bluuebunny/crossref_metadata_2025_split huggingface dataset:
Etude de nouveaux cepages <em>V. vinifera</em> L. en Allemagne Fédérale
Authors: Schöffling Harald , Faas Karl-Heinz , Faber W. , Duplessis H. 
Published: September 2016

<p style="text-align: justify;">Un programme de recherches a été entrepris pour comparer vingt-deux nouveaux cépages et trois anciennes variétés sur quatre zones viticoles de la Haute-Moselle. La première phase de ce programme s'est étendue sur cinq ans (1975-1980). L'examen de vingt caractéristiques portant sur les raisins, les moûts et les tests sensoriels des vins obtenus montre Ia supériorité des nouveaux cépages sur le cépage témoin « Elbling blanc ».</p><p style="text-align: justify;">Sur les vingt-deux cépages testés, au cours de la première phase des recherches, les résultats obtenus ont permis aux auteurs de sélectionner pour la deuxième phase de l'étude les huit cépages suivants : Faberrebe, Kerner, Gutenborner, Ortega, Reichensteiner, Forta, Rabaner et Regner.</p><p style="text-align: justify;">+++</p><p style="text-align: justify;">A comparative study has been made between twenty-two new and three traditional varieties. They are located in four different sites in the Upper-Moselle wine-growing area. The date presented is based on a five-year (1975-1980) programme, which is one of three phases. Twenty characteristics has been taken into account. Experiments in vinification and sensoric wine tests showed great improvements when compared with the variety « white Elbling » which has been taken as control.</p><p style="text-align: justify;">After having got the results of the first part of the study, we selected to continue the experiments with eight varieties instead of twenty-two, namely : Faberrebe, Kerner, Gutenborner, Ortega, Reichensteiner, Forts, Rabaner and Regner.</p>
Using Sucker Rod Pump Repair Data to Optimize Rod Lift Design
Authors: Dove J.. , Smith Z. D. 
Published: September 2016

Abstract
Sucker rod pump repair data can provide valuable insights into failure causation for the rod lift system. Tracking trends on metrics, such as well pull causes and pump parts replacement, enable operators to understand both individual well performance issues as well as overall field performance. Comparing historical performance to current performance can provide operators with a better understanding of which rod lift techniques are effective for their area and which techniques need adjustment and further evaluation.
The method for tracking pump repair data begins with a standardized approach to data collection by systematically disassembling and repairing a pump using software as a reliable means to collect the information. Pumps are disassembled, inspected, and assembled following specific guidelines that are included in a pump repairman's training program. The standardization of pump repair ensures that the data collected on metrics, including part wear, corrosion, and foreign material, will be accurate for analysis. The level of detail in the pump repair record, along with user-tracked well history, provides the end user the information needed to identify the root cause for specific failures, as well as visibility on prior failures to track design changes and performance over time.
Tracking pump repair data provides the operator the visibility needed to evaluate well and field performance. As the database grows over time, a more precise picture on performance versus design will emerge. Run times can now be investigated at the field level, and variations in downhole conditions, wellbore geometries, design considerations, and well maintenance practices can be optimized. Using the data obtained from the pump repairs helps the operator to identify root causes for failures and modify the rod lift design to improve system efficiency.
Throughout the life of the well, especially during periods that involve high capital investment, there is an appreciation in the industry for data collection to aid in decision making. Rod lift is an ideal artificial lift method for most wells, and typical data collection focuses mainly on dynamometer data for system monitoring. Understanding the changes that are occurring downhole, and optimizing the downhole design to suit those changes, are largely influenced by the experience of the operator's teams than by data specific to the system. Using pump repair data analysis to supplement the failure team's experience can improve the rod lift failure analysis and optimization process. By providing the team with information on the hardware that has been exposed to the downhole environment, the team can understand the suitability of the pump and bottomhole assembly design to the well and make the appropriate changes to improve performance.
Real-Time Decision Making for ESP Management and Optimization
Authors: Hackworth Matt , Williams Sandy 
Published: September 2016

