bluuebunny/crossref_metadata_2025_split huggingface dataset:
Preventing Wax Deposition in Crude Oil Using Polyethylene Butene and Nano Zinc Oxide
Authors: Balogun Ademola , Odutola Toyin , Balogun Yakubu 
Published: November 2021

Abstract
This research examines the use of 75nm Zinc Oxide nanoparticles (Nano ZnO) and Polyethylene Butene (PEB) in reducing the viscosity of Nigerian waxy crude oil. The rheology of the crude oil was studied by measuring the viscosity and shear stress of crude samples contaminated with varying concentration of PEB (500ppm, 1000ppm, 2000ppm, 3000ppm, 4000ppm and 5000ppm), varying concentrations of Nano ZnO (1wt%, 2wt%, 3wt% and 4wt%) and different blends of PEB and Nano ZnO at temperatures of between 10°C to 35°C and shear rates from 1.7 to 1020s-1. From Rheological Modelling analysis conducted, the Power law pseudoplastic model was the best fit for the experimental data with a regression coefficient of 0.99. Analysis of crude sample before addition of inhibitor showed evidence of non-Newtonian fluid behaviour as the shear stress-shear rate relationship curves were nonlinear due to wax precipitation at low temperatures (10°C to 15°C). The waxy crude demonstrated shear thinning behaviour with increasing shear rates (increasing turbulence) and the viscosity reduced with increasing temperature. The addition of inhibitors (PEB, Nano ZnO and their blends) effected Newtonian fluid behaviour in the crude samples as the shear stress-shear rate relationship curves were linear at all temperatures under study. The optimum concentration of the inhibitors in this study is 2000ppm PEB (causing 33% viscosity reduction) and 1wt% Nano ZnO (effecting 26% viscosity reduction). The best concentration of the blend was 2000ppm PEB blended with 1wt% Nano ZnO which effected a viscosity reduction of 41%. The research demonstrates the novel application of the blend of Nano ZnO and PEB in improving flowability of Nigerian waxy crude oil especially in offshore conditions with prevailing cold temperatures.
The Combined Flooding of Dispersed Particle Gel and Surfactant for Conformance Control and EOR: From Experiment to Pilot Test
Authors: Yin Xia , Zhao Tianyi , Yi Jie 
Published: November 2021

Abstract
The water channeling and excess water production led to the decreasing formation energy in the oilfield. Therefore, the combined flooding with dispersed particle gel (DPG) and surfactant was conducted for conformance control and enhanced oil recovery in a high temperature (100-110°C) high salinity (&gt;2.1×105mg/L) channel reservoir of block X in Tahe oilfield.
This paper reports the experimental results and pilot test for the combined flooding in a well group of Block X. In the experiment part, the interfacial tension, emulsifying capacity of the surfactant and the particle size during aging of DPG were measured, then, the conformance control and enhanced oil recovery performance of the combined flooding was evaluated by core flooding experiment. In the pilot test, the geological backgrounds and developing history of the block was introduced. Then, an integrated study of EOR and conformance control performance in the block X are analyzed by real-time monitoring and performance after treatment. In addition, the well selection criteria and flooding optimization were clarified.
In this combined flooding, DPG is applied as in-depth conformance control agent to increase the sweep efficiency, and surfactant solution slug following is used for improve the displacement efficiency. The long term stability of DPG for 15 days ensures the efficiency of in-depth conformance control and its size can increase from its original 0.543μm to 35.5μm after aging for 7 days in the 2.17×105mg/L reservoir water and at 110°C. In the optimization, it is found that 0.35% NAC-1+ 0.25% NAC-2 surfactant solution with interfacial tension 3.2×10-2mN/m can form a relatively stable emulsion easily with the dehydrated crude oil. In the double core flooding, the conformance control performance is confirmed by the diversion of fluid after combined flooding and EOR increases by 21.3%. After exploitation of Block X for 14 years, the fast decreasing formation energy due to lack of large bottom water and water fingering resulted in a decreasing production rate and increasing watercut. After combined flooding in Y well group with 1 injector and 3 producers, the average dynamic liquid level, daily production, and tracing agent breakthrough time increased, while the watercut and infectivity index decreased. The distribution rate of injected fluid and real-time monitoring also assured the conformance control performance. The oil production of this well group was increased by over 3000 tons.
Upon this throughout study of combined flooding from experiment to case study, adjusting the heterogeneity by DPG combined with increasing displacement efficiency of surfactant enhanced the oil recovery synergistically in this high salinity high temperature reservoir. The criteria for the selection and performance of combined flooding also provides practical experiences and principles for combined flooding.
Storage of CO2 and Coal Fly Ash using Pickering Foam for Enhanced Oil Recovery
Authors: Lv Qichao , Zhou Tongke , Zhang Xing , Guo Xinshu , Dong Zhaoxia 
Published: November 2021

