bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reducing Nonproduction Times during ESP Installation Using the MWI Device (Measure While Installing)
Authors: Archila Jesus , Ramirez Santiago , Perez Juan , Carreño Oscar A. 
Published: May 2015

Abstract
One of the most common problems in operations with ESP equipment is the increase of the non-production time during Electrical Submersible Pumps installation in highly deviated or tight casing wells. This often results in mechanical damage to the power cable that creates lost insulation problems that cannot be rapidly identified.
One solution to this issue is the implementation of a device called MWI (measuring while installing) created by Baker Hughes that helps reduce the non-productive time, ensuring an operation with less hours of rig-downtime during an ESP installation. This paper will focus on the real time measurement performed by the MWI through the ESP downhole sensor, which replaces the standard adopted practice of taking electrical measurements repetitively every 1000 ft. This practice did not allow to rapidly identify insulation problems during ESP running, but only when there was a stop for electrical measurements. Besides, the implementation of the MWI reduces the electrical exposure risk avoiding the need to take electrical measurement several times in a single operation.
The MWI was implemented as a field tool that provides a fast response capability during an ESP installation issue generating savings of 4 to 10 hours of NPT per ESP installation, while providing a high quality service from Baker Hughes to Ecopetrol, the operating company.
Optimization of Production Units Alternatives Considering Pressure Drop and Nonlinear Constraints
Authors: Figueira Alexandre F. , Silva Eugênio , Pacheco Marco Aurélio , Zanni João , Abreu Ana Carolina , Mendoza Leonardo 
Published: May 2015

Abstract
The exploration and production of oil fields involves multidisciplinary teams and has several decision variables. These variables can be optimized in order to maximize the profits of the operating company assisting the process of decision making regarding the development of the oil fields. The problem addressed in this paper is to optimize simultaneously the number, location and sizing of Production Units, considering technical and operational constraints and pressure drop during the simulation of production. To evaluate the pressure drop we used multiphase flow tables in order to obtain the required pressure curves. Each alternative of Production Unit has a different set of multiphase flow table in accordance with the distances between the wellheads and their Production Unit. The evaluation of each alternative of Production Units takes into account the union of the reservoir model with its respective fixed configuration of wells using gas-lift as lifting method. The optimization process uses Genetic Algorithms with the goal of maximizing the net present value (NPV) of a project evaluating possible alternatives of Production Unit through numerical reservoir simulation. A case study was conducted to demonstrate how the simultaneous optimization of the decision variables works. The optimization result shows that the alternative founded when was optimized the sizing of Production Units - besides the quantity and location - obtained a NPV higher than that obtained by the alternative resultant of the location and the quantity optimization of replicants Production Units.
An Improved Electrical Submersible Pump Performance Testing System
Authors: Bhuiyan Ariful I. , Reed Stewart , Nemec Barnabas , Henson Dale 
Published: May 2015

Abstract
Recent advances in exploration and energy extraction have been significant and occurred very quickly, greatly impacting the US economy. A major component of these advances is the electrical submersible pump (ESP), which targets high-volume energy extraction. Consequently, ESP testing system demands are increasing to new levels. Reliable and safe testing systems that provide quick, accurate, and repeatable results are highly desirable.
A service company recently developed a highly accurate, reliable, and fast ESP testing system. The new, improved testing system incorporates a control valve coupled with an actuator, two electromagnetic flow meters, a variable frequency driver (VFD), and programmable logic controller (PLC) driven automation. API standards were strictly followed concerning flow, pressure, and torque measurements. A proprietary software package allows real-time communication with the PLC and helps operators to run tests and to post test results online. Finally, identified safety issues were mitigated, either by design or administrative methods, to help minimize their severity.
The newly improved testing system helps reduce pump testing time by 75%. This new design is also modular, which helps to reduce transportation/installation costs and greatly simplifies installation.
ESP Installed in a Subsea Skid at Jubarte Field
Authors: Tarcha B. A. , Borges O. C. , Furtado R. G. 
Published: May 2015

