bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Effect of Temperature on the Mechanical Pump Slippage in Heavy Oil Wells With Steam Injection
Authors: Benavides Diaz L. C. , Chacon A. Gil , Ortiz J.. 
Published: May 2013

Abstract
In the last two decades the participation of heavy oils in the global volumes of production of oil has been constantly increasing and so the requirement for the development and adjusts of the existing technologies within the different stages of the extraction process of the petroleum.
For the specific case of the production of these oils to achieve the goal of making this flow economically viable up to the Surface is normally the bigger risk with their high viscosity being the main risk. In this way the use of the cyclic injection of steam is the improved and most commonly used method of recovery which increases the temperature of the oil and decreases its viscosity while allows an easier extraction of the resource.
Therefore a research was developed showing how the change of temperature decreases the efficiency of the pump due to the increase of the slippage which in turn is due to drop in the viscosity of the oil and, like in some wells, depending on the permeability of the sand a peak is shown in the efficiency at the beginning of the production because of a momentary pressurization of the well. All this based on slippage formulas developed by different authors, lab tests and field data acquired in the Zone of Moriche, municipality of Puerto Boyacá, where the steam injection is currently used for the extraction of petroleum.
Finally, these data were the start point to develop a new design of pump which adapts to the temperature changes and is more efficient under the conditions of steam injection than the conventional pumps, all this seeking the optimization of the petroleum extraction process in the industry.
Spatial Well Surveillance : An Approach For Early Detection of Well Behavior in Highly Populated Fields
Authors: Hidalgo J. G. , Ataguile S.. , Bertomeu F.. 
Published: May 2013

Abstract
Nowadays, supporting systems are scattered with several applications, some of them are custom developed, generating redundant and inconsistent data stores and silos across engineering, geo-science and operational domains, making it extremely difficult to access and effectively use data or information. An opportunity exists –by combining the industry’s monitoring and instrumentation capabilities with spatial data management and predictive analytics– to provide real-time operational intelligence, resulting in improved decision making.
This project outlines the development and implementation of a Geo Portal designed to provide information about wells behavior based on Production and Automation Data. The term Geo Portal refers to a map-based visualization tool that enables analysis of complex spatial and tabular data from a user friendly and intuitive web interface, enabling the user to analyze and understand vast amounts of data to make better and faster business decisions.
Through the Geo Portal it is possible to: View active and inactive pumping units and theirs technical characteristics.Verify the last time a well test was madeVisualize wells test rate differencesAnalyze the distribution of wells in downtimeLook at Production bubble mapsProvide online Diagnosis of pumping status (Combined KPI from Fluid above pump, pump efficiency and others)
The significance of this is that the integration enables an interface for quick, intuitive information retrieval. From an operational perspective, it is a great opportunity to manage field resources with focus on efficiency and maximizing production. Also, it is easy to identify opportunities for field foremen or field managers.
Improving Well Performance with Multiphase Helicoaxial Pump in Wells with High Gas to Liquid Ratio
Authors: Fidani C.. , Peralta M. Belen , Nuova L.. , Gould M. Sanchez 
Published: May 2013

Abstract
As the number of mature reservoirs continues to increase worldwide, so has the development of new technologies to aid electrical submersible pump (ESP) performance. Because depleting fields produce increasing gas volume, gas separators and gas handlers are necessary to maintain pump performance and production.
In wells with high gas volume, production is limited by the centrifugal pump’s ability to handle gas. Centrifugal pumps suffer from a head degradation and gas-locking in the presence of high percentages of free gas. Different technologies have been implemented to help operators achieve their production goals. However, as downhole conditions continue to change, the gas-handling capability of the technology installed becomes insufficient, resulting in downtime due to gas-lock, limited drawdown, high operational costs, high motor current fluctuations, and others issues.
A multiphase helicoaxial pump installed below the main production pump allows the production pump to efficiently handle higher percentages of free gas and up to 75% of gas volume fraction (GVF) at the first stage. This system is designed to improve stability in gassy wells, provide better slug handling in horizontal wells, increase the production rate and recovered reserves, and increase ESP effectiveness.
To enhance production in oil wells experiencing gas-locking problems, an operator began optimizing downhole ESPs where they showed unstable operational behavior and where the GVF was overcoming the maximum gas- handling capability of centrifugal pumps (up to 45% GVF).
In the first optimized ESP wells, the operator was able to increase production by reducing gas-locking production shutdowns, to stabilize motor current fluctuations, and to Increase production and reservoir life by increasing drawdown and allowing effective pump operation at lower intake pressure.
By the end of 2010, a total of 10 wells were operating with this technology within three different fields. Currently, more than 25 wells have been optimized.
The implementation of this technology in wells with high GLR has been demonstrated to be an effective solution. It has also allowed the operator to expand the use of the ESP in gassy wells, previously thought to be unsuitable for ESP application.
Downhole Fluid Conditioning System for Electric Submersible Pumps
Authors: Tarabelli Roberto , Ingouville Dolores , Rivas Olegario 
Published: May 2013

Abstract
Argentinian oil production comes from five basins: the Noroeste basin in northern Argentina, the Cuyana and Neuquina basins in west-central Argentina, and two southern basins, the Golfo San Jorge at the center of Patagonia and the Austral, south of Patagonia.
The Golfo San Jorge Basin is amongst the most prolific, with 39% of total oil production.
The two most commonly used artificial lift (AL) methods are electric submersible pumps (ESPs) for 4% of total production and rod pumps (RPs) for 27.5% of total production.
Most of the wells in these five producing basins are low-volume producers. Of the total wells, 80% produce less than 252 bpd (40 m3/d) and 13% produce between 252 bpd (40 m3/d) and 629 (100 m3/d). Because of these low production rates, RP systems account for the biggest percentage of AL installations in Argentina.
Because of environmental considerations, the water injection process to support reservoir pressure is under evaluation in the Golfo San Jorge basin. Well productivity in the region has decreased because water injection flow rates have been reduced. To overcome this reduction in the productivity, ESPs are being installed deeper in the wells (at or below perforation depths) allowing an increase in the drawdown of the wells that corresponds to an increase in production rate. However, setting the ESP system adjacent to or below the perforations may adversely affect the cooling efficiency of the ESP motor.
In a field trial in this basin, a recirculation system—the downhole fluid conditioning system for ESPs—was installed as a solution to the adverse motor cooling issues that typically result when ESPs are installed in front of the perforations. This recirculation system maintains or even increases the production rate by installing the ESP system deeper in the well. The system in this field study was installed in October 2007 and has a run life of more than 3 years.
Successful Strategy through Artificial Lift Systems to Develop Coalbed Methane Production in Colombia
Authors: Sarmiento Varela D. B. , Monroy Barrios M.. , Gil Chacon A.. , Luna L.. , Buitrago A.. 
Published: May 2013

Abstract
Beam pumping system implementation as alternative of Artificial Lift System to produce the water associated to coalbed methane (CBM), was found for this specific case as the best options in performance and realiability also (production of gas and water, handling of liquid level over the pump and higher run life).
The coal extraction developed in Pribbenow and El Descanso Mines involve degassing of coal stratums and dewatering. An artifitial lift is required to ensure an effective dewatering process and accelerate the gas and water recovery. Since the start of the project of CBM (Coalbed Methane) In Pribbenow and El Descanso Mines has been installed three types of artificial lift systems: Progressive Cavity Pump (PCP), Electrosubmersible Pumping (ESP) and Reciprocating Rod Lift (RRP).
The installation of Reciprocating Rod Lift Systems began with four wells on February 2010 and currently the project has a population of eleven operative wells, and the expansion program includes the completion of eighteen additional wells by 2012 and 2013. Optimum design installed in each well is composed of: – Hydropneumatic Variable Speed pumping units which had proven been the best choice for this application due to versatility in changing production conditions and in order to have a better handle of presented gas bags.– High Stretch sucker rods that has large resistance and also presenting good performance in corrosion environments, these are centralized according to the wear evidence.– Subsurface Tubing Pumps developed for handling high volumes of water and gas and solids production.
The achieved run life with Reciprocating Rod Lift is above seven times the run life obtained with the previous artificial lift systems (PCP and ESP).
This application becomes the first successful CBM project in Colombia and has a high potential for expansion to other areas considering that preliminaries evaluations of the CBM resources of Colombia indicates that there are at least 8 regions with large CBM potential.
Successful PCP Applications in High Deviated Wells: Breaking Away the Paradigm of PCP Only for Vertical or Low Deviated Wells in Colombia
Authors: Correa Sandra , Pertuz Gustavo , Cuellar Hipatia , Moreno Luis Felipe , Salazar Jose I , Romero Jose 
Published: May 2013

Abstract
It highlights the good performance of various Progresive Cavity Pumping (PCP) Systems with pumps landed in ultra high deviated angles, superior than 54°, and critical dog leg severity, 3.4 - 4.5°/100ft in Dina Terciarios field. This performance goes beyond the traditional Colombian oil industry conception about PCP system, it can only be used for vertical or slightly deviated wells and there is a large prevention regarding.
This paper applies for any well with fluid properties and production conditions where PCP technically applies as an artificial lift system, and the critical well geometry rejects the PCP systems due to curvature characteristics, horizontal and highly deviated wells. This specific case is focused to Dina Terciarios as an oil field and two Operator oil companies, Petrominerales and Ecopetrol.
Five PCP Systems have successfully been working in this field since March 2010 with pumps landed at deviation angles of up to 80 degrees and 4.5°/100 ft dog leg severity.
The average Run Life for those wells is higher than 652 days, including a maximum performance in the DT-137 well of 1041 days and counting.
Technically speaking the key factors of these PCP applications are the use of continuous rod, instead of conventional sucker rods, tubing rotators in surface and an appropiate management of application (lifting and pumping capacities, speed and torque control), all oriented to minimize contact loads and wearing effect associated to the well survey and operational conditions.
For both Operator companies this new PCP scope has shown economic advantages in terms of equipment and maintenance costs, well services and spare parts, changing their technical point of view and being a reference for other areas in Colombia.
Aggressive Applications: Successful Beam Pump Systems under Ultra High GOR and Deviated Conditions in Guaduas Field - Colombia
Authors: Monroy Manuel , Urdaneta Octavio , Finol Edeberto , Estupinan Diego , Chicaiza Dario , Rodriguez Luis Fernando 
Published: May 2013

Abstract
Results of the optimization in Guaduas Field with the implementation of the Beam Pumping as an alternative of Artificial Lift System. Installation of different equipment and pumping units as required by the well, Long Stroke, Variable speed hydra-pneumatic and Conventional units, subsurface pump, gas separator, and sucker rod design to deviated wells, allowed increasing of oil production between 40-60%.
Guaduas is a field with an ultra-high GOR reservoir and wells highly deviated, typically the field has been produced with ESP, but the gas generated low volumetric efficiency in the pump; besides, wells near at 60 grades of inclination and DLS more than 6 grades/100 ft. The beam pumping was the method that allowed production increasing and reduction of energy cost per barrel produced.
The implementation initially was for five wells, ES-1N, ES-2E, TP-1E, ES-2S and ES-1S, during 18 months, achieving important production incremental, e.g., 520 BOPD to 1009 BFPD.
Gas production was reoriented to internal consumption and local sell processes.
Results evaluation from reciprocating rod lift systems installed opened opportunities for more additional wells and initiation of a benchmarking process regarding other lifting applications in Guaduas field.
Petroleum community knows successful applications with less uncertainty to choose the best Artificial Lift Method to produce their wells; this, increasing oil production and exploring new limits for gas production and high GOR issues associated.
Mature Fields, Oil Well Optimization Using Plunger Lift Systems in Tibu Field
Authors: Andrade Julio , Parada S. Milena , Jimenez Jose L. 
Published: May 2013

Abstract
For oil wells with high GLR and low potential in mature fields, the production is not only affected by the declination, but also by well backpressure coming from liquid load. This paper presents the plunger lift project results in the Tibu field, North of Santander, Colombia where it was possible to optimize the wells production, with additional reservers according to the natural well depletion curve.
For the wells that make part of the study, the predominant method production was stop cocking that consists in closing well regularly to reestablish well pressure and once the desired pressure is reached, the well is opened until the pressure and production drop. After Plunger Lift implementation, a production increasment was registered, for about 137% up.
The steady production evidenced technical and economic advantages of engineering and technology in the operation field.
Although the plunger lift system in Colombia is not frequently used, the success of Tibu field results gives another alternative to optimize production in Colombia.
Successful Installation of 7" Bypass System for PLT Test on Highly Deviated Wells in Colombia
Authors: Orozco Diego , Lopez Bladimir , Rodriguez Alfredo , Lozano Ramiro , Rincon German , Duran Jaime Alberto , Pinto F.. 
Published: May 2013

Abstract
Oil and Gas industry use PLT methods to obtain information of the reservoir, dynamic test using ESP artificial lift systems with Bypass to allow have access to the perforations has been commonly used on 9 5/8" Casing on different weights. However not all the time those casing sizes are available raising the requirement of logging on 7" casing configuration which require slim design equipment on both ESP and By pass tools in order to leave enough clearance not only to run and pull the equipment safely but also to make it suitable for PLT logging (using Wireline and Coil tubing) when installed on hi deviated well configurationsi
The purpose of the following paper is to present a real example of a successful installation of 7" Bypass Systems with successful PLT logging experience in Rubiales Field (Pacific Rubiales - Colombia), using tools that has been installed and pulled several times to perform the operation on 25 wells introducing savings for over 1MM$ on completion equipment and providing important reservoir information to help develop the field. Also this documents aims to become a reference for logging process planning having the right considerations when installing this system on Hi deviated zones (over 60 Degrees)
Evidence explained on this paper helps to conclude that 7" Bypass System installed prove to comply with industry requirements on Hi deviation Wells (over 60 Degrees) and that not only can be run but also by Introducing right redress and inspection process the system can be re used several times (Over 12 times) saving money on completions equipment. Logging on Hi deviation Wells with 7" By pass Systems introduce an alternative for reservoir understanding, promising to have huge impact on the way fields can be developed by having PLT test on wells with these characteristics.
Successful Installation of a Dual Concentric Completion System on 9 5/8" Casing ESP-ESP Type in Colombia
Authors: Mata H.. , Aristizabal K.. , Rincon G.. , Duran J. A. , Pinto F.. 
Published: May 2013

Abstract
The Oil and Gas industry is always looking for methods that reduce costs associated with the drilling process and, over the last decade, eliminate the environmental impact of well preparation. One new technology provides an option for oil and gas producers to achieve that goal allowing installation of two sets of electrical submersible pumps (ESP) on the same well bore but producing two sands separated by a packer.
The purpose of the following paper is to to present a real example of the successful installation of a Dual Concentric Completion System in COPA ASUR3, allowing two ESP systems to produce two different sands on the same well bore separated by a packer, and to demonstrate the economic effects of its use, reducing by 38% the costs associated with the drilling process, 14% on the total drill/completion investment and 50% on the environmental impact in COPA field (Colombia). The design and installation of the system were carried out taking into consideration Local Governmental regulations requiring both production zones remain insulated from each other.
Evidence explained on this paper helps to conclude that Dual Concentric Systems are proven to be applicable for specific fields with adequate sand distribution and fluid characteristics, also the use of Dual Concentric Systems complies with Government regulations keeping production from both zones isolated when applying the right integrity test procedure and that the use of Dual Concentric Systems significantly reduces costs and environmental impact associated with the drilling process and surface facilities configuration requirements.
Management and Best Practices of Progressive Cavity Pumps Failures Huyaparí Field, Orinoco Oil Belt
Authors: Yánez Eglier , Arredondo Hecsony , Han Micksu 
Published: May 2013

Abstract
According to the 2010-2011 annual statistical bulletin issued by the OPEC oil reserves in Venezuela reached 296.5 MMMBls, positioning the country with the biggest proven oil reserves worldwide. Most of these reserves are in the FPO (Orinoco Oil Belt) as part of the ambitious project PDVSA Magna Reserve.
The produced oil in the FPO is 8-10° API, high viscosity and located in shallow reservoirs so horizontal type wells are constructed to increase well productivity. The artificial lift system of choice is predominantly progressing cavity pump (PCP).
During the pumping operation conditions are generated that affect the performance and run life of the main elements of the pumps. T o manage and improve the run life a prudent field operator should implement specific methods to trace each pump component from delivery to the field until the final failure report is completed. This abstract describes the recommended steps, including; manufacturer quality assurance, installation documentation and completion diagram, operational data, and workover completion. The failure database should include all details: well information, bench test data, operating parameters such as torque, intake and discharge pressures, production data, operating days and accumulated revolutions, among others. At this point it is important to mention that this work will be specified only regarding the process of handling of pump failures without specifying actual statistical data that belongs to the joint venture Petropiar PDVSA (PDVSA 70% and Chevron 30%).
This methodology allows clearly identifying the weak point in the chain of the process regarding this artificial lift method. The use of it has documented properly the history of pump field failures and also serves as the basis for the completion of a significant destructive and non-destructive analysis of failed pumps with the different suppliers.
For the above and considering that only in the FPO are currently more than 3,000 wells with this system, it is necessary to manage a process to ensure the completion of the failure analysis of this equipment in a safe and technically reliable manner.
Lower Tertiary - A Fully Comprehensive Well Completion Design Methodology to Overcome Reservoir Challenges
Authors: Chavez Marco A , Garcia Gonzalo A , Pogoson Oje , Li Yu Lisa , Cardona Andres H , Nelson Roy N 
Published: May 2013

Abstract
In developing an encompassing well completion design, an integrated, comprehensive solution study was under taken for the Lower Tertiary, mainly Wilcox Formation in the Gulf of Mexico. This included Reservoir Characterization, Optimized Hydraulic 3-D Fracture Design and Modeling, Nodal Analysis and Production Forecasting and Reservoir Simulation to determine the optimum well completion requirements in terms of tubing size internal diameter, completion tools inner string and downhole control valve sizes.
Preliminary studies from the Wilcox Formation were taken into consideration and under the assumption of 3000 ft. MD gross height for the Wilcox formation, a representative LAS file containing the main curves for this formation was stretched out to have representative curves for the Gamma Ray, Resistivity, Neutron Porosity, Density, Sonic Delta Compressional and Values of Core Permeability.
The pore pressure gradient and stress gradient was defined for each of the zones selected for stimulation. The stress profile was calculated considering the Gamma Ray Index and VShale on a per foot basis for the zones selected considering the Gamma Ray Curve and the assumed input values for the Sand and Shale.
The mechanical properties were calculated from correlations for Vp and Vs utilizing the Vsh values as defined above, which in turn provided for determination of dynamic values for Young Modulus and Poisson on the same per foot basis. Additional calculations were performed to determine the static values of these same characteristics for each of the depths considered in the selected zones.
The optimum well completion configuration was determined with the evaluation of: the fracture design (optimum treatment schedule for each zone) and minimizing the pressure losses in the production tubing. Well completion reservoir simulations assisting to estimate the flow velocity during the well life. The production system was designed to do not exceed the critical erosion velocity of the downhole equipment.
This study assists in re-defining the well completion design requirements (maximum ratings) for ultra-deep water, high pressure and temperature applications.