the dedicated injection program indicate it will lead to a higher recovery factor in the lower lobe because of dedicated injection into the lower lobe resulting in higher processing rate of CO2.

The methodology presented in this paper provides a logical workflow that can identify areas with stranded oil in a reservoir with multiple zones. Following this process could lead to opportunities to drill dedicated injectors to improve oil production rate, conformance, and recovery factor.
Containment of Water-Injection-Induced Fractures: The Role of Heat Conduction and Thermal Stresses
Authors: Hwang Jongsoo , Zheng Shuang , Sharma Mukul , Chiotoroiu Maria-Magdalena , Clemens Torsten
Published: August 2020

Reservoir cooling by water or waste-water injection can significantly alter the reservoir stress. The out- of-zone fracture growth is substantially affected by this poro-thermo-elastic stress changes occurring in heterogeneous rock layers. No previous study, however, systematically investgated the influence of heat conduction and convection on the associated stress alteration and fracture height growth during the long- term water injection in multiple layers. Without understanding this coupled effect, which occurs over a long-term fracture propagation, it is difficult to capture the conditions for the fractures to breach into the bounding shale layers.

In this paper, we present that the thermal conduction between the injection sand and bounding shale is crucial in predicting the fracture containment during water injection. We developed a fully coupled compositional reservoir/fracturing simulator that solves poro-thermo-elasticity. We used it to simulate 3- dimensional fracture propagation induced by cold water injection and, at the same time, calculate the stress field influenced by the thermo-poro-elastic effect in heterogeneous reservoir layers. Effective stress in the bounding layer is dynamically updated to capture the poro-thermo-elastic effect and associated fracture height growth. We first validate our model with existing analytical solutions and studied a field case. We identify the effects of fluid properties, rock properties, and injection temperature on stress changes and the fracture containment for the first time.
Transport of Biopolymer Scleroglucan in Cores at HTHS Conditions
Authors: Song Haofeng , Mohanty Kishore K.
Published: August 2020

Polymers are extensively used in chemical EOR processes to provide mobility control. Both synthetic polymers (e.g., HPAM) and biopolymers (e.g. Xanthan, Scleroglucan) are used. HPAM and Xanthan, do not show high temperature and high salinity (HTHS) tolerance. The purpose of this study is to evaluate temperature and salinity tolerance of an EOR grade biopolymer, Scleroglucan at HTHS conditions (100 °C and sea water salinity) and study its transport through medium permeability rocks (200-500 mD). In the absence of oxygen and glutaraldehyde, the Scleroglucan solution prepared in synthetic seawater, maintained its viscosity at 100 °C for at least two months. In the presence of a biocide, glutaraldehyde, the biopolymer degraded at 100 °C. Transport of this biopolymer was studied in both Indiana limestone (200~500 mD) and Berea sandstone (~300 mD) cores at 100 °C. The results suggest transport in porous media (~200 mD) without inducing any face plugging.
Bhagyam ASP Pilot: Successful Formulation Development to Pilot Design and Planning
Authors: Jain Shakti , Prasad Dhruva , Pandey Amitabh , Koduru Nitish , Raj Rahul
Published: August 2020

The paper discusses the alkaline surfactant polymer (ASP) flood pilot design including formulation development, pilot area selection, well and pattern type, slug size and sequence, slug viscosity etc for the Bhagyam field. It also discusses the various lab, well and reservoir surveillance techniques planned for the baseline, ASP flood monitoring, residual oil saturation and incremental recovery estimates from the pilot.

The Bhagyam is an onshore field in the Rajasthan state of western India and is part of Mangala-Bhagya m- Aishwariya (MBA) development in the Barmer basin. The main producing unit is Fatehgarh multi -storied fluvial sand stone. Reservoir quality is excellent with permeability in the range of 1 to 10 Darcy and porosity in the range of 25-30%. The crude oil is moderately viscous (15 to 500 cP) and highly active with TAN (total acid number) value of ~2 mgKOH/gm. All the reservoir and fluid properties together with low salinity (5000 ppm) and moderate temperature (54 degC) makes it an ideal candidate for polymer and ASP EOR methods. The field has been developed with downdip water injection and post successful evaluation of long term polymer injectivity test, it is currently under full-field polymer flood implementation. The details of polymer flood injectivity and full-field expansion plans are discussed by Sharma et. al. 2016 and Shankar et. al. 2018.

EOR assessment has been part of the field development planning process from start. Multiple phase behaviour studies and corefloods have been conducted to screen the surfactant and generate necessary parameters for the simulation studies. The formulation consists of combination of sulfate and sulfonate based surfactants. The focus of the pilot area selection has been to utilize the existing well s to maximum possible extent, reduce the geological uncertainty and minimize the interference from ongoing activity in the field. A normal 4 spot pilot with ~150m spacing has been selected together with two observation well for time lapse saturation monitoring and one coring well towards end of pilot for saturation determination.