Abstract
The FPSO P-58 is located in a deepwater field and produces pre and post salt reservoirs. The artificial lift method selected for two post salt wells is the mudline ESP, where the equipment is installed in a submarine skid. The main advantage of this technology is to reduce intervention costs due to cheaper vessels. The concept was developed and tested in two Petrobras projects: Espadarte and Cascade-Chinook fields.
Some of the challenges are related to the need for horizontal positioning of the equipment, due to the dimensions involved. This impacted the method of assembly and installation of the ESP in the capsule, as well as design of the protectors. The Mudline ESP has two pumps powered electrically in parallel and arranged in series hydraulically. In this project, the equipment has evolved in relation to the previous installations, in particular the inclusion of chemical injection, access to hot stab and the capability to receive a flow homogenizer.
The system will begin operation in 2015 and it is expected that its runlife will be similar to the standard equipment installed in the well, but with lower intervention costs. Possible improvements for the next projects are the use of sensors on both pumps and the installation of the system with even simpler and cheaper vessels.
Since the assembly of the pump and the whole skid is done onshore, the process can have a better control and supervision. Also, an integration test is performed before the system installation, which allows a complete evaluation of its performance.
A State-of-the-Art Modeling Technique for Thrust Prediction in Bottom Hole Electrical Submersible Pumps
Authors: Marsis Emanuel , Patil Abhay , Baillargeon David , McManus David , Gary II Steven , Williams Brett , Lana Dario , Nichols Jonathan , Zedtwitz Cristian Von , Ives Jason 
Published: May 2015

Abstract
Thrust in Electrical Submersible Pumps (ESPs) is a very important factor that affects pumps' performance. Thrust forces in pumps can increase the friction losses and reduce the overall pump efficiency and lifetime. Pump designers have to design pumps to handle thrust generated in the operating range whether by adding up-thrust protection, down-thrust protection, or sometimes both kinds of protections if the operating range includes both up and down thrust.
Hydraulic thrust mainly depends on the hydrodynamic forces generated inside ESPs. These hydrodynamic forces depend on many factors like blade loading, seal geometries, seal diameters, seal engagement, and balance holes location and sizes. Not only is the thrust magnitude important to predict, but also the shape of the thrust curve plays an important role in defining the operating range. If the thrust curve is flat, then this means a wider operating range for the pump.
Currently, no model is available to predict or design for thrust curve. Engineers use an iterative process of manufacturing and testing trying to reach the optimum seal configuration and balance holes geometry for better thrust and pump performance.
In this paper, a detailed CFD model of a mixed flow multistage ESP is presented including all seal elements and balance holes to be able to predict hydraulic thrust. Thrust curve is predicted for the first time using CFD analysis. Different seal geometries and balance holes configuration is also modeled to study the effect of geometry change on thrust curve. The model is validated using experimental test results. Also, other design parameters like the shape of the head curve, pump efficiency, and gas handling capability were controlled early in the design phase using CFD analysis.
Successful In-Well Deepwater Installation of Largest ESP Capsules With Crossing Lines Protected Inside a Capsule
Authors: Monteiro G.. , Neto F. Liborio , Pessoa R.. , Martinez I.. , Lima A.. , Pinto M. F. 
Published: May 2015

