Haider, Bader Y.A. (Kuwait Oil Company) | Rachapudi, Rama Rao Venkata Subba (Kuwait Oil Company) | Al-Yahya, Mohammad (Kuwait Oil Company) | Al-Mutairi, Talal (Kuwait Oil Company) | Al Deyain, Khaled Waleed (Kuwait Oil Company)
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.
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 220ºC (428ºF) and 250ºC (482ºF).
ESPs are presently the most widely used downhole mechanical lift method in SAGD production wells. Due to the added complexity and high cost of SAGD well interventions, the longevity of ESP systems has become a critical consideration when balancing well economics. At the same time, ESP technology has been pushed toward more challenging conditions such as operating with produced fluid temperatures of up to 250ºC (482ºF) and operating at very low intake pressures near the steam saturation curve.
The reliability of submersible systems is strongly dependent upon the internal temperature of the ESP motor, meaning the expected run time of the ESP system can be significantly shorter when operating at higher fluid temperatures where motor insulation capabilities are often reduced. For this reason, the ability to monitor the ESP motor temperature (and make appropriate operational adjustments) has become extremely important when striving to maximize longevity. ESP manufacturers have made some significant progress during the past few years to increase the internal temperature ratings of ESP motors, especially in material temperature ratings. This has included collaborating with operators to test new high-temperature systems and working to optimize performance and reliability throughout a broad range of operating conditions [Noonan 2010] [Waldner 2011] [Medina 2012].
The Ompoyi and Orindi fields are located 5 km offshore Gabon in a water depth of 20 m. The high oil density (23o API) and high produced water salinity (150 kppm) combined with reservoir pressure depletion meant that primary production of the Ozouri reservoir required artificial lift. Initially, progressing cavity pumps (PCPs) were selected, however, following failures of the elastomers, electric submersible pumps (ESPs) were deployed to produce at higher rates with high gas/oil ratios (GORs). The production instability associated with the dual-porosity reservoir behaviour and high free-gas content in both the inflow and outflow of the wells presented the main challenge to ESP design and operation. Additionally, most of the wells were remote from the main production facility and were produced via multiphase subsea flowlines, which made well testing difficult due to the phase segregation in the flowlines.
To achieve economically viable production utilizing ESPs, innovative use was made of a range of existing technology. Operationally, however, real-time monitoring was essential to setting wellhead pressures and pump speed to maximize drawdowns. Key technology elements were monopods to minimize the offshore structure cost, fit-for-purpose subsea power cable and helicoaxial downhole pumps for high gas void fraction operation. Key lessons were learned following the trial of several completion architectures to find the optimal combination of gas venting, reservoir access, and a dual barrier mechanism.
The first well was put on production in 2002. Since then a further 10 wells have been drilled to reach a total liquid production of 8,000 B/D with a 60% water cut. Production has been economical and thus confirmed ESPs as being the right solution for this reservoir. The lessons learned prove that the application of ESPs is not limited to traditional waterfloods and that it is feasible to produce challenging reservoirs with ESPs.
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 ). 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
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 153944, "Pressure Distribution in Progressing-Cavity Pumps: Test Results and Implications for Performance and Run Life," by Evan Noble, SPE and Lonnie Dunn, SPE, Weatherford, prepared for SPE's Progressing Cavity Pumps 2011 Digital Edition.
The ESP system is an important artificial lift method commonly used for medium- to high-flow-rate wells for subsea developments. Multiphase flow and viscous fluids can cause severe problems in pump applications. Free gas inside an ESP causes operational problems and lead to system failures. Under two-phase flow conditions, loss of pump performance or gas lock condition can be observed. Under viscous fluids, the pump performance degrades as well. This paper provides a model 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 theoretical study includes a mechanistic model based on Barrios (2011) for the prediction of the degradation due to bubble accumulation. The model comprises a one-dimensional force balance to predict occurrence of the stagnant bubbles at the channel intake as a main cause of deviation from homogeneus flow model.
The testing at Shell's Gasmer facility revealed that the ESP system performed as theoretical over the range of single flowrates and light viscosity oils up to Gas Volume Fractions (GVF) around 25%. ESP performance observed gas lock condition at gas fraