bluuebunny/crossref_metadata_2025_split huggingface dataset:
Characterization of Mixed Wettability using Surface Energy Distribution
Authors: Arsalan Naveed , Nguyen Quoc P. 
Published: March 2016

Abstract
A systematic approach to characterize the mixed wet configurations of various reservoir rocks (sandstone and carbonates) by evaluating their surface energy distributions has been presented in this paper. This approach was tested against the macroscopic spatial distribution of oil-wet and water-wet sites and at different temperatures for validation.
The new approach used to characterize the mixed wettability of a reservoir rock pertains to establishing a relation between the volume fraction of the mixed-wet reservoir rocks and surface energy of the mixture. This approach is based on an accurate description of the various physico-chemical interfacial forces present at the reservoir rock surface using Inverse Gas Chromatography (IGC). Mixed-wet configurations of various reservoir rocks are created by combining water-wet and oil-wet samples of the rock in different volume fractions and shaken together to establish uniform distribution. These samples are then subjected to the IGC analysis at different temperatures to deduce their surface energy distribution. The relation developed herein is tested against spatial heterogeneity by combining the oil-wet and water-wet rock samples in a layered fashion to validate the approach. The complete method to deduce the surface energy distribution of a rock surface using IGC has also been explained in detail.
A definite and conclusive relationship between the surface energy and mixed wettability of silica glass beads, calcite, and dolomite samples was established in this study. The mixed-wet configurations of the rock samples ranged from 0% oil-wet (meaning water-wet samples) to 100% oil-wet samples. The findings indicated that the Lifshitz-van der Waals component of the rock mixture did not undergo any change with change in the wetting state of the system under study. However the acid base components showed a marked decrease with increasing oil wetness before plateauing. Temperature was found to have a profound impact on the surface energy of a rock surface. Spatial heterogeneity by way of layered and segregated distribution of oil-wet and water-wet sites did not affect the eventual surface energy distribution thereby validating the new approach.
Irrigation and Trinexapac‐Ethyl Effects on Seed Yield in First‐ and Second‐Year Red Clover Stands
Authors: Anderson Nicole P. , Chastain Thomas G. , Garbacik Carol J. 
Published: March 2016

Irrigation and trinexapac‐ethyl (TE) [4‐(cyclopropyl‐α‐hydroxymethylene)‐3, 5‐dioxo‐cyclohexanecarboxylic acid ethylester] plant growth regulator (PGR) have been reported to enhance seed yield in red clover (Trifolium pratense L.). This study examined the interaction of irrigation and TE on seed productivity in first‐and second‐year stands in western Oregon (OR). Two field trials were established and followed over a 2‐yr period (2012–2013, 2013–2014). Treatments consisted of an untreated control, and 140, 280, 420, 560, and 700 g a.i. ha−1 TE PGR applied at BBCH growth stages 32 and 51, and in split applications at BBCH 32 + 51. A single irrigation (100 mm) applied at BBCH 55 increased seed yield and weight in first‐and second‐year stands by 13 and 5%, respectively. Seeds m−2 increased nearly 10% with irrigation in both first‐and second‐year stands in 2013 but not in 2014. Application of TE at BBCH 32 increased seed yield by 13.8% in second‐year stands, except at the 700 g a.i. ha−1 rate, and had no effect or reduced seed yield in first‐year stands. Seed weight was reduced by TE at all timings and reductions were proportional to the rate of application. Seeds m−2 increased in first‐year stands with TE rates ≥280 g a.i. ha−1 and ≥420 g a.i. ha−1 in 2012 and 2013, respectively, and with all rates in second‐year stands. There was no interaction between irrigation and TE in any year. First‐ and second‐year stands will likely benefit from irrigation; however, TE only increased seed yield in second‐year stands.Core Ideas

