bluuebunny/crossref_metadata_2025_split huggingface dataset:
Miniature Viscosity Sensors for EOR Polymer Fluids
Authors: Gonzalez Miguel , Ayirala Subhash , Maskeen Lyla , Sofi Abdulkarim 
Published: April 2022

Abstract
There are currently no technologies available to measure polymer solution viscosities at realistic downhole conditions in a well during enhanced oil recovery (EOR). In this paper, custom-made probes using quartz tuning fork (QTF) resonators are demonstrated for measurements of viscosity of polymer fluids. The electromechanical response of the resonators was calibrated in simple Newtonian fluids and in non-Newtonian polymer fluids at different concentrations. The responses were then used to measure field-collected samples of polymer injection fluids. The measured viscosity values by tuning forks were lower than those measured by the conventional rheometer at 6.8 s-1, indicating the effect of viscoelasticity of the fluid. However, the predicted rheometer viscosity versus QTF measured viscosity showed a perfect exponential correlation, allowing for calibration between the two viscometers. The QTF sensors were shown to successfully produce accurate viscosity measurements of polymer fluids within the required polymer concentration ranges used in the field, and predicted field sample viscosities with less than 5% error from the rheometer data. These devices can be easily integrated into portable systems for lab or wellsite deployment as well as logging tools for downhole deployment.
Rapid Estimation of Carbon Dioxide Stored in CO2 EOR Operations for Screening Purposes
Authors: Carlino Andrea , Muggeridge Ann Helen , Smalley Philip Craig 
Published: April 2022

Abstract
We describe the development, testing, and first application of a rapid method for estimating the CO2 storage potential associated with CO2 enhanced oil recovery in both secondary and tertiary modes. The new method builds on various published empirical models for predicting incremental oil recovery (and hence CO2 storage) in solvent floods. It improves the representation of reservoir heterogeneity caused by depositional layering and fracturing. This is then combined with material balance to make site-specific estimates of the CO2 storage potential.
We cross-checked predictions from the new method against historical field data for major onshore CO2 floods with satisfactory results considering the very approximate nature of the estimation. We then applied the method to a selection of offshore oil reservoirs and found that, generally, the larger the remaining oil, which is a function of initial size and current recovery factor, the greater the CO2 storage potential. We also modelled the case of continued injection after ceasing oil production at, or after, CO2 breakthrough and observed that, as expected, the amount of CO2 stored at breakthrough depends on how early this occurs, which is affected by reservoir heterogeneity, whereas continued injection is limited by the headroom between current reservoir pressure and fracture pressure. The overall storage is the result of the interplay between these two mechanisms. In the studied fields/reservoirs, we demonstrated that large amounts of CO2 can be stored in terms of absolute mass and that storage of these quantities would represent significant abatement of the emissions generated by burning the incremental oil.
The new method can be used as a screening tool to identify and rank candidate oil fields for combined CO2 enhanced oil recovery and storage in regional, national, or corporate portfolios.
Novel Application of Polyethylene Oxide Polymer for EOR from Oil-Wet Carbonates
Authors: Trine Eric Brandon , Pope Gary Arnold , Britton Chris James , Dean Robert Matthew , Driver Jonathan William 
Published: April 2022

Abstract
The objective of this study was to test the performance of high-molecular weight polyethylene oxide (PEO) polymer in a low-permeability, oil-wet carbonate reservoir rock. Conventional HPAM polymers of similar molecular weight did not exhibit acceptable transport in the same rock, so PEO was explored as an alternative polymer. Viscosity, pressure drop across each section of the core, oil recovery, and polymer retention were measured. The PEO polymer showed good transport in the 23 mD reservoir carbonate core and reduced the residual saturation from 0.29 to 0.17. The reduction of residual oil saturation after polymer flooding using PEO was unexpected and potentially significant.
Methods to Improve Accuracy and Performance in a Fully Implicit Surfactant Flood Simulator
Authors: Shi Xundan , Han Choongyong , Wolfsteiner Christian , Chang Yih-Bor , Güyagüler Baris 
Published: April 2022