Abstract
The application of artificial lift in deepwater environments is constantly evolving due to a growing need for more sophisticated and robust completions that improve run-life expectancy and reliable deployment. The downtime associated with disruption of functionality while lowering a completion string in the well or dealing with a string stuck in hole can be a major concern because it can lead to an expensive workover or even well loss when fishing operations are unsuccessful. Because of this, most oil producer companies complete their wells only with field-proven or stringently qualified tools. That is the case of two subsea wells recently completed in the Atlanta field (14°API oil) with an electrical submersible pump (ESP) in more than 1,550 m water depth.
What makes the two initial wells unique to date are the large capsules (OD and length), high-power ESP and technology used to protect the lines going downhole. In the heart of each capsule there is a 1,500 HP ESP unit capable of pumping 12,000 bbl/d of viscous oil. Deploying such large systems inside 9⅝-in. capsules was already a great achievement. Nevertheless, the biggest challenge was to deal with the lines (two chemical injection, reservoir monitoring and hydraulic control) that had to go deeper than the ESP system. Even with the use of clamps, passing these lines outside of the capsule imposes a high risk of damaging them in the well's horizontal section or getting them stuck if the lines broke and wrapped between the capsule OD and the casing.
Overcoming this risk was possible through the implementation of a breakthrough idea that consisted in closing the bottom end of the 9⅝-in. capsule with a hydraulic retrievable packer instead of a torqued crossover, as is usually done in ESP capsules. The packer has the advantage that setting it doesn't create any relative movement of the feedthrough lines with respect to the capsule body, so all lines that must go deeper pass through without damage during closure of the capsule's bottom end. Splice subs above and below the packer make it even easier to pre-install the lines before shipping offshore.
Assembly was a breeze and the capsules were successfully pressure-tested to confirm there was no leakage before installing them in 11¾-in., 60.7-lb/ft casing at an inclination angle of 75°. All lines were commissioned and proven functional after finishing the completion job. These are the largest ESP capsules successfully installed in-well in Brazil and probably in the world with feedthrough lines crossing and protected inside the capsule. The creative concept can be extended to other wells and is very valuable to manage the risk of damaging the lines in ESP capsules.
ESP Application on Heavy Oil in Peregrino Field
Authors: Castro Vinicius , Leite Daniela , Lemos Daniel , Marins Jean , Pessoa Rui , Magalhães João 
Published: May 2015

Abstract
This paper discusses the experience and lessons learned during three years of electrical submersible pump (ESP) operation in heavy and viscous oil in the Peregrino field. Artificial lift applications on heavy oil fields have been a challenge for operators, and the Peregrino field is a good example for this type of ESP application.
An ESP was designed to enable a wide operation window to fulfill reservoir conditions changes and to focus on the extended run life and overall lifting efficiency. Three different ESP configurations were applied to produce liquid rates from 1500 to 20000 STB/d utilizing 1100-HP and 540-HP motors. Upper completions using a packer and capsule solution were selected to comply with all production conditions.
Peregrino field is a Statoil asset located in Campos Basin, approximately 85 km offshore from Cabo Frio/Rio de Janeiro state in Brazil. The oil in Peregrino has viscosity between 129 cp to 364 cp, and the API gravity varies between 13° and 15° API. The first phase of field development comprised two drilling-capable wellhead platforms and a centrally moored FPSO. Currently, there are 27 producer wells, including 3 multilaterals and 6 injectors in operation. The field is currently producing close to 100,000 STB/d of oil and has achieved a production record of 104,292 STB/d in July 2013.
The learning and experience developed from the ESP design phase through three years of operation represents a very important set of best practices. This information can be used by the industry as a complete field-proven method of ESP project implementation, particularly when dealing with high flow rates, high horsepower, and viscous oil ESP operations in an offshore environment.
A Time-Frequency Study of the Behavior of an Electrical Submersible Pump Operating Nearly the Gas-Locking Condition
Authors: Pedrotti M. M. , Biazussi J. L. , Bannwart A. C. , Sassim N. A. 
Published: May 2015

