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Electric submersible pumps
Abstract Production from Artificially lifted (ESP) well depends on the performance of ESP and reservoir inflow. Realtime monitoring of ESP performance and reservoir productivity is essential for production optimization and this in turn will help in improving the ESP run life. Realtime Workflow was developed to track the ESP performance and well productivity using Realtime ESP sensor data. This workflow was automated by using real time data server and results were made available through Desk top application. Realtime ESP performance information was used in regular well reviews to identify the problems with ESP performance, to investigate the opportunity for increasing the production. Further ESP real time data combined with well model analysis was used in addressing well problems. This paper describes about the workflow design, automation and real field case implementation of optimization decisions. Ultimately, this workflow helped in extending the ESP run life and created a well performance monitoring system that eliminated the manual maintenance of the data. In Future, this workflow will be part of full field Digital oil field implementation.
- 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...)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Abstract At Kuwait Oil Company (KOC) most of the ESP wells are running with downhole sensors to enhance the daily monitoring routine and for having a better knowledge of the pumps performances. However, one of the most important parameter of these ESP Wells is only known after a time period within 3-6 months: The Flow Rate. Production Tests are obtained using Multiphase Flow Testing Units which usually last between 4 and 6 hours that are also utilized to conduct some sensitivities such as choke size and motor speed changes. At Well Surveillance Group, a tailored fit model was developed from which the ESP flow rate can be estimated based on the downhole sensor data and basic fluid properties with an overall deviation below 2% (when they are compared to the results obtained from the Testing Unit). In this sense, flow rate monitoring can be performed at any time and flow testing time and associated cost can be reduced among other benefits. The method requires knowing the ESP model and total number of stages installed in the well, and then using the corresponding performance curve of the ESP model usually provided by the manufacturer, the data is processed and the calculation performed. This work aims to show how this model works, advantages, limitations, implementation status and future improvements.
- North America > United States (1.00)
- Asia > Middle East > Kuwait (0.71)
- Well Completion (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (0.88)
Abstract This paper describes the selection, design, successful application and performance monitoring of Electrical Submersible Pumps (ESP) in the giant Mangala oil field and Thumbli water field situated in the Barmer basin in Rajasthan, India. Mangala oil field contains in excess of 1 billion barrels of STOIIP (Stock Tank Oil Initially in Place) in high-quality fluvial reservoirs. The field was brought on production in August 2009 and is currently producing at the plateau production rate of 150,000 bopd of which approximately more than one- third of the oil production is from the ESP oil wells. To support the water requirement of Mangala and other satellite oil fields, Thumbli source water field was developed with 5 water production wells with up to 4 wells operating at a time. Each of these water wells is installed with 60,000 bwpd capacity pumps and the field is currently producing up to 225,000 bwpd to meet the water requirements of Mangala and other satellite fields. The Mangala oil field is a multilayer, multi-Darcy reservoir, has waxy viscous crude with in-situ oil viscosity up to 22 cp and wax content in the range of 18 to 26%. The field was developed using hot water flood for pressure maintenance. Significant production challenges included unfavorable mobility ratio with early water cut and hence the early requirement of artificial lift to maintain the plateau production rate. The field has 12 horizontal producers and 92 deviated producers. ESP was selected as the artificial lift method for the high rate horizontal producers while hot water jet pumping was selected as the artificial lift method for low rate deviated oil wells. Each horizontal well is capable of producing up to 15,000 blpd and high rate ESPs were designed and installed to deliver the production requirement. Currently 8 of the 12 horizontal producers are on ESP lift and the remaining four wells are planned for ESP installation in the near future. Apart from two early ESP failures during installation, ESPs have had a good run life; the paper also describes lessons learnt from the infant mortalities. The Thumbli water field, located ~20 km southeast of Mangala field has been developed to meet the water requirement of Mangala and other satellite fields. Thumbli water aquifer is a shallow water field which contains water of ~ 5000 ppm salinity with dissolved CO2, oxygen, chlorides and sulphate reducing bacteria (SRB). 5 high capacity water wells were drilled in Thumbli field to meet the huge water demand from Mangala for water injection in Mangala and satellite field injector wells, hot water circulation in oil production wells and associated water requirement for boilers etc. 1000 HP water well ESPs were designed to produce up to 60,000 bwpd from each well with installed water production capacity of up to 300,000 bwpd from Thumbli field. A state of the art ESP control and monitoring architecture including ESP tornado plotting was developed and successfully implemented in the ICSS to remotely operate, monitor and optimize ESP well performance from the central control room within Mangala field and from the company headquarter located in Gurgaon.