Abstract
CO2 foams have been used for a long time for enhanced oil recovery (EOR) and carbon capture, utilization, and storage. Note that conventional CO2 foam focuses on mobility control and storage of bare CO2. However, this technology has suffered from low storage efficiency and EOR because of foam instability. In this study, the geological storage of CO2 and coal fly ash (CFA) using Pickering foam for EOR was explored. The aim is to obtain an inexpensive method for EOR and storage of greenhouse gases and atmospheric pollutants.
The Pickering foam was prepared using Waring blender method. The experiments were conducted to evaluate CO2/liquid interface enhancement by measuring the interfacial tension and interfacial viscoelastic modulus. As per the heterogeneous sandpack flooding experiments, the profile control capacity and the performance of oil displacement using CO2 foam enhanced by CFA were investigated. The amount of storage from dynamic aspects of CO2 and CFA was measured to demonstrate the storage law.
The stability of aqueous foam was improved significantly after the addition of CFA. The half-life time of foam stabilized by CFA particles increased by more than about 11 times than that of foam without CFA particles. The interfacial dilatational viscoelastic modulus of CO2/foaming solution increased with CFA particle concentration increasing, indicating the interface transformed from liquid-like to solid-like. Flooding experiments in heterogeneous porous media showed that more produced fluid was displaced from the relatively low-permeability sandpack after the injection of CO2 foam with CFA. The oil recovery by CFA stabilized foam was improved by ~28.3% than that of foam without CFA particles. And the sequestration of CO2 in heterogeneous porous media was enhanced with the addition of CFA to CO2 foam, and the CFA stabilized foam displayed a strong resistance to water erosion for the storage of CO2 and CFA.
This work introduces a win–win method for EOR and storage of CO2 and atmospheric pollutant particles. CFA from coal combustion was used as an enhancer for CO2 foam, which improved the interfacial dilatational viscoelasticity of foam film and the dynamic storage of CO2. Furthermore, the storage of CO2 and CFA contributed to improvement in sweep efficiency, and thus EOR.
Enhancing Performance of High Viscosity Friction Reducers HVFRs in Brine
Authors: Phatak Alhad , Seymour Brian , Ren Ginger , Gonzalez Isaias 
Published: November 2021