Irrigation and trinexapac‐ethyl independently increase red clover seed yield but there is no interaction between the two.
Red clover seed yield is enhanced by increasing seed weight with irrigation whereas seed weight is reduced with trinexapac‐ethyl.
Irrigation increases seed yield in first‐and second‐year stands but trinexapac‐ethyl only increases seed yield in second year stands.
Development of a Yellow Flag Assessment Tool for Orthopaedic Physical Therapists: Results From the Optimal Screening for Prediction of Referral and Outcome (OSPRO) Cohort
Authors: Lentz Trevor A. , Beneciuk Jason M. , Bialosky Joel E. , Zeppieri Giorgio , Dai Yunfeng , Wu Samuel S. , George Steven Z. 
Published: March 2016

Study Design Clinical measurement, cross-sectional. Background Pain-associated psychological distress adversely influences outcomes for patients with musculoskeletal pain. However, assessment of pain-associated psychological distress (ie, yellow flags) is not routinely performed in orthopaedic physical therapy practice. A standardized yellow flag assessment tool will better inform treatment decision making related to psychologically informed practice. Objectives To describe the development of a concise, multidimensional yellow flag assessment tool for application in orthopaedic physical therapy clinical practice. Methods A 136-item yellow flag item bank was developed from validated psychological questionnaires across domains related to pain vulnerability (negative mood, fear avoidance) and resilience (positive affect/coping). Patients seeking physical therapy with neck, back, knee, or shoulder pain completed the item bank. Iterative statistical analyses determined minimal item sets meeting thresholds for identifying elevated vulnerability or low resilience (ie, upper or lower quartile, as indicated). Further item reduction yielded a concise yellow flag assessment tool to assess 11 psychological constructs measuring pain-associated psychological distress. Correlations between the assessment tool and individual psychological questionnaires were measured and compared between anatomical regions. Concurrent validity was assessed by determining variance explained in pain and disability scores by the assessment tool. Results Subjects with elevated vulnerability and decreased resilience were identified with a high degree of accuracy (minimum of 85%) using a 17-item tool. Correlations were moderate to high between the 17-item tool and individual psychological questionnaires, with no significant differences in correlations between different anatomical regions. Shorter 10- and 7-item versions of the assessment tool allow clinicians the flexibility to assess for yellow flags quickly with acceptable trade-offs in accuracy (81% and 75%, respectively). All versions of the tool explained significant additional variance in pain and disability scores (range, 19.3%-36.7%) after accounting for demographics, historical variables, and anatomical region of pain. Conclusion Concise assessment of yellow flags is feasible in outpatient physical therapy settings. This multidimensional tool advances assessment of pain-associated psychological distress through the addition of positive affect/coping constructs and estimation of full questionnaire scores. Further study is warranted to determine how this tool complements established risk-assessment tools by providing the option for efficient treatment monitoring. J Orthop Sports Phys Ther 2016;46(5):327–345. Epub 21 Mar 2016. doi:10.2519/jospt.2016.6487
Les collaborateurs devant la cour d'assises du Nord après la très Grande Guerre.
Authors: Martinage Renée 
Published: March 2016

Les deux tiers des accusés d'intelligences avec l'ennemi en France, soit 83 personnes, furent jugés à la cour d'assises du Nord de 1920 à 1925. Le statut de la région pendant la guerre explique la concentration locale de ces crimes dont le nombre absolu demeure faible. Les collaborateurs furent jugés soit pour avoir secondé les Allemands dans les extorsions qu'ils pratiquaient, soit pour leur avoir fourni des renseignements, le plus souvent sous forme de dénonciations.
La rigueur de la cour d'assises fut relative. La moitié des accusés fut acquittée sans doute en raison des difficultés de preuve inévitables dans ces procès tardifs. Les deux tiers des condamnés subirent les peines criminelles politiques spécifiques pour ces infractions, c'est-à-dire la déportation et la détention, car depuis 1848 la peine de mort était abolie en matière politique. Six accusés, dont 3 contumax, furent condamnés à la déportation perpétuelle en enceinte fortifiée (aux îles du Salut à l'époque), en raison de l'accumulation des forfaits commis. 22 personnes furent condamnées à la détention, une peine qui s'exécute dans l'une des forteresses du territoire continental, pour des durées qui varièrent de 5 à 15 ans. Enfin 15 accusés furent condamnés à la peine correctionnelle de l'emprisonnement. Une seule cassation, trois grâces, une seule libération conditionnelle, aucun sursis, tempérèrent peu la lourdeur des châtiments. La justice de la cour d'assises, conforme au niveau de sévérité habituelle dans les années vingt, et liée par les caractéristiques judiciaires des procès, fut peu appréciée par l'opinion publique déçue principalement par l'acquittement des industriels fournisseurs des Allemands.
Effect of Corrosion, Scale and Biocide Inhibitor on Residual Oil Saturation
Authors: Ali Mohammad A. J , AL-Quraishi A. , Kholosy S. , Al-Makimi A. 
Published: March 2016