Abstract
Saturation distributions exhibiting unphysical "checkerboard" patterns, time-step size sensitivity, and slow convergence in certain instances are observed in a fully implicit surfactant simulator that is based on an industry-wide accepted formulation. In this paper, we discuss methods to address each of the above conditions and hereby achieve a robust algorithm with favorable convergence characteristics.
The proposed remedies are result of in-depth studies of the physics of micro-emulsion appearance and disappearance as well as detailed analysis of the numerical convergence difficulty. Our method considers wide ranges of solution variables in a typical surfactant flood simulator and critical key parameters identified by flash algorithm [Han, et al. 2017] and general non-linear solver. The details of the improved formulation are provided and should enable readers to replicate all these results.
Identifying grid cells in a reservoir model where and when the micro-emulsion phase appears is a key capability in the modeling of surfactant phase behavior. The Critical Micelle Concentration (CMC) is the commonly accepted triggering criterion for forming the micro-emulsion phase. We have observed unphysical "checkerboard" saturation patterns for several cases where water mobility is greater than oil mobility when using the conventionally accepted CMC calculation method. We have analyzed the reasons for this unphysical solution and propose a new CMC definition to ensure physically consistent simulation results. Typical CMC values for surfactant flood are in the range of 10-5 to 10-3. This requires surfactant concentration to be solved more accurately relative to other component concentrations as it directly affects micro-emulsion phase disappearance. The simulation results may vary with time-step sizes not only from the time-truncation errors but, more importantly, from the accuracy of the solved surfactant concentration for each time-step. Special treatments are introduced to reduce the time-step size sensitivity in our simulator. For cases with cation exchange, slow convergence is observed as the corresponding governing equations form an ill-conditioned matrix for cells with small surfactant concentration. An extra term is introduced into the formulation to speed up the convergence rate without changing the model behavior.
Revised Correlation for Accurate Estimation of CO2-Brine Interfacial Tension at Reservoir Conditions
Authors: Jerauld Gary Russell , Kazemi Nia Korrani Aboulghasem 
Published: April 2022

Abstract
A recently reported correlation of CO2−brine interfacial tension (IFT) for the full range of reservoir pressure, temperature, and formation water salinity necessary to evaluate CO2 sequestration in hydrocarbon reservoirs has been revised and simplified. The new CO2−brine correlation predicts CO2−brine IFT normalized by water surface tension from temperature, CO2-water density difference normalized by the density difference between water and it's vapor(function of pressure and temperature), and the valence-weighted molality of the cations. The correlation was derived from a database that covers 1298 CO2−brine IFT data including 484 for pure water. The revised CO2−brine IFT correlation accurately predicts available data for pure CO2−pure water IFT data with an average absolute relative error (AARE) of 2.4% and standard deviation (SD) of 3.1%. Similarly, for CO2−brine IFT correlation achieves an AARE of 2.4% and a SD of 3.5%.
We also examine simple methods for predicting the interfacial tension between water and mixtures of CO2 and other gases. We find that while under ideal conditions the mole-fraction weighted average is a viable approximation to the mixture interfacial tension, it typically overstates IFT in many situations. We propose a minor generalization of Kashefi's (2012) method which has better qualitative behavior and improves predictions with an AARE of approximately 5%.
A New Logistically Simple Solution for Implementing ASP/ACP in Difficult Environments – Evaluation of Concept with High TAN Viscous Crude Oil
Authors: Southwick Jeffrey George , Upamali Karasinghe Nadeeka , Fazelalavi Mina , Weerasooriya Upali Peter , Britton Chris James , Dean Robert Matthew 
Published: April 2022