Abstract
High Viscosity Friction Reducers (HVFRs) are often employed in hydraulic fracturing fluids to increase the proppant carrying capacity of slickwater fluids. However, it has been widely reported that the performance of HVFR fluids drops precipitously with even small amounts of salt. This study explores and reports the use of surfactants to alleviate the loss of performance of HVFR fluids due to salinity in the mix water. Fracturing fluids were prepared in the laboratory by mixing the HVFR at concentrations between 2 and 8 gal/1,000 gal with and without surfactant formulations. The viscosities of the fluids were measured on a TA Instruments DHR-3 rheometer using a concentric cylinder geometry. Both anionic and cationic HVFRs were tested with various surfactants. As expected, we observed that HVFR fluids display dramatic loss of viscosity with the addition of as little as 1% salt to the mix water. However, certain surfactant formulations were found to provide a significant boost in viscosity of HVFR fluids in brines over a wide range of shear rates. Increases in viscosity by a factor of as much as 10 times were observed, particularly at low shear rates. The ability of the surfactant formulations to enhance fluid viscosity was observed in both monovalent and divalent model brines, as well as brines that mimicked field produced water compositions. In addition, measurements were also performed in a slot flow device to determine if the results from the rheometer translated to proppant transport characteristics of the fluids. The slot flow results were found to correlate well with fluid viscosity measurements. The fluids containing the surfactant formulation transported nearly 4 times as much proppant as fluids not containing surfactant through a 2.5 ft. long rectangular slot of 0.5 in. thickness at a proppant concentration of 2 lb/gal. An obvious benefit of the approach proposed in this study is that it can enable the use of HVFR fluids in recycled and produced waters, providing both cost and sustainability benefits. Secondly, these surfactant formulations can reduce the amount of HVFR required to obtain a certain target viscosity in brine, thereby reducing the likelihood and potential severity of formation damage from HVFR residue.
Novel H2S Scavenger Testing Methodology to Meet the Ever-Present Challenge of Simulating Scavenger Application Methods with Laboratory Testing Protocols
Authors: Taylor Grahame , Wylde Jonathan , Allan Bridgette 
Published: November 2021

Abstract
The design methodology for H2S scavengers relies heavily on developing a test protocol that most closely simulates field applications. These include gas contact towers, direct gas production injection and multiphase treatments, such as subsea umbilical delivery lines to sea floor well heads, hydrocarbon flow lines and sour storage tank treatments. There are very few testing standards and while there are industry accepted methods, the novel methods presented fill the gaps that exist.
A thorough review is made of existing test methodologies such as the static gas breakthrough test and the multiphase Parr Autoclave. Each of these has become an accepted, albeit unofficial, industry standard. Novel methods recently developed comprise the "Direct Injection Laboratory Simulator" (DILS) which, as the name suggests, represents a laboratory method of evaluating a direct gas injection application. Also included is a unique modification of the gas breakthrough test, known as the "miniature Ultrafab tower" which simulates a regenerative tower-based system, commonly in operation in the field.
The results showed fascinating validation of gas direct injection and dynamic tower interactions. In some cases, the results are as expected and in others fresh insight has been obtained into any observed discrepancy between a scavenger's field performance and how it performs in the laboratory development studies. In the case of the "miniature Ultrafab tower", this ingenious piece of equipment has been proven to accurately simulate the packing typically seen in the gas contactor to enhance gas/liquid interaction as well as provides the ability to continually replenish the tower with fresh chemical during the test using an accurately controlled flow rate from an HPLC pump. These have been shown to be vitally important parameters for accurate lab to field correlation and are uniquely available from this test, for example gleaning the minimum flow rate of fresh scavenger which can control the H2S concentration to the predetermined level; exactly as is done in field operations. This novel apparatus also has a separator chamber where the spent chemical can be collected, analyzed and evaluated, exactly as is done in a field trial for a dynamic contact gas tower.
Armed with a new series of test methodologies, the development of H2S scavengers can enjoy a much higher success rate in the all-important transition from laboratory to field. The test methods also give invaluable tools to trouble shooting and investigate unexpected deficiencies in products which have in the past performed as expected. This includes providing a validation method for changes and enhancements desired during the manufacture process and raw material sourcing for chemical scavengers.
Innovative Surfactant Chemistry Offers the Performance Advantages to Invert Emulsion Drilling Fluids While Drilling Under Challenging Environments
Authors: Patel Arvindbhai , Singh Anil Kumar , Bidwai Nikhil , Indulkar Sakshi , Gupta Vivek 
Published: November 2021