AbstractIn most water injection projects, inhibitors are added to the injected water to protect the pipelines, facilities, and reservoir from corrosion, scaling, and bacteria growth. Most studies in the literature focus on the efficiency of inhibitors to prevent corrosion and scale, but very few discuss their effect on formation permeability and oil recovery.Laboratory experiments on core samples were carried out and chemical additives to seawater were tested at different conditions to evaluate formation damage and residual oil saturation. Different solutions of combined scale, corrosion, and biocide inhibitors at concentrations of 0.5 and 1% were added to seawater.Formation damage was studied using core samples at full water saturation and showed permeability decline up to 75% due to suspended solids formed from the interaction between the inhibitors and dissolved salts in water. Oil recovery was measured using core samples at full oil saturation. Residual oil saturations varied between 24 to 70% depending on the type and concentration of inhibitors. An increase in the concentration of a single inhibitor yielded a reduction in oil recovery. However, for mixture of inhibitors, the relationship becomes complex. A linear model developed to predict residual oil saturation from inhibitor concentration and an optimum concentration of the mixtures minimizing permeability reduction and residual oil saturation was defined.
220°C Ultra-Temperature Fracturing Fluid in High Pressure and High Temperature Reservoirs
Authors: Liwei Wang , Wen Zhai , Bo Cai , Yongjun Lu , Xiaohui Qiu 
Published: March 2016

Abstract
X basin was located in the eastern China with diverse types and complex structures, is dominated by algal dolomite. The formation charactristers are summarized as following: high temperature from 180 °C to 230°C(quick acid reaction) and ultra-low porosity and permeability(less than 10% and 0.1md), high in-situ stress(&gt;90MPa), high leak-off and because of natural fracture networks which making fracture encounted many problems. This paper presents a new type of synthetic anionic terpolymer gelatinizer and the related influencing factors were studied including a new polymer and a new crosslinking. During the development process of synthetic polymers, the monomer selection, synthesis processes and other conditions directly affect temperature resistance capability of the polymer fracturing fluid. Furthermore, the optimal reaction conditions of polymer thickener with high temperature resistance capability are acquired through "single-factor method", obtaining high temperature polymer thickener with certain temperature resistance capability. Moreover, the temperature resistance, shear resistance and gel breaking performance of cross-linked fracturing fluid were also investigated which shear viscosity was retained more than 150 mPa.s at 220 °C sheared at 170s-1 for 120min. The pilot and production of polymer gelatinizes was carried out and the results showed that new polymeric fracturing fliud system overcomes the thermal limitations of traditional guar. The post-fracturing rate is encourge with 80m3/d oil and 10×104m3/d gas, respectivity. The new fracturing fluid provides a new way to improve production in HTHP reservoirs.
A Novel Oil-Water Separator Design Based on the Combination of Two Flow Resistance Mechanisms
Authors: Wang Xiaoqiu , Zeng Quanshu , Wang Zhiming , Guo Xiao , Zhao Yanlong 
Published: March 2016

