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Abstract Real time analysis and visualization of the performance of a rod pumped well are achieved using multiple small and compact wireless sensors that simultaneously transmit acquired data to a digital laptop manager that integrates the measurements, displays performance graphs and provides advanced tools for analysis and troubleshooting of the pumping system. Battery powered wireless sensors for fluid level, pressure and dynamometer data acquisition are easily deployed and quickly installed on the well. The laptop manager automatically recognizes and commissions the sensors. The user sets up and controls the acquisition of data which may include multiple sensors that synchronously monitor variables such as tubing and casing pressures, fluid level and polished rod acceleration/position and load as a function of time. Elimination of cables and connectors improves the reliability of the hardware and data while speeding up the set-up-tear-down process. The user interface presents a smart instrument rather than a complex application. Among the many innovations provided by these well performance analysis tools stand out the real time visualization of the operation and fluid distribution in the down-hole pump, the simultaneous display of quantitative surface and pump dynamometer graphs in conjunction with fluid level and wellbore pressures. Acquired data, wellbore description and pumping system characteristics are saved as a historical data base creating a continuum of the well’s information and performance for direct comparison and detailed analysis. The paper describes the hardware and user interface, the procedures for installation and acquisition and several examples of field data and well performance analyses for a variety of rod pumping installations.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Abstract The main artificial lift method used in the field Corcel, located in the Llanos Basin, since its beginning in 2007, is the electric submersible pump (ESP). Until April 2011, 9 ESP units were running with an average run life of 218 days and, during those four (4) years, a total of 37 installations were performed, of which 21 were associated to ESP failures. As a result of the high number of failures and low run life presented, an interdisciplinary research group was created, including production, completion, reliability, product and applications engineers from Petrominerales and Baker Hughes, with the ultimate goal of increasing the life of the equipment, reducing intervention costs and minimizing deferred production. Failure analysis focused on two main points: identification of the affected components and root cause of the failures. First results evidenced that the seal was the most affected component of the Electric Submersible Pump, and, more specifically, the elastomer bags and mechanical seals. Although the initial root cause of failure was not clear and was associated exclusively to a problem of compatibility between the seal elastomers and the well fluids, a further detailed analysis was performed to determine other possible failure mechanisms of this component. This paper aims to describe and analyze the failure mechanisms, as well as to provide the solutions designed specifically to mitigate them, starting with the development of a new technology such as the SP1 seal to substantially improve the lifetime of the equipment. An illustration of one of the most important applications of fluid characterization for the sizing or selection of an ESP is presented, as well as the results in reduction of deferred production and intervention costs.
- Asia (0.68)
- South America > Colombia (0.49)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.57)
- South America > Colombia > Llanos Basin (0.99)
- Oceania > Australia > South Australia > Cooper Eromanga Basin > Moomba Field > Toolachee Formation (0.99)
- Oceania > Australia > South Australia > Cooper Eromanga Basin > Moomba Field > Daralingie Formation (0.99)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Ghasha Concession > Mubarraz Field > Thamama Group Formation (0.99)
Abstract Hydraulically actuated sucker rod pumps have been around since the 1940’s but have not received a widespread adoption or acceptance on the order of beam pumps, ESP’s or PCP’s. This is in no small part, due to a reputation of high maintenance costs and frequent failures. Innovations in hydraulically actuated sucker rod pumps, with a keen insight for the oilfield environment, have helped improve reliability and reduce maintenance costs. Among these improvements are the elimination of persistent external hydraulic leaks, a long-stroke capability, and a simplified control system. The instrumentation and control of the hydro-mechanical system is accomplished with an innovative method for determining both polished rod position and load based solely on the hydraulic fluid dynamics. This eliminates any sensors, or points of failure, at the wellhead. Vast improvements in control and data acquisition have greatly reduced the failure rates of hydraulic sucker rod pumping systems by automatically responding to adverse conditions. By allowing operators to remotely interact and troubleshoot the system, a finer grained level of optimization can be achieved by closely matching the wells inflow to the production rate. In some down-hole failure cases, such as a stuck pump, a unique advantage of a hydraulic system allows the operator to attempt unsticking the pump by overloading the polished rod. Although this procedure is not always successful, it does provide a last resort that may save the cost of pulling the well. This procedure is unique to a hydraulic system because there are no structural or reducer load limitations beyond that of the rod-string capacity. The long-stroke improves down-hole equipment runtimes by distributing the wear over a larger surface and by reducing the cyclic fatigue on the rod-string. While the hydraulically actuated sucker rod pump is not appropriate for every well, it does offer significant advantages in those wells where it is suitable. These advantages include long-stroke capability, remote optimization, and safe operation in terms of no external moving parts. The complete system is simple, cost effective, and portable, making it ideal for both permanent and trial installations.
- South America (0.67)
- North America > United States > California (0.46)
- North America > United States > Texas (0.28)
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 made Visualize wells test rate differences Analyze the distribution of wells in downtime Look at Production bubble maps Provide 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.
- South America > Argentina (0.70)
- Asia > Middle East > Israel > Mediterranean Sea (0.25)
Abstract Heavy sandy fluids production is one of the biggest challenges for an artificial lift system. Progressing cavity pumping (PCP) has always been the preferred method, but as sand cuts get higher a PCP by itself is not enough: this is when charge pumps come into the picture. This system consists of a main pump, which has high lift and low volumetric capacity; a charge pump which has low lift and three times the capacity of the main pump and a perforated nipple between them. This arrangement provides higher suction velocities reducing the deposition of solids in the rathole and the recirculation between both pumps helps keeping the perforations clean. This study is based on the first experience in Argentina using charge pumps. The field is "Cerro Huanul Sur" and is located in the Neuquen Basin. This system was installed in seven wells and this study covers the benefits and limitations of each case. The design of the bottomhole assembly was tailored to the specific needs of each well. This included the analysis of fluid properties, well configuration and production history. The installations were carefully supervised and the performance tracked using data logging and surveillance. The completion of this type of wells is costly and time consuming since the sand cut has to be reduced to acceptable values. Once in production, the typical problems are blocked suction, formation of sand bridges in the annular space between casing and tubing, bridges in the tubing itself and sanded pump. In the conclusion this study will show how these issues were all overcome; reducing completion time, the interventions of the well with a flush-by unit or a pulling rig and downtime, and increasing pump run life.
- South America > Argentina > Neuquén Province > Neuquén (0.55)
- South America > Argentina > Mendoza Province (0.35)
Abstract As hydrocarbon reservoirs deplete and lose their natural energy to produce fluids to surface, Artificial Lift technologies become essential to maintain hydrocarbon production. Often Electric Submersible Pumps (ESPs) are selected as the optimum Artificial Lift method for a particular field/well but, typically run on jointed tubing, their limited ‘run lives’ require frequent heavy rig/hoist interventions to replace failed systems. This incurs significant production deferment, increased operating cost and unwelcome disruption to operations. Furthermore it often distracts the rigs/hoists from more profitable oil-generating activity. In light of the above, there has been a persistent and continual drive to improve ESP performance and ‘run life’ but, nevertheless, any machine of electro-mechanical complexity will eventually fail, especially in the hostile downhole environment. Attention naturally turned to minimizing the impact of these inevitable ESP failures and focus shifted to ‘alternative deployment methods’ designed to eliminate the ‘turnaround’ time, production deferment and operating costs associated with heavy rig/hoist intervention. Several ‘alternative’ ESP deployment options have been developed over the years but, for various valid reasons, none were readily embraced by the industry. Most recently a downhole electrical wet-connector technology has enabled ESPs to be ‘shuttled’ through tubing on wireline, coiled tubing, slickline or sucker rods and plugged into a downhole ‘docking station’ without the need of a rig or hoist. Although this technology has been successfully installed both onshore and offshore in Africa, Middle East and Far East, this paper reports the first successful installation in Latin America. Moreover, and more pertinently, the paper also reports on the expedient ‘rigless’ retrieval and replacement of the ESP system in response to an unexpected ESP system failure some months after initial installation. The latter substantiates the value proposition of this ‘alternative’ ESP deployment option. These operations took place in the PetroProducción Cuyabeno field, in Ecuador in September and December of 2012.
- South America > Ecuador (0.35)
- North America > United States > Texas > Dawson County (0.25)
- North America > Central America (0.24)
Abstract This paper describes the physical principles behind the backspin generated by stopping progressing cavity pumping systems (PCP). After describing each and every one of them, action items are recommended to help operators to mitigate risks and potential safety hazards, based on the field experience and applying modeling and simulations. The main goal is to create awareness over their characteristics and implicit risks and contribute with operators to manage PCP systems in a reliable and secure manner. There is a wide range of surface equipment with different technologies to control backspin working in a variety of application conditions and this is why it is necessary to identify the criticality of each system and technology in terms of backspin and potential energy which must be released. It is also necessary to understand the right relationship between all variables involved and their hazard potential in case the backspin control system failed during the release of this energy. It is highly recommended to take action and put barriers to minimize risks, such as the ones mentioned below: ■Preparation of hazard maps in terms of velocity of backspin ■Proper backspin control technology selection for each application ■Implementation of preventive maintenance programs ■Non-destructive inspections to critical components. In conclusion, throughout its content this paper expects to contribute to a safer operation, with the objective of protecting the physical integrity of individuals and operational reliability.
Abstract This paper aims at presenting the experimental ESP performance curves (head, brake horsepower and efficiency) when operating with gas-liquid mixtures and viscous fluids. In order to investigate the ESP performance operating with gas-liquid, a three-stage ESP with some modifications in its casing was used so that we could visualize the flow inside the pump. This pump was tested with gas void fraction varying between 0% and 10%, different liquid flow rate and speed. Pump tests operating with viscous fluid were conducted in a radial three-stage ESP with viscosity ranging from 1 to 820 cP and different speeds. Data has shown that it is possible to verify the performance degradation of ESP operating under unfavorable conditions, contributing, therefore, to a better physical understanding of the phenomena involved.
- South America > Brazil (0.94)
- North America > United States (0.68)
Abstract The present work shows the development applied at the site of Cerro Dragon of Pan American Energy (PAE), which implemented a system that collects, integrates and analyzes dynamometer charts and shooting level measurements. PAE Cerro Dragon field is the largest oil field in Argentina, located in the Golfo San Jorge basin (Patagonia), with 2900 production wells (75% RP, 24% ESP) + 533 injection wells. The current production is almost 90,000 bopd + 1,000,000 bwpd This work shows how it was faced with the challenge for data consolidation and validation from different sources. One source is data from suppliers who collect dynamometers/shooting levels. Another information source is the automation system from Rod Pumping Controllers. Finally it also uses information from different maintenance and administrative databases. All information is processed by the software that was developed by the Operator. It is not a standard or commercial product. This tool is a big gateway, database tool, user manager/viewer, and the most remarkable part is the mathematical tools that allow for the processing of all the information, calculating the Downhole analysis and reports. Before having this tool, there was on one hand software for manual physical measurements, and on the other a pump off software; both independent and often outdated in one or other piece of information. This required the production meetings to refer to both systems, and in other cases obtain independent reports which then had to be consolidated. Another problem was that, although it was not necessary from the operational point of view to have manual measurements of a well with a pump off controller, in practice one was made about every 3 or 4 months, and the information was consolidated in one place, which was then linked to other company databases. This new tool has replaced both of the old software systems, since it allows for the generation of downhole reports from remote automation sources in addition to the manual sources, and saves them in a single database consolidated and linked to the rest of the organization. This demanded a complete and responsible reorganization inside the production staff. This paper will present these reorganizational challenges and lessons learned. Approximately 7000 people work in the oilfield (85% contractors).
- South America > Argentina > Patagonia > Golfo San Jorge Basin (0.99)
- South America > Argentina > Chubut > Golfo San Jorge Basin > Cerro Dragon Field (0.99)
- Information Technology > Software (0.68)
- Information Technology > Information Management (0.67)
- Information Technology > Data Science (0.64)
- Information Technology > Artificial Intelligence (0.47)
Abstract A developing technology involving the use of electric submersible pump systems (ESP), tubing conveyed perforating (TCP) and Drill stem testing (DST) tools in an all-in-one string design was implemented for the very first time in Colombia to accurately test the potential of non-naturally flowing wells. With the implementation of this well test procedure, the perforation and production steps can be followed immediately during the same run, helping to decrease the operating time by reducing the running jobs required and, achieving a significant enhancement on the data gathering process by avoiding to kill the well after perforation and breaking the test into separate runs for testing string and the artificial lift method; situation which likely will damage the formation. The use of a pod to fully encapsulate the ESP and hold the DST-TCP equipment is the key element that enabled the integration of the three technologies into a single run, allowing the study of the inflow performance relationship (IPR) by using the pump to create the optimum environment for perforating, increase the energy of the fluids to transfer them to surface and, obtain controllable production rates required when the formation pressure is not capable enough to do so in the typically called non-naturally flowing wells. The successful integrated job performed during the first semester of 2012 has led to a growing interest in this technology and its use is expected to increase in the near future.