Abstract
It is estimated that 95% of oil wells globally use Artificial Lift and 2014 statistics show that Electrical Submersible Pumps (ESPs) represents 43% of the global annual artificial lift spend[0]. Occidental Petroleum is a large user of ESPs, with over 2,200 in West Texas alone, and while ESPs can produce at high rate, they are also high cost. In today's low oil price environment, it is imperative that ESPs are operated efficiently to produce at the lowest cost per barrel.
When applying ESPs to unconventional wells, efficient production is even more important with the added operational complications of producing frac sand, high gas/oil ratio (GOR) reservoirs, and rapidly changing flow rates. These three factors can dramatically shorten ESP run lives if not properly managed. Providing surveillance, monitoring, and optimization to Occidental's more than 400 unconventional wells required improved field data delivery systems, surveillance practices, and optimization techniques to meet this challenge.
To achieve this, Occidental internally-developed a system for real-time ESP decision making that combines real-time data transmission, a data analytics tool, and an ESP analysis engine, all supported by trained staff and engineering workflows. By pulling all of these components together in one platform called "OxyLIFT," production engineers have a tool to enable rapid problem detection and diagnosis.
The OxyLIFT system represents a major step forward in real-time decision making. By performing an automated analysis process on thousands of ESPs, Occidental can take proactive action on production losses at any point in the ESP's operational phase, as well as enabling semi-predictive failure analysis. Most importantly, the system highlights proactive ESP replacement opportunities which minimizes both production downtime and equipment losses. This system can be applied to any type of ESP well however the challenges associated with an unconventional well will be specifically investigated and explained with multiple case studies.
CFD and FEA-Based, 3D Metal Printing Hybrid Stage Prototype on Electric Submersible Pump ESP System for High-Gas Wells
Authors: Ye Zheng , Rutter Risa , Martinez Ignacio , Marsis Emanuel 
Published: September 2016

Abstract
Advanced computer simulations for pump stage design enable an efficient way to design and evaluate pump performance. Simulations also provide detailed structural behavior (e.g., stress, modal analysis), temperature analysis and performance at various flow regimens (multiphase flow). Finite element analysis (FEA) and computational fluid dynamics (CFD) can be coupled with multi-disciplinary design optimization (MDO) in pump stage design practice, becoming a more helpful tool than traditional trial-and-error approaches. These tools are used to accelerate the design process of new pump stages for electric submersible pumps (ESP).
A simulation-based design was used to develop a hybrid gas-handling stage. It has been demonstrated that a hybrid stage manages a higher gas volume fraction (GVF) through production tubing as well as achieves a rising head across the operating range. The hybrid comprises an axial-flow stage and a mixed-flow stage as a set. An axial-flow stage is designed at high flow rates to push the liquid and gas phases together. The two-phase fluids then enter a mixed-flow stage, which generates a head with a reduced gas lock. One of the challenges is achieving a rising head curve across the operating range. The head curve of an axial-flow pump often constantly rises, leading to a wide operating range. Combining an axial-flow stage with a mixed-flow stage achieves a rising head and a wider flow range. Computer-based, two-phase flow modeling was used to accelerate and optimize the design of hybrid stages. As a result, this hybrid stage exhibits a high-efficiency rising head across the operating range and high gas-handling capabilities.
The prototype of this new hybrid stage was manufactured by 3D metal printing. Additive manufacturing technology has a shorter processing time, a lower scrap rate and is more affordable in the prototype phase. Material selection was considered to meet the design requirements for the testing system.
In this study, a new 4-in. hybrid concept was developed to meet the need of high-GVF wells. Pump performance testing and two-phase flow testing with the prototype pump was performed, and the results were compared with simulation models. Simulation models, well authenticated by thorough tests, provide reliable and effective stage-design tools, which provide a validation of a project's viability. The prototype has demonstrated capabilities to pump above 75% GVF without gas locking. Currently, the hybrid stage pump is under the product development phase based on the encouraging results on handling high percentage of gas.
Production Optimization in Highly Deviated Unconventional Wells
Authors: Bridges Jeffrey , Fougerdi Morteza , Clour Eric , Sappington Eric 
Published: September 2016

Abstract
This paper describes an artificial lift case study where ten horizontal Mississippian Lime wells exhibiting high dogleg severity above the tangent section were tested on an electrical submersible pump (ESP) to maximize fluid production. The three main objectives of the test were: (1) to reduce pressure on perforations to an acceptable level; (2) to implement flangeless connections on the equipment string; and, (3) to monitor the economic impact of the installations of the ESP units to the wells.
The challenges for the ESP systems for this specific test included: (i) mechanical damage passing through high dogleg severity (up to 25°/100ft); (ii) quickly declining production; (iii) high gas/liquid ratio (&gt;800 SCF/BBL); (iv) low liquid inflow during gas slugging. These challenges eliminated the possibility of using traditional ESP equipment. Gas-avoidance and gas-separation technology was used to enhance reservoir drawdown, along with flangeless ESP connections, to maneuver the string through the typically equipment-destroying dogleg severity.
This paper describes uncommon techniques to effectively install and operate an ESP unit in highly deviated wells and the application of ESP systems in gassy and gas-slugging wells. Historical design challenges, system-specific design/operation, and production results of the tested wells are also presented. Comparisons to other traditional artificial lift methods, including ESPs with flanged connections, help support the conclusion that it is possible to successfully and economically improve production in a highly deviated unconventional well by using a properly designed ESP. The economic impacts are viewed as positive when the test well results are compared to conventional alternatives that are not adequately equipped to handle all of these challenges.
These results are used to make inferences on potential changes to future wellbore planning and drilling that will impact drilling and completion costs, as well as improved recovery.
Hydraulic Tubing Anchor Results from Uinta Basin Oil Wells
Authors: McDaniels Anthony D. , Sakakura Scott 
Published: September 2016