AbstractElectrical submersible pump system (ESP) represents a very effective artificial lift method in oil production; however, the possible presence of free gas may affect the performance of the pump in several ways. Depending on the gas content at suction conditions and on the suction pressure, it can block the impeller where no pumping action takes place, a phenomenon known as gas locking. The objective of this study is to investigate the pump behavior operating near this condition by using signal processing and analysis tools, in order to understand and anticipate the phenomenon.The tests were performed in laboratory, using a horizontal skid operating with a three-staged ESP. It was acquired time varying signals for process variables such as inlet and outlet pressures, shaft power and liquid flow rate for a constant gas mass flow rate. Then, using a mathematical software package for signal processing, the data were analyzed in both time and frequency domain to correlate these results with the pump operating nearly the gas locking point.Thus, it was possible to observe that as the void fraction increases, the most variables tend to oscillate heavily at some particular frequencies. It suggests that the frequency analysis relates with the physical phenomenon since the same operating conditions is ensured. This preliminar analysis permits the diagnose of operation, emphasizing the behaviour of the pump before and during the gas locking point.In literature, it is possible to find a lot of information about frequency analysis in flows through pipelines, so this work introduces a different approach of signal analysis for ESPs in order to predict the above mentioned phenomenon. Therefore, this work suggests that new kind of tests could be advantageous in future in order to evaluate the pump's behavior at different conditions, for example by varying the gas flow rate or inlet pressure.
Progressing Cavity Pumps in Horizontal Wells and 2,000,000 cp Viscosity
Authors: Monasterio Emmanuel A. , Gusberti Pablo I. 
Published: May 2015

Abstract
This article describes the techniques and tools using Progressing Cavity Pumps (PCP) that allowed the development of Llancanelo Field, in southern Mendoza, Argentina, where heavy oil with 12° API is produced through 13 horizontal wells. In addition they were able to overcome many technical and environmental challenges, such as adverse weather conditions and being located in an ecological reserve.
Some adverse characteristics were:
Viscosities up to 2.000.000cp at environmental temperature (10°C). Pumps installed at different depth conditions.
Example, the 2019 NLL-well with pump landed at 1197 m inside 5.5 pulg liner, and 90° from the vertical reference.
Sucker rod centralizer limited use by flow restriction caused. Wide operational temp range, below −15°C in winter, plus 35°C in summer.
Different applications are described, with particular advantages and high performance in each case. Main topics analyzed:
Viscosity and hydrodynamic wedge reducing the contact between sucker rods and tubing, preventing accelerated wear and final failure event. Using pipe heating wire for viscosity reduction in tubing production. Installation of relief and recirculation valves in production wellhead as protection regarding high back pressure blocked pipelines. Monitoring and automation systems with downhole pressure & temperature sensors. Low operating costs / reduced pulling ratio.. Technical feasibility to develop reservoir exploitation with PCP as ALS.
The results are presented case by case, and then an overall balance for entire field, where based on initial performance with 5 wells and 7600 m3 production in 2005, was possible to increase production until 21,727 m3 with 13 wells in 2013.
In conclusion the working methodology applied is shown for those applications, proving efficiency and recommendations for potential similar fields; that represented in an average run life of 1800 days, or examples as NLL-2001 well (3621 days) and NLL-1003 well (4000 days) both still operating, which becomes the longer runlife for a PCP application registered in Argentina.
The principal contribution is sharing experiences, solutions and working methodology among Operator, Services Company, and even an educational institution as the National University of Cuyo where rheological studies and oil characterizations were performed.
A New Approach To Diagnosis of Sucker Rod Pump Systems by Analyzing Segments of Downhole Dynamometer Cards
Authors: Reges Galdir D. , Schnitman Leizer , Reis Ricardo , Mota Fabricio 
Published: May 2015