Dynamic models have been used to design slug size, sequence, viscosity and estimate incremental oil potential. Multiple tracer surveys together with distributed pressure measurements and interference tests are planned to establish connectivity and calibrate model. Initial estimates of pilot incremental oil recovery is in the range of 15-25% of stock tank oil intial in-place (STOIIP) over the polymer flood. Overall pilot design aims at collecting all the necessary data for reducing uncertainty for full-field expansion in a short time frame.
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

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

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

For very viscous oils (>500cp), a stable polymer flood is not economical due to low processing rates. In such cases, a partially stable (mobility ratio >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

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

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

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

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

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

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

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

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.
Surfactant in Fracturing Fluid: Enhancing Imbibition Oil Recovery or Blocking Pore Throats?
Authors: Yousefi Mohammad , Habibi Ali , Dehghanpour Hassan
Published: August 2020

Low recovery of fracturing water is partly due to fracturing fluid leak-off into formation and water trapping in matrix. In our previous studies (Soleiman Asl et al. 2019 and Yuan et al. 2019), we showed that using surfactant solutions in fracturing fluid can significantly enhance imbibition oil recovery. However, there is one critical question remained unanswered: What are the consequences of these additives on well performance during flowback and post-flowback processes? Can they block the pore-throats of rock matrix and induce formation damage? To answer this question, we develop and apply a comprehensive laboratory protocol on a tight core plug to simulate leak-off and flowback processes under reservoir pressure, with and without initial water saturation (Swi). We evaluate the possibility of pore-throat blockage by comparing pore-throat size distribution of the core plug and size distribution of the particles formed in a microemulsion (ME) solution. We also investigate the effects of Swi on effective oil permeability (koeff) after the flowback process.

The results of leak-off and flowback tests using tap water as the base case shows that koeff after flowback is lower than that before the leak-off, mainly due to phase trapping. However, results of the tests using the ME solution show that koeff after flowback is greater than koeff before leak-off. This observation suggests that the leak-off of ME solution enhances regained oil relative permeability during flowback by reducing phase trapping and water blockage. When Swi = 0, the blockage of leaked-off fluid reduces koeff during the flowback process. The mean size of self-assembled structures (referred to as "particles" here) formed by mixing the ME solution with water is around 10-20 nm. The MICP profile of the core sample shows that around 95% of pore throats are bigger than the size of formed particles, suggesting low chance of pore-throat blockage by the suspended particles.
Long noncoding RNA XIST suppresses tumorigenesis and enhances radiosensitivity in neuroblastoma cells through regulating miR-653-5p/HK2 axis
Authors: Mou Liping , Wang Lili , Zhang Shaoming , Wang Qinghua
Published: August 2020

Background: Abnormal expression of long noncoding RNAs (lncRNAs) was usually involved in tumorigenesis and radiosensitivity of various cancers. The aim of this study was to explore the biological function and regulatory mechanism of lncRNA X-inactive specific transcript (XIST) in tumorigenesis and radiosensitivity of neuroblastoma (NB).Methods: The expression levels of XIST, microRNA-653-5p (miR-653-5p) and hexokinase 2 (HK2) were detected by quantitative real-time polymerase chain reaction (qRT-PCR). Methylthiazolyldiphenyl tetrazolium bromide (MTT) assay, colony formation assay and transwell assay were utilized to detect cell viability, colony formation and cell invasion abilities. Glucose consumption or lactate production was measured by glucose assay kit or lactate assay kit, respectively. The mice xenograft model was established to investigate the role of XIST in vivo. The interaction between miR-653-5p and XIST or HK2 was predicted by starBase v2.0 and verified by dual-luciferase reporter, RNA Immunoprecipitation (RIP) and RNA pull-down assays. Western blot was used to measure the protein expression of HK2.Results: XIST and HK2 were highly expressed whilst miR-653-5p was lowly expressed in NB tissues and cells. XIST knockdown inhibited tumorigenesis by repressing NB cell proliferation and invasion. Meanwhile, XIST downregulation increased the radiosensitivity via inhibiting colony formation rates and glycolysis. Moreover, miR-653-5p could bind to XIST and its downregulation reversed the effects of XIST knockdown on tumorigenesis and radiosensitivity. Additionally, HK2 was a direct target of miR-653-5p and its overexpression attenuated the effects of miR-653-5p restoration on suppression of tumorigenesis and promotion of radiosensitivity. Besides, XIST functioned as a molecular sponge of miR-653-5p to regulate HK2 expression. Furthermore, XIST knockdown also suppressed tumor growth by upregulating miR-653-5p and downregulating HK2 in vivo.Conclusion: XIST interference inhibited tumorigenesis and increased radiosensitivity in NB by regulating miR-653-5p/HK2 axis, providing a novel therapeutic strategy for NB.
Tanshinone IIA Attenuates Inflammatory Responses by Downregulating MicroRNA-23b, Upregulating TRIB1 and Inactivation of the TLR4/NF-κB Signaling Pathway in THP-1 Macrophages
Authors: Ji Wei , Li Gengyao , Liu Yuqian , Yan Xiaofeng
Published: August 2020