Abstract
Mechanical tubing anchors are a widely used technology in rod pump production. One alternative method of anchoring tubing is the hydraulic anchor, a technology which is gaining acceptance in the industry. The method of actuation and overall geometry give the hydraulic tubing anchor appealing technical advantages, while also offering long term solutions to known mechanical tubing anchor problems. In the Uinta Basin, mechanical tubing anchors have made production and work-over operations complicated and lengthy. This study discusses and reviews the use of hydraulic tubing anchors vs. mechanical tubing anchors in Bundage Canyon and Lake Canyon of the Uinta Basin Wells. The Senior Production & Completions Engineer for these wells collected and monitored the data presented. Data covers decisions to install and installations of hydraulic anchors from April 2013 to October 2014. Beginning with a trial period, the hydraulic anchors had proven to operate as intended and minimize (in some cases eliminate) problems prevalent with running mechanical anchors. Although hydraulic anchors presented a greater initial cost than mechanical anchors, the benefits in reliability, reduction in install time, and reduction in retrieval time amounted to an estimated 46% savings over the course of the study.
Pump Stroke Optimization: Case Study of Twenty Well Pilot
Authors: Elmer William G. , Elmer John B. 
Published: September 2016

Abstract
"Pump Stroke Optimization" or PSO was invented to address problems encountered when rod pumping in rapidly changing flow regimes observed with oil production from horizontal wellbores. Current RPC ("Rod Pump Controller") technology was developed for vertical wells. The application of RPCs to horizontal wells often results in frequent full spectrum speed changes and excessive low pump fillage events, both which are undesirable.
The common method operators employ to mitigate this problem is to manually reduce the maximum working speed setpoint to a value slightly above that required to handle all the daily production. This intervention must be done routinely, and is counterproductive should the well see increased deliverability due to events such as downtime or offset fracs. Pump Stroke Optimization (PSO) replaces human intervention by regularly adjusting the maximum working speed based on analysis of several hours of observed pumping speeds and low pump fillage events.
Some RPC's allow for the downstroke to operate at a slower speed than the upstroke. For RPC's with this feature, the PSO device decreases the downstroke pumping speed preferentially, leaving the upstroke pumping speed unchanged until an operator set differential is reached. This practice results in less pump slippage, as well as additional time for evolving gas to exit the rod pump's gas anchor. This results in less strokes per day for the same production, which results in less downhole wear and less power consumption.
Field trials began in two Eagle Ford wells in March of 2015, with initial very successful results presented at an industry workshop in September 2015. An expanded twenty well Eagle Ford pilot test was begun December 3 of 2015. Rather than handpicking wells that were similar to the initial two well pilot, a wide range of production rates were chosen. After 45 days of operation, the following indicators were reviewed by the operator to determine overall success or failure: Algorithm Convergence (Indicating successful PSO device supplied pumping speeds)Greater average pump fillage (earlier load transfer better for downhole equipment)Less Strokes per day without production loss (provided by greater fillage and less slippage)Higher Bottom Minimum Stress in final rod taper (indicating less buckling tendency)Less electrical power consumption
The data was obtained using standard industry SCADA and data analysis software, as well as manually reading power meters. In summary, the operator deemed ten wells highly successful, five marginally successful, and five were not successful. The reasons contributing to success and failure will be expounded upon to obtain higher success rates in future applications.
Artificial Lift Selection Strategy to Maximize Unconventional Oil and Gas Assets Value
Authors: Oyewole Peter 
Published: September 2016