Abstract
This work proposes a new method of diagnosing the Sucker Rod Pump Systems, by analyzing segments between the points of opening and closing valves identified in the Downhole Dynamometer Cards. An analysis of the shape of the pumping condition classes represented in the Downhole Dynamometer Cards, especially regarding the behavior of segments between the valve opening and closing points is presented. The feasibility of the classification of Downhole Dynamometer Cards by the curvature characteristics of segments is demonstrated. Then, methods of classification of 16 pumping condition classes are presented, 4 by simple statistics and 12 of them extracting curvature characteristics of the segments andusing statistics to implement Mamdani fuzzy inference systems. Tests are developed with classifiers created by the method, and the test results over a library of Dynamometer Cards from real wells, previously classified by human experts, demonstrate the feasibility of the approach and the precision of the classification even without a deeper study to choose the better characteristics and statistics. In addition the classifiers were developed using samples of Dynamometer Cards from the literature, showing that the method reduces the need of many samples of the great variety of the Dynamometer Cards Shapes from real wells. Different from other methods, these results indicate the severity degree of many pumping condition classes and demonstrate the concomitant pumping condition detection feature. The classifiers were even able to spot misleading classifications by the human experts thanks to deeper understanding of the behavior of the Dynamometer Cards segments in the case of one or more anomalies in the system. The features to quantify and identify concomitant classes of so many pumping conditionsdemonstrated in this approach are novel in the area. The paper shows the feasibility of the approach and the potential for greater identification precision.
Optimizing Completions and Artificial Lift in an Unconventional Play in the United States
Authors: Van Sickle S.. , Shelly G.. , Snyder D.. 
Published: May 2015

Abstract
The Marmaton formation is a large limestone reservoir straddling the Oklahoma and Texas Panhandle. This oil laden formation is a significant resource with potential recovery exceeding 88 million BOE, making it an attractive target for many operators. Similar to the Bakken, it was once considered unviable as an unconventional carbonate play due to complexity and associated production costs. With the application of modern horizontal drilling and fracturing techniques, operators are dispelling this notion.
To date more than 1,300 vertical and approximately 300 horizontal wells have been drilled in this play. Although the first horizontal was completed back in 1992, full development of the Marmaton has been relatively slow. Until recently, much of it was considered marginally economic, but this is changing with the application of innovative technologies that unlock and extract commercial volumes of hydrocarbons from the reservoir.
The standard well completion is typically an open hole, multistage (OHMS) completion system that utilizes packers for isolation and fracturing sleeves for stage diversion. This technology facilitates placement of stimulation treatments in one continuous pumping operation. Once the stimulation operation is complete, the well can be immediately flowed back and put on production resulting in efficient operations.
This paper will discuss how one of the more prolific operators in the play is developing its acreage by prudently employing new technologies. These new technologies and advancements include the following: degradable balls, water-soluble tracers, radioactive tracers, and high-rate water fractures. Each will be discussed in detail to help paint a picture of how this particular operator is leading the industry in unlocking the full potential of the Marmaton. To assist in the ongoing development of this unconventional play, theoretical and practical lessons will be highlighted.
The Concept of Smart Water Discharge (SWD), The Next Revolution in Produced Water Treatment
Authors: Richerand Frank , Peymani Yoosef 
Published: May 2015

Abstract
In modern process automation, the Oil and Gas industry is shifting toward Closed-Loop or Feedback process-control automation to constantly maintain the output at a predetermined set point by means of monitoring and controlling the vital process parameters.
Currently, most produced water treatment systems are acting as a non-feedback process or passive feedback control system (i.e. the outcome of treatment does not dynamically or actively influence the process). The development of an effective and dependable Closed-Loop control system is prevented by the lack of a reliable and accurate monitoring system that continuously measures the concentration of contaminates in the process. However, recent developments in Oil in Water (OIW) analyzers encouraged the authors to conduct a profound study on the development of a Closed-Loop System or Smart Water Discharge™ (SWD).
Goal-oriented Smart Water Discharge (SWD) allows the operator to set parameters for oil concentrations in overboard water at specific values (ppm); the Closed-Loop control system adapts the process conditions and/or employs the excursion tertiary water treatment equipment to maintain the set points.
This paper presents the concepts and algorithms of Smart Water Discharge (SWD), the essential components, the priority of a control system, the control functions, and operator-SWD interactions. Furthermore, the authors illustrate the results of field and lab testing for each component providing valuable information on selection and design of the system (including OIW analyzers, logic controllers and controlling elements).