The authors have withdrawn this preprint due to erroneous posting.
MicroRNA-520a discourages lung cancer pathogenesis and progression involving the downregulation of RRM2 and Wnt signaling deficits
Authors: Xie Yi , Xue Congyu , Guo Shuai , Yang Lei
Published: August 2020

The authors have withdrawn this preprint due to erroneous posting.
Pharmacokinetic herb-drug interactions between Aidi injection and Doxorubicin in rats with diethylnitrosamine-induced hepatocellular carcinoma
Authors: Lu Yuan , Pan Jie , Zhu Xiaoqing , Zhang Shuai , Chunhua Liu , Sun Jia , Li Yueting , Chen Siying , Huang Jing , Cao Chuang , Wang Yonglin , Li Yongjun , Liu Ting
Published: August 2020

Background: Aidi Injection (ADI), a Chinese herbal preparation with anti-cancer activity, is used for the treatment of hepatocellular carcinoma (HCC). Several clinical studies have shown that co-administration of ADI with doxorubicin (DOX) is associated with reduced toxicity of chemotherapy, enhanced clinical efficacy and improved quality of life for patients. However, limited information is available about the herb-drug interactions between ADI and DOX. The study aimed to investigate the pharmacokinetic mechanism of herb-drug interactions between ADI and DOX in a rat model of HCC.Methods: Experimental HCC was induced in rats by oral administration of diethylnitrosamine. The HCC rats were pretreated with ADI (10 mL/kg, intraperitoneal injection) for 14 consecutive days prior to administration of DOX (7 mg/kg, intravenous injection) to investigate pharmacokinetic interactions. Plasma concentrations of DOX and its major metabolite, doxorubicinol (DOXol), were determined using ultra-performance liquid chromatography-tandem mass spectrometry (UPLC-MS/MS).Results: Preadministration of ADI significantly altered the pharmacokinetics of DOX in HCC rats, leading to increased plasma concentrations of both DOX and DOXol. The area under the plasma drug concentration-time curve (AUCs) of DOX and DOXol in rats pretreated with ADI were 3.79-fold and 2.92-fold higher, respectively, than those in control rats that did not receive ADI.Conclusions: Increased levels of DOX and DOXol were found in the plasma of HCC rats pretreated with ADI.
Lived experience of women who underwent early removal of long-acting Contraceptive Methods in Bedesa town, Wolaita Zone, Southern Ethiopia: A phenomenological study
Authors: Obsa Mohammed Suleiman , Takiso Kassahun Tekle , Ayele Tamiru Tilahun , Koyra Hailu Chare , Hidota Kasahun Tafesse , Shanka Getahun Molla , Hanfore Lolemo Kelbiso , Arba Mihiretu Alemeyehu , Anjulo Antehun Alemeyehu , kanche Zewde Zema , kercho Melkamu Worku
Published: August 2020

Background Long-acting contraceptive methods can play a pivotal role in reducing maternal mortality. In Etiopia, the total fertility rate per woman is 4.6. However, this rapid population growth is not in line with the weak economic growth of the country. Therefore, this study was done to explore the lived experiences of women who underwent early removal of long-acting contraceptive methods in Bedesa town, Southern Ethiopia. Methods A phenomenological study design was employed to include a total of 10 in-depth interviews of sampled women. Participants were recruited through criterion sampling method. Open code version 4.03 was used to code and facilitate analysis. Transcripts were read and re-read separately to identify emerging themes. Thematic analysis technique was used. Results This study revealed that the side effect of the long-acting family planning methods were the main reason for early removal. Furthermore, heavy and irregular menses were mentioned as the most frequently occurred side effects. Delayed fertility after removal of long-acting contraceptive was one of frequently stated fear by the clients. It was also stated that counseling provided by health professionals was not adequate. Conclusion The majority of study participants taught that the side effects of long-acting family planning methods outweigh the benefits. Besides, the counseling services provided by health care providers were not adequate. Therefore, proper counseling services should be given to mothers who are taking long-acting family planning methods.