Abstract
The challenges of producing and lifting unconventional oil and gas economically is no doubt the most daunting phase of unconventional oil and gas development. The traditional approach of lift selection is no longer sufficient to effectively manage unconventional wells, with high decline rates between 40 to 80% in the first year. Slug flow, high free gas production, solid (proppant, scale, paraffin), horizontal wellbore geometry, surface pad for multi-well in a cellar, and other unique unconventional wells problems are continuously testing the limit of our existing artificial lift systems. As it might be expected, this is invariably, affecting the economic viability of unconventional oil and gas production.
This paper presents an exceptional Artificial Lift selection process, required to maximize unconventional oil and gas asset value. The presentation includes a case study of Permian Delaware basin unconventional formations. The lift evaluation process which includes, a combination of several output from various models (reservoir, well and economic models) developed to analyze the economic impact of various artificial lift selection on the well-life is also presented.
Three distinct periods are defined for the analysis:
Managed Flow-Back Managed Production (Managed Drawdown) End of Life
The overarching impact of lift selection and application, on Lease Operating Expense (LOE), Net Present Value of Cash Flow, Overall Asset Value Rate of Return on Investment and other Economic Indicators, for oil and gas operators is highlighted in this paper.
Artificial Lift Types were evaluated based on several criteria through elimination and selection techniques. Artificial Lift is phased over the life of the well according to current and expected production rate requirement and lift method capability. Other major consideration includes flexible rate delivery, solid handling, and failure frequency - repair cost and operational expense and initial lift cost and required infrastructure. The output from the type of curve/production forecast, combined with well performance modeling was used to determine future well and reservoir performance. Formation was grouped into various categories based on reservoir characteristics and fluid properties
The results showed cases of lift type selection for various types of unconventional formation. Actual well performance and lease performance results are also presented.
The managed production (drawdown) period has a major deciding factor on the artificial lift selection strategy. Combination of traditional artificial lift selection processes with several other model output to create artificial lift selection strategy for Permian Delaware basin unconventional formation is applicable in other unconventional basins
Fiber-Optic Monitoring in Electrical Submersible Pump Systems
Authors: Cooper Daniel , Rutter Risa , Forsberg Michael , Martinez Ignacio 
Published: September 2016

Abstract
Fiber-optic technology provides operators the ability to monitor temperature and vibration at multiple locations in electrical submersible pump (ESP) components using a single optical fiber. Conventional accelerometers and thermocouples have limited use downhole because of their size and issues with electrical interference. Intrinsic fiber-optic sensors are small enough for installation inside the equipment at optimal sensing positions in protected areas and are immune to electrical interference. In addition, conventional accelerometers and thermocouples provide single- point measurements rather than spatially distributed measurements. The distributed sensing ability of fiber-optic technology enables better understanding of equipment performance downhole. This work consisted of an investigation of fiber-optic systems for obtaining distributed temperature and vibration measurements of ESP components.
Prototype ESP motors and a seal were manufactured to enable fiber-optic monitoring of internal temperature throughout the equipment. Fiber Bragg Grating (FBG) sensors interrogated using Optical Frequency Domain Reflectometry (OFDR) enabled temperature measurements every 2 cm along the ESP assembly during operation as well as during epoxy cure. Separate prototype vibration sensors derived from FBG pairs were used to measure vibration of an ESP pump. Like the temperature measurements, these sensors were interrogated using OFDR. The prototype sensors were attached along the pump housing with accelerometers and measurements at multiple speeds and flow rates were taken. Vibration spectra and mode shapes were calculated from the fiber and accelerometer measurements and compared.
Motor temperature test results showed that the FBG sensors are capable of monitoring winding temperatures throughout entire length of the motor as well as at the bearing. In addition, the sensors were able to detect the location of insulation failure before the motor shorted. During epoxy curing FBG sensors were used to monitor curing temperature across the stator to ensure the consistent temperature distribution across the stator, preventing uneven heating and curing issues. In the seal the sensors demonstrated the ability to measure internal temperature along the shaft and at the thrust bearing, enabling accurate calculation of oil volume expansion rates. The vibration results show that the fiber-optic vibration sensors successfully measured the vibration frequency and the vibration modes of the pump. Together, vibration and temperature measurements enable the monitoring of ESP equipment health as well as detection of abnormal operating conditions, providing improved reliability as well as scheduled interventions.
Sucker Rod Lift System Optimization of an Unconventional Well
Authors: Orji Enyinnaya , Lissanon Janvier , Omole Oluwole 
Published: September 2016

AbstractOptimizing a well requires an understanding of all the parameters that govern the existing production rate, as well as an understanding of the production potential. The challenge in unconventional reservoirs is that the reservoir deliverability governing the existing rate changes with time. Hess's unconventional acreage in the Bakken field (tight oil, in this instance) spreads across North Dakota, with over 1,000 wells on artificial lift. The addition of an artificial lift system adds to the complexity of understanding a well's performance. The objective for well optimization in this paper is to understand current well performance and quantify potential production gains from changing operating parameters. This paper proposes a new approach to modeling and optimizing the well performance of an unconventional well that captures the flow hydraulics from the sandface to the sales point using an Integrated Production Model from the Petroleum Experts suite of software.