Abstract
Research on alkali assisted chemical EOR technology with high TAN crude oils have led to developments with liquid organic alkalis and co-solvents (Southwick J., et al., 2020) (Fortenberry, et al., 2015) (Schumi, et al., 2019) (Upamali, et al., 2018). Both concepts afford potential significant cost reduction in field operations but to date it has not been demonstrated that these two concepts can work together.
Monoethanolamine (MEA) alkali and a wide variety of liquid co-solvents are evaluated with high TAN (total acid number) crude oil. Formulations are found that give ultra-low interfacial tension (IFT) at a specified injection salinity. Fine tuning the formulation to different injection salinities can be done by choosing alternate co-solvents (or a co-solvent blend). A formulation comprising 1% MEA and a novel high molecular weight (3,152 g/gmol) co-solvent, 0.5% Glycerin alkoxylate with 30 moles propylene-oxide and 35 moles ethylene-oxide (Glycerin-30PO-35EO), gave ultra-low IFT in 21,000 TDS injection brine and gave 100% oil recovery in Bentheimer sandstone with 3500 ppm FP 3630 as mobility control agent. All oil was produced clean, no separation of emulsion was needed to measure oil recovery.
Alkali consumption tests were also performedwith a high permeability reservoir sandstone. Results confirmed earlier data published with Boise outcrop sandstone (Southwick J., et al., 2020) showing low alkali consumption with MEA. On a mass basis, only 12% of the amount of MEA is consumed relative to sodium carbonate. This reduces the logistical challenges of shipping chemicals to remote locations. MEA is also a low viscosity liquid which further simplifies field handling.
A Visualization Study of Low-Tension Polymer Flood for Viscous Oil Reservoirs
Authors: Guo Yujia , Song Haofeng , Mohanty Kishore K. 
Published: April 2022

Abstract
Polymer flood improves the sweep efficiency of viscous oil recovery over water flood. The low-tension polymer (LTP) flood has the potential to improve the displacement efficiency due to low interfacial tension without sacrificing sweep efficiency. The objective of this research is to evaluate the performance of LTP floods as a function of IFT for a viscous oil in a 2D sand pack. Over 20 non-ionic surfactants/co-solvents were tested. A series of sandpack flooding experiments were conducted in a custom-designed 2D visualization cell. The results show that short-hydrophobic surfactants 2EH-xPO-yEO can reduce the IFT to as low as 0.05 dynes/cm. Flooding experiments were performed in sandpacks with and without connate water saturation. For the experiments with connate water saturation, the sandpack was water-wet/intermediate-wet. A base-case polymer flood (without any surfactant) with a viscosity ratio of 10 showed a stable displacement and 82% OOIP oil recovery at the first pore volume injected (PVI).LTP flood with an IFT of 0.1 dynes/cm also showed stable displacement front, but ahigher oil recovery at 1 PVI (90% OOIP).Further reduction in IFT to 0.05 dynes/cm resulted in an unstable displacement and a lower recovery of 65% OOIP. For the experiments without connate water saturation, sandpack was oil-wet, the base-case polymer flood at a viscosity ratio of 10 showed severe fingering and a low oil recovery at 1 PVI (58% OOIP). Adding the nonionic surfactants did not improve displacement efficiency nor oil recovery in oil-wet sandpacks.
First Nanoparticle-Based EOR Nano-EOR Project in Japan: Laboratory Experiments for a Field Pilot Test
Authors: Kaito Yutaro , Goto Ayae , Ito Daisuke , Murakami Satoru , Kitagawa Hirotake , Ohori Takahiro 
Published: April 2022