Abstract
Stable invert emulsion with oil wet solids is achieved using invert emulsifiers and wetting agents. This paper reviews the chemistry and performance criteria of traditional invert emulsifiers and wetting agents utilized in formulating stable invert emulsion drilling fluids. However, occasionally such stable invert emulsion drilling fluids can be destabilized due to various hostile conditions encountered during drilling operation, and can adversely impact the drilling cost. Extreme preventive measures cannot avoid such hostile conditions such as sudden water influx, excessive solids and salt contaminations during drilling. Upon solids becoming extremely water wet with "flipped emulsion", it becomes impossible to fix the drilling fluid, resulting in expensive maneuver. Often situation cannot be corrected with traditional wetting agents and emulsifiers even at high level of treatments.
New innovative chemistry addresses the severe water-wetting and emulsion instability of invert emulsion under extreme challenging and hostile situations. The unique water soluble oil mud conditioner (OMC) synergistically enhances the performances of traditional oil-wetting agents and emulsifiers at very low, as little as 0.5 ppb levels of treatment. This OMC improves and extends the efficacy of the traditional invert emulsifiers and oil wetting agents resulting in reduced usage of these additives with excellent economic advantages.
The 15.0 ppg, invert emulsion drilling fluids were prepared using 2-3 ppb of primary and secondary emulsifiers, and these fluids were destabilized using high shear mixer for 7-8 hours. The destabilized fluids had severe water wet solids and ES value of less than 5. These destabilized fluids, upon treating with 0.5 ppb of newly developed OMC instantly became oil-wet and shiny and ES was increased to greater than 500. To demonstrate the effectiveness of OMC in pre-treatment situation, the base fluids treated with 0.5 −1.0 ppb of OMC showed superior mud stability compared to base fluid when contaminated with sea water, fine solids, barite and high salt contaminations. The OMC is flexible in its application and can be used as pre-treatment to improve the overall performance of drilling fluids and can also be used for post-treatment to recover the drilling fluids, which have been rendered unusable.
A Semiempirical Model for Predicting Celestite Scale Formation and Inhibition in Oilfield Operating Conditions
Authors: Zhao Yue , Dai Zhaoyi Joey , Dai Chong , Paudyal Samridhdi , Wang Xin , Ko Saebom , Yao Xuanzhu , Leschied Cianna , Kan Amy , Tomson Mason 
Published: November 2021

Abstract
Mineral scale formation has always been a serious problem during production. Most scales can be treated by adding threshold scale inhibitors. Several crystallization and inhibition models have previously been reported to predict the minimum inhibitor concentration (MIC) needed to control the barite and calcite scale. Recently, more attentions have been paid to the formation of celestite scale in the oilfield. However, no related models have been developed to help determine the MIC needed for the celestite scale control. Therefore, in this study, the crystallization and inhibition kinetics data of celestite under a wide range of celestite saturation index (SI = 0.7 – 2.6), temperature (T = 25 – 90 °C), ionic strength (IS = 1.075 – 3.075 M) and pH (4 – 6.7) with one phosphonate inhibitor (diethylenetriamine penta(methylene phosphonic acid, DTPMP) and two polymeric inhibitors (phophinopolycarboxylate, PPCA and polyvinyl sulfonate, PVS) were measured by laser apparatus or collected from previous studies. Then, based on the results, the celestite crystallization and inhibition models were established accordingly. Good agreements between the experimental results and calculated results from the models can be found. By using these newly developed models, the MIC needed for three commonly seen inhibitors, DTPMP, PPCA and PVS on celestite scale control can be predicted under extensive production conditions. The developed models can fill in the blank in scaling management strategies for high Sr2+ and SO42- concentrations in the produced waters.
Flow Dynamics of Microemulsion-Forming Surfactants and its Implications for Enhanced Oil Recovery: A Microfluidic Study
Authors: Yu Fuwei , Wang Lida , Liu Ben , Ma Mengqi , Liu Fan , Kang Lixia , Jiang Hanqiao , Li Junjian 
Published: November 2021