- Geology > Sedimentary Geology > Depositional Environment (0.34)
- Geology > Mineral > Sulfate (0.34)
- Oceania > Australia > Western Australia > Indian Ocean > Perth Basin > Abrolhos Basin > Block WA-325-P > Cliff Head Field (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.95)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.95)
- (9 more...)
The oil production wells and a water source well at Situche Central field will require artificial lift as planned with the subsurface basis of design. Artificial lift for the oil producers is required to maximize ultimate recovery and maintain oil production with increasing water cut. The main goal for Situche Artificial Lift is to provide a lift system that is efficient, the least complicated and robust enough to survive Situche downhole conditions for a minimum 2 ½ years. Such a lift system would be safer (less rig time for pump repairs and less equipment handling and transport) and have the least impact on the environment. Situche Central is a seven well development expected to be sanctioned in Q1 2013, with first oil in 2015. The successful development of Situche Central requires the re-completion of the two existing exploration wells and the drilling of two additional oil producers and water handling wells. This is the Phase 1 development.
- South America > Peru (1.00)
- North America > Canada > Alberta (0.28)
- South America > Peru > Marañón Basin > Situche Central Field (0.99)
- South America > Peru > Marañón Basin > Morona Block > Situche Central Field (0.99)
- South America > Peru > Marañón Basin > Block 64 > Situche Field (0.99)
- South America > Peru > Marañón Basin > Vivian Formation (0.98)
- Production and Well Operations > Artificial Lift Systems > Hydraulic and jet pumps (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (1.00)
- Well Completion > Completion Selection and Design > Completion equipment (0.94)
Summary This paper presents electric-submersible-pump (ESP) -stage performance handling air and water in a laboratory setup. Experimental data gathered shows the effect of volumetric gas flow rate and intake-stage pressure for different rotational speeds. The presence of gas mildly deteriorates the stage performance at low volumetric gas flow rates. A sudden reduction in the stage-pressure increment is observed at this operation condition for a certain critical liquid flow rate, which marks the initiation of surging on the stage performance as mentioned by Lea and Bearden (1982). The surging initiates at lower liquid flow rates as the volumetric gas flow rate increases, which demonstrates the relationship between the surging initiation and liquid flow rate. It is also observed that the initiation of the surging moves toward lower liquid flow rates by increasing the rotational speed or the stage intake pressure. A two-phase stage-performance map was recently introduced, defining boundaries for five pump-performance regimes: homogenous, mild-performance deterioration, performance reverse slop, server performance deterioration, and nil performance (Gamboa and Prado 2011b). The current work shows that these performance regime boundaries are affected by rotational speed and intake-stage pressure.