Abstract
Numerous oil wells, especially in their middle-late periods, are becoming less economic due to the high lifting costs and reduced recoveries. The downhole oil-water separation (DOWS) system is aimed to lower the production cost, reduce the environment impact, and enhance the oil recovery. However, current separators are of either poor separation effects or poor separation efficiencies.
In this paper, a novel oil-water separator design is proposed based on the combination of two different flow resistance mechanisms and pipe serial-parallel theory, with the restrictive path restricting the heavier water, while the frictional path impeding the more viscous oil. Based on the combination of the flow pattern transformation criterion, homogenous model, two-fluid model, and pipe serial-parallel theory, a unified model of oil-water two-phase flow is developed to predict both the flow rate and water content distributions in different paths, which is then compared with the computational fluid dynamics (CFD) results. Unlike the CFD results, each path has a specific flow rate and water content, and as a consequence, specific flow regime and flow pattern.
Both the CFD and model results show that the flow distributions in different paths of the separator will be adjusted automatically according to the fluid's property, while the model can also predict the water content distributions at the same time. And the average relative error for flow distribution is 17.71%, while that for water content distribution is 32.66%. Specifically, oil, being more viscous, mainly takes the restrictive path; while water, being heavier, tends to take the frictional path instead. To sum up, this autonomous function directs oil and water to different paths, hence oil and water is well separated.
Feasibility of Thermal Oil Recovery Processes in Offshore Heavy Oil Reservoirs: Simulations and Experiments
Authors: Sun Xiaofei , Zhang Yanyu , Chen Huijuan , Duan Xuewei , Hu Wentao , Zhang Xiansong 
Published: March 2016

Abstract
The Bohai Bay Basin is located in the eastern part of North China. Within it lies one of the largest offshore heavy oil deposits in China, roughly 4 billion tons of oil in place. In order to recover sufficient heavy oil at economical rate within limited lifetime of the production platform, CNOOC launched cyclic steam stimulation (CSS) and multi-component thermal fluid (MCTF) huff and puff process on offshore oilfields in Bohai Bay. However, thes processes realize recovery factors less than 15%, which implies that &gt;85% of the oil remains in the ground after the processes become uneconomic to continue operation. Therefore, the incentive is strong for the development of appropriate follow-up techniques that will maximize the recovery potential of and profitability from these offshore heavy oil reservoirs in Bohai Bay, China.
A series of experiments were conducted to test thermal conductivity of unconsolidated sandstones, heavy oil-water and heavy oil-steam relative permeabilities used in thermal simulations. The effects on these parameters of temperature, pressure and heavy oil viscosity were also studied. Furthermore, reservoir simulations were conducted to guide the design of oil recovery processes for three heavy oil reservoirs with a range of in situ oil viscosities from 342 to 926 mPa·s by comparing different operating strategies, including steam flooding, hot water flooding, and MCTF (high pressure steam, CO2 and N2) flooding. The experimental results of the thermal conductivity varied from 0.385 W/ (m °C) to 0.488 W/ (m °C) under systems and temperatures used in this study. Higher temperature are beneficial to decreasing residual oil saturation and increasing water and oil relative permeabilities, which is the main mechanism for thermal recovery method to enhance oil recovery. The simulation results show that, for lower viscosity heavy oil, MCTF flooding as a follow-up process achieved much better performance compared to steam flooding and hot water flooding operation. However, for intermediate and higher viscosity heavy oil, steam flooding was found to be more effective.
Development and Application of Ultra-High Temperature Drilling Fluids in Offshore Oilfield Around Bohai Sea Bay Basin, China
Authors: Mao Hui , Qiu Zhengsong , Xie Binqiang , Wang Zaiming , Shen Zhonghou , Hou Weichao 
Published: March 2016