Abstract
The microfluidic experiments were conducted in this paper to clarify the flow dynamics of in situ microemulsion and further understand its EOR performances. Two kinds of 2.5D glass micromodel with varied depths of pore and throat are fabricated. One is designed for the imbibition tests, which consists of two fractures and a tight matrix. Another one is a fractured micromodel designed for the flooding tests. The micromodels are originally water wet, and can be altered to oil wet through the surface modification. At the same time, three microemulsion-forming surfactant solutions at the salinity of type I, II or III were prepared, respectively. Then the flow dynamics of these three surfactant solutions during imbibition and flooding process were visualized by the microfluidic experiments. Results show that the type I surfactant solution realizes the highest oil recovery rate in both water-wet and oil-wet imbibition micromodels. Meanwhile, the type III surfactant solution realize the highest oil recovery in both water-wet and oil-wet fractured micromodels.
Wellbore Integrity and CO2 Sequestration Using Polyaramide Vesicles
Authors: Contreras Elizabeth Q. , Santra Ashok 
Published: November 2021

Abstract
A new cementing additive is chemically engineered to react with formation fluids that act antagonistically towards cement. Engineered polymer capsules house encapsulants to react with antagonistic gases downhole like CO2 to form a more benign and beneficial material. Embedded in cement, the polymer capsules with semi-permeable shells allow fluids to permeate and react with encapsulants to produce beneficial byproducts, such as calcite and water from CO2. Reactivity between the encapsulant and antagonist gas CO2 is demonstrated using thermal gravimetric analysis (TGA) and other tests from oilfield equipment.
When cement fails, casing-in-casing events, or CCA, causes antagonistic gases like CO2 to migrate to the surface. Embedded in the cement for such moments such as cement failure, additives housed within polyaramide vesicles chemically and physically intersect CO2 from gas migration events. The shape of the polyaramide additive is unique and versatile. Furthermore, because the material is polymeric, it imparts beneficial mechanical properties like elasticity to cement. A vesicle in form, this polymer allows the manufacturing of new cement additives for applications such as increasing the integrity and sustainability of oil well cement. Data also shows production of calcite by the bulk of the material. This technology applies to CO2 fixation and self-healing cement using reactive polymer vesicles.
Influencing Factors of Lung Cancer Patients' Participation in Shared Decision-making: a Cross-sectional Study
Authors: Wang Ying , Zhang Jinna , Hu Bo , Wang Jizhe , Zhang Laixiang , Li Xiaohua , Zhu Xiuli 
Published: November 2021

Abstract
Purpose: The purpose of this study was to investigate and analyze the level of actual participation and perceived importance of shared decision-making on treatment and care of lung cancer patients, to compare their differences and to explore factors that influence them.Methods: A total of 290 lung cancer patients were collected from the department of oncology and thoracic surgery of a comprehensive medical center in Qingdao from October 2018 to December 2019. Participants completed a cross-sectional questionnaire to assess their actual participation and perceived importance in shared decision-making on treatment and care. Descriptive analysis and non-parametric tests were carried out to assess the status quo of patients' shared decision-making on treatment and care. Binary logistic regression analysis with a stepwise back-wards was applied to predict the factors that affected patients' participation in shared decision-making.Results: The results showed that patients with lung cancer had a low degree of participation in shared decision-making. There were significant differences between actual participation and perceived importance of shared decision-making on treatment and care. Education level, younger, gender, income, marital status, personality, the course of the disease (>6 months), and the Pathological TNM staging (Ⅲ) affected the patient's level of participation in shared decision-making.Conclusion: Actual participation in shared decision-making for the treatment and care of lung cancer patients was low and considered unimportant. We could train oncology nurses to use patient decision aids to help patients and families participate in shared decision-making based patients’ value, preferences and needs.