Abstract
"Nanoparticle-based enhanced oil recovery (Nano-EOR)" is an improved waterflooding assisted by nanoparticles dispersed in the injection water. Many laboratory studies have revealed the effectiveness of Nano-EOR. An evaluation of the EOR effect is one of the most critical items to be investigated. However, risk assessments and mitigation plans are as essential as investigation of its effectiveness for field applications. This study examined the items to be concerned for applying Nano-EOR to the Sarukawa oil field, a mature field in Japan, and established an organized laboratory and field tests workflow. This paper discusses a laboratory part of the study in detail.
This study investigated the effect and potential risks of the Nano-EOR through laboratory experiments based on the workflow. The laboratory tests used surface-modified nanosilica dispersion, synthetic brine, injection water, and crude oil. The oil and injection water were sampled from a wellhead and injection facility, respectively, to examine the applicability of the EOR at the Sarukawa oil field. The items of the risk assessment involved the influence on an injection well's injectivity, poor oil/water separation at a surface facility, and contamination of sales oil.
A series of experiments intended for the Sarukawa oil field showed that 0.5 wt. % nanofluid was expected to contribute to significant oil recovery and cause no damage on an injection well for the reservoir with tens of mD. This is considered a favorable result for applying Nano-EOR to Sarukawa oil field because it contains layers of tens mD. Furthermore, the experiments also showed that 0.5 wt.% nanofluid did not lead to poor oil/water separation and contamination of sales oil. Thus, field tests are designed with this concentration.
This paper introduces the entire study workflow and discusses the detailed procedure and results of experiments investigating the Nano-EOR effect and potential risks.
Modeling of High Pressure and Temperature Microemulsion Experiments using HLD-NAC Based Equation of State
Authors: Magzymov Daulet , Johns Russell T. , Hashim Hafsa , Dindoruk Birol 
Published: April 2022

Abstract
Surfactant flooding is a promising technique that can reduce interfacial tension (IFT) between oil and water to ultra-low values, mobilizing previously trapped oil. For reservoirs at moderate to high pressures, understanding and modeling how pressure affects the phase behavior of a surfactant-brine-oil system is important to the design and implementation of an efficient/cost-effective surfactant flooding project. Typically, however, phase behavior experiments and models of that phase behavior are made only at low pressures. The main objective of this paper is to show how to model experimental data in a unified way for a large range of pressure, temperature, and other parameters, using hydrophilic-lipophilic deviation (HLD) and net-average curvature (NAC) based equation-of-state (EoS).
Pressure and temperature scans show that pressure has a significant effect on the surfactant microemulsion phase behavior, shifting it from an optimal three-phase system at low pressure to a non-optimal two-phase system at high pressure. Further, multiple scans at different oil-water ratios show a shift in the optimum indicating that phase behavior partitioning of the various components is changing with oil saturation. We obtained good fits of all experimental data including all two and three-phase regions using a single tuned HLD-NAC EoS. This is the first attempt to model such complex phase behavior with a large variation in T, P, and compositions, which also demonstrates the type of data needed for an accurate EoS. When input into a numerical simulator, the tuned EoS improves the predictions of the resulting phase behavior (size and shape of the two-phase lobes and three-phase regions) and IFTs with changing pressure, temperature, salinity, oil-water ratios, and surfactant/alcohol concentrations.
Review of Offshore Chemical Flooding Field Applications and Lessons Learned
Authors: Han Ming , Ayirala Subhash , Al-Yousef Ali 
Published: April 2022

Abstract
This paper presents an overview of both research advancements and field applications of offshore chemical flooding technologies. Along with offshore oilfield development strategies that require maximization of oil production in a short development cycle, chemical flooding can become a potential avenue to accelerate oil production in secondary oil recovery mode. This makes it different from onshore chemical flooding processes that mostly focus on enhanced oil recovery in matured or maturing reservoirs. The advancements of offshore chemical flooding field applications are reviewed and analyzed. By summarizing offshore application cases, it also assesses the chemical formulations applied or studied and injection/production facilities required in the offshore environments. Main technical challenges are presented for scaling up the applications on offshore platforms or floating production storage and offloading (FPSO) systems.
The technologies reviewed include polymer flooding, surfactant-polymer flooding, and alkaline-surfactant-polymer flooding. By assessing the technology readiness level of these technologies, this study presents their perspectives and practical relevance for offshore chemical flooding applications. It has been long realized that chemical flooding, especially polymer flooding, can improve oil recovery in offshore oil fields. The applications in Bohai Bay (China), Dalia (Angola), and Captain (North Sea) provide the know-how workflows for offshore polymer flooding from laboratory to full field applications. It is feasible to implement offshore polymer injection either on platform or FPSO system. It is recommended to implement polymer flooding at early stage of reservoir development in order to maximize the investment of offshore facilities. By tuning the chemistry of polymer products, they can present very good compatibility with seawaters. Therefore, choosing a proper polymer is no longer a big issue in offshore polymer flooding.
There are also some interesting research findings reported on the development of novel surfactant chemistries for offshore applications. The outcome from a number of small-scale trials including the single well tracer tests on surfactant, alkaline-surfactant, surfactant-polymer in offshore Malaysia, Abu Dhabi, Qatar, and South China Sea provided valuable insights for the feasibility of chemical flooding in offshore environments. However, the technology readiness levels of surfactant-based chemical flooding processes are still low partially due to their complex interactions with subsurface fluids and lack of much interest in producing residual oil from matured offshore reservoirs. Based on the lessons learned from offshore applications, it can be concluded that several major challenges still need to be overcome in terms of large well spacing, reservoir voidage, produced fluid treatment, and high operational expense to successfully scale up surfactant based chemical flooding processes for offshore applications.
Chronic cough in postmenopausal women and its associations to climacteric symptoms
Authors: Ziller Volker , Oppermann Thea Sophie , Cassel Werner , Hildebrandt Olaf , Kroidl Rolf , Koehler Ulrich 
Published: April 2022

Abstract
Background
Postmenopausal women often have chronic cough, which is likely caused by hormonal changes affecting lung function and the mucous membrane of the airways, causing hypersensitivity of the cough reflex. Therefore, postmenopausal hormonal changes could play a key role in the association between increased cough and menopause. The aim of this study is to evaluate the relation of chronic cough and postmenopausal symptoms.
Methods
We performed a questionnaire-based cohort study in generally healthy postmenopausal women (age 45–65 years). Women with cough of known origin were excluded. Comorbidities, medication and baseline data were collected. The Menopause Rating Scale II (MRS II) was combined with the Leicester Cough Questionnaire (LCQ). Groups were divided in chronic cough versus non-coughing participants, chronic cough was defined as ‘symptoms for over 8 week’. We performed correlations and logistic regression for predicting cough based on postmenopausal symptoms.
Results
66 of 200 women (33%) reported mild to heavier symptoms of chronic cough for over 8 weeks. No significant differences in baseline data (age, BMI, onset of menopause, years since menopause, concomitant diseases, and medication) were found between coughing and non-coughing women. The MRS II showed higher menopausal symptoms in patients with cough, with significant differences in 2 of the 3 MRS-domains (urogenital (p < 0.001) and somato-vegetative (p < 0.001)). Climacteric symptoms strongly correlated with parameters of cough (p < 0.001). On the basis of the MRS total score (p < 0.001) and the somato-vegetative and urogenital domains (p < 0,05), the prediction for respiratory complaints could be shown.
Discussion
Chronic cough was significantly associated with menopausal symptoms. Therefore chronic cough as a possible climacteric symptom and its underlying mechanisms should be further explored.
Neuropathology of Yellow Fever Autopsy Cases
Authors: Frassetto Fernando , Rosemberg Sergio 
Published: April 2022

Abstract
Objective: We analyzed morphologically and immunohistochemically the brains of yellow fever patients who underwent autopsy, in order to identify and characterize neuropathological changes, which have few descriptions in the literature. The data were compared with brains collected from individuals without the disease, as a control group. Both cases and controls were subdivided according to the presence or absence of co-concurrent septic shock, in order to exclude changes of the sepsis associated encephalopathy.Results: All cases and controls presented, at least focally, neuropathological changes, which included edema, meningeal and parenchymal inflammatory infiltrate and hemorrhages, and perivascular inflammatory infiltrate. We did not find an unequivocal aspect of encephalitis. The only parameter that, after statistical analysis, can be attributed to the presence of yellow fever, was the perivascular inflammatory infiltrate. Since most of the parameters evaluated did not show statistically significant differences between cases and controls, an explanation for the presence of neuropathological findings may be the vascular changes, consequent to shock induced endotheliopathy, associated with stimulation of the immune system inherent to systemic infectious processes.