- Europe (0.93)
- North America > United States > Oklahoma (0.29)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.64)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (1.00)
Abstract This paper will outline and discuss the processes involved from planning to conceptual design, detailed design, equipment preparation and onsite execution that has contributed to the successful offshore installation of Malaysia's first dual ESP system. It will also highlight the challenges and issues encountered throughout the project. The well was originally completed in 1989 as a single producer with gas lift. It is closed in 2004 due to high solid production. A workover operation was carried out in end of May 2011 to revive the well. The current producing zone was plugged and abandoned and the shallower producing interval is opened up and completed. Instead of continuing with the status-quo, gas lift strategy the well is completed with a Dual ESP system with bypass tubing, making it the first ever dual ESP installation in Malaysia. Gas lift has been predominantly used as the main artificial lift strategy in the region. It's relatively ‘cheap’ resources and simple application has been the main driver for oil operator to continue using it as their preferred option. However as the water cut increases and lift gas supply become limited there is a need to have a look on the so called ‘commodity’ artificial lift application. ESP has been seen as one of the most attractive alternatives. The field's first conventional ESP installation with a backup gas lift system in 3 wells was installed in late 2008. In 2010 another ESP with pod configuration was installed. Ever since then, Bokor Project Management team has started to explore on the advancement of ESP system in order to find the optimized design for Bokor Field. However there are several challenges to be addressed. Justification to use a dual ESP system rather than a conventional gas lift system or single ESP configurations that has been done previously in 4 other wells, especially in term of initial cost. The complex installation of a dual ESP system complete with bypass tubing and gas lift backup system which is not a common practice in the area Design considerations and challenges for a successful installation. A complete design of a dual ESP for well specific application. Installation challenges of Dual ESP system with bypass tubing and backup gas lift system utilizing a hydraulic workover unit which has limited handling capacity compared to a conventional rig. Surface requirement and limitations of the existing facility for ESP commissioning and startup. Among others, the paper will discuss on the justification and technical solutions that have been proposed for the installation of the dual ESP system in Bokor field. Lesson learned from the project is also compiled in this paper for any future similar installation in the field
- North America > United States > Texas (0.93)
- Asia > Malaysia > Sarawak > South China Sea (0.55)
- Production and Well Operations > Artificial Lift Systems > Gas lift (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (1.00)
Abstract The current problem related to poor-quality control of artificial lift operational parameters can be solved by means of development and application or real-time monitoring, control and analysis systems. As one way to solve this problem, TNK-BP has implemented the real-time SRP monitoring system. The SRP monitoring system is a specialized SCADA and expert system for SRP. The system displays and analyzes the information from the controllers, gives a possibility of remote control by means of controllers on the wells. SRP controllers are installed on the well sites in order to gather and analyze the data received from the transducers for SRP monitoring and operational control. The controller technology is based on processing a dynagraph for each pump jack stroke, which enables to ensure SRP control as per the rated parameters settings, diagnose the SRP condition, change the operational mode depending on the influx from the formation. To date the flow rates are measured periodically (once or twice a day), which is not enough. The monitoring and diagnostics system enables to receive real-time pressure data from the submersible transducer and use this information for automatic calculation of "instantaneous" flow rate. For this purpose the Company carries out pilot projects to try out the submersible telemetry systems (Russian-made) with additional transducers that record pressure and fluid temperature at the submersible pump discharge end and their transmittal to the external devices. Russian manufacturers of submersible telemetry are taking initial steps in producing telemetry systems with additional transducers. Also, in field development the oil companies face the problem of solids flow-back from the wells. The use of ultrasonic transducer to evaluate amounts of solids flown back from the well and their type is the most advanced practice. Ultrasonic transducer for solids detection has the following technological advantage: it enables to ensure optimal rate for the complex wells stock by means of data-based control and prompt real-time response to changes. In this paper the authors described application of such systems.
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.72)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (0.50)
Development and Application of Small Esp'S for Efficient Development of Remaining Reserves in Poorly Drained Parts of Reservoirs of Samotlor Field
Akopyan, B.. (OJSC TNK-BP Management) | Svidersky, S.. (OJSC TNK-BP Management) | Liron, E.. (OJSC TNK-BP Management) | Prudnikov, A.. (OJSC Samotlorneftegaz) | Vetokhin, E.. (OJSC Samotlorneftegaz) | Martyushev, D.. (Novomet Group of Companies) | Khudyakov, D.. (Novomet Group of Companies) | Komarov, O.. (Novomet Group of Companies)
Abstract The article describes issues of achieving optimum underbalances while operating wells with small-diameter sidetracks and discusses approaches to developing small and very small sized electrical submersible pumps (ESP). In the recent years, the sidetracking technology has been actively developed to reactivate flooded and damaged wells and to optimize the development system. It is sometimes difficult to implement the sidetracked well production potential due to small diameters of sidetracks (liners). The ESP running depth in such wells is limited with the production string sidetrack window location depth since standard pumps have bigger sizes than the sidetrack internal diameter, so they cannot be run to the design depth. The article presents technical solutions that helped build unprecedented small-size ESP serviceable under complicated conditions as well as results of their pilot application in the Samotlor field being developed by TNK-BP.