Abstract
It is known that ultra-high temperature drilling fluids are still quite a challenge to drilling engineering. When bottomhole temperatures exceed 200°C, the design and formulation of drilling fluids can present a host of problems. Drilling fluids destabilize under such extreme conditions, possibly causing wellbore instability, well control problems, and ultimately loss of the well. Drilling buried hill hydrocarbon reservoir in offshore oilfield around Bohai Sea Bay Basin in China has often resulted in failure to reach desired objectives. Bottomhole temperatures up to 220°C, however, the pressures requiring drilling fluid weights just to 1.04 to 1.10 g/cm3 equivalent place severe limitations on the performance of drilling fluids and often contribute in failure to reach the desired drilling objectives. Polymers as viscosifying agent that control rheological properties and fluid loss create major challenges for drilling fluid performance and stability when temperatures over 200°C are reached. Additionally, the gelation of drilling fluids containing low solids content and high fluid loss can become difficult to control under ultra-high temperature conditions. Both of these issues are compounded when the ultra-high temperature is coupled with a requirement for low drilling fluids density. The wildcat well NP3-81 and NP3-82 were drilled in this offshore oilfield around Bohai Sea Bay Basin on January 2014. TD of 6066 meters and 6037 meters were attained, respectively. Both of the bottomhole static temperatures were exceed 220°C and the pore pressure was 1.04 to 1.10 g/cm3 equivalent. Logs were run to bottom without incident and drilling fluids related problems and the primary drilling objectives achieved. The success is attributed to the new technology, fit-for-purpose drilling fluids and rigorous pre-well planning. The paper describes the laboratory development and field application of a new technology of environmentally acceptable and seawater discharged drilling fluids designed for ultra-high temperature environments, highlighting the viscosifying agent which has excellent ultra-high temperature resistance and salt resistance viscosifying property, thermal stability and thermo sensitive characteristics. The apparent viscosity retention rate of novel viscosifier after aging at 220°C after 16 h were 90.81% and 95.95% respectively and the EC50 value was 15.529×104 mg/L in both fresh water based drilling fluid and salt-water based drilling fluid. Field application data shows that this new polymer viscosifying agent could play a critical role even though at harsh conditions such as ultra-high temperature and low density drilling fluids system which decreasing daily performance maintenance problems at the expense of the large consumption of fluid additive including conventional sulfonate copolymer.
The Flow-Field and Sand Retention Characteristics of a Full-Scale Sand Screen for Gas Field Deployment
Authors: Wong C. Y. , Wu B. , Solnordal C. B. , Yang W. , Zamberi M. S. A. , Shaffee S. N. A. , Johar Z. , Jadid M. 
Published: March 2016

Abstract
In order to gain a better understanding on fluid and sand flow around and through a stand-alone-sand (SAS) screen, a scouting study on the flow-field and sand retention characteristics of a full-scale 5.5" OD sand screen was conducted. The velocity flow-field around a horizontal 1-metre long sand screen within a clear acrylic cylinder was investigated in air using state-of-the-art laser diagnostics experiments with complementary computational fluid dynamics (CFD) simulations. The flow-field in the annular space was interrogated by a 2D Particle Image Velocimetry (PIV) technique. CFD using standard solution techniques for dilute particle flows in air employed over 20 million elements to capture the fine details around the individual components in the screen shroud. The sand retention and pressure drop characteristics across the same sand screen were similarly conducted in the same flow loop. At the toe of the screen, some of the flow entering the base pipe also entered the annular space. The inflow from the base-pipe continues to contribute to the annular flow which builds up in magnitude towards the heel of the screen. As the flow approaches the heel of the screen, the annular flow is forced to re-enter the base-pipe via the screen. This phenomenon is observed in the PIV experiments and the CFD simulation results, albeit with minor differences. However, evaluation of the velocity range and span suggest that the CFD results are reasonably validated by the experimental data. Further tests on the sand retention and plugging characteristics of the screen demonstrated that the screen responds differently to low concentrations of coarse, medium and fine sands. Taken together, these provide field engineers some insight into the screen characteristics and behaviour when deploying such screens in the field. When validated with physical data, CFD is a reliable engineering tool to assess the complex single phase flow phenomena occurring in downhole completion equipment where it may not be economically viable to simulate in field conditions. The sand retention work on a 1-metre long full bore screen also provides a reality check for the screen when subject to low concentration of sand loading, which alters the pressure drop requirements and sand retention capability of that screen. For the first time, the annular flow in a full-sized sand screen has been measured in the laboratory using 2D Particle Image Velocimetry. The results provide supporting evidence to confirm the annular space flow features obtained in the CFD simulation results and provides some insight into the behaviour of annular flow around the sand screen.