Abstract During 2012, BakerHughes, ConocoPhillips and Nexen Inc. continued their research partnership [Waldner 2011] with a new experimental test program focused on the thermal performance of Electric Submersible Pump (ESP) systems for Steam Assisted Gravity Drainage (SAGD) applications, which was completed in the high-temperature flow loop at C-FER Technologies. Accurately monitoring the internal temperature of the ESP motor is a key consideration when trying to increase the operational longevity of an ESP system for any application; however, as the SAGD process develops, understanding this temperature profile has become more critical. This test program included several tests at various fluid temperatures and ESP operating conditions that helped determine the thermal performance of the ESP motor. Another unique aspect of this test program was the incorporation of two different temperature monitoring methods at approximately the same position on the internal and external base of the ESP motor: one internal probe positioned near the motor windings via a fiber optic sensor and one external skin temperature RTD positioned on the motor surface to monitor this important temperature differential. This paper presents the equipment and instrumentation used, and demonstrates some of the more interesting test results, thus providing further insight into the thermal performance of this ESP motor under representative SAGD conditions between 220°C (428°F) and 250°C (482°F).
- North America > United States > Texas (0.46)
- North America > Canada > Alberta (0.28)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (1.00)
Abstract This paper provides insight into the Caisson ESP Technology Maturation for subsea boosting systems with high GOR and viscous fluids. It will focus on the developmental research on the effects of viscosity and two phase (liquid & gas) fluids on electric submersible pumps (ESPs), which are multistage centrifugal pumps for deep boreholes. The Electrical Submersible Pump (ESP) system is an important artificial lift method commonly used for subsea boosting systems. Multiphase flow and viscous fluids cause problems in pump applications. Free gas inside an ESP causes many operational problems such as loss of pump performance or gas lock conditions (Barrios 2010 [6]). The objective of this study is to predict the operational conditions that cause degradation and gas lock. This paper provides a summary on the Technology maturation for a high scale ESP Multi-Vane Pump (MVP) for high GOR fields to in support of Shell's BC-10 developments. These novel projects continue the long tradition of Shell's leadership in the challenging deepwater environment. This paper will describe the capability and effects of viscosity and two phase (liquid & gas) fluids using a MVP 875 series G470 as a charged pump in a standard ESP system 1025 series tandem WJE 1000 mixed-type pump. Extensive testing and qualification of the subsea boosting system was undertaken prior to field considerations. Testing was conducted at the world's only 1500-hp ESP test facility capable of controlling multi-phase fluid viscosities and temperatures. A comprehensive suite of tests was performed in conjunction with Baker Hughes Centrilift replicating the expected conditions and performance requirements for Shell's deepwater assets. This paper describes the subsea boosting system maturity process, and reports the effects of viscosity and two phase liquid - gas fluids on ESPs. The test facility work was performed using pumps with ten or more stages moving fluids with viscosity from 2 to 400 cP at various speed, intake pressure, and gas void fractions (GVF, aka gas volume fractions). The testing at Shell's Gasmer facility revealed that the MVP-ESP system is robust and performance tracked theoretical predictions over a wide range of two-phase flow rates and light-viscosity oils
- South America > Brazil (0.46)
- North America > United States > Texas (0.28)
- South America > Brazil > Espírito Santo > South Atlantic Ocean > Campos Basin > Block BC-10 > Parque das Conchas Field (0.99)
- North America > United States > Texas > East Texas Salt Basin > Shell Field (0.98)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Ostra Field (0.94)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block BC-10 > Argonauta Field (0.94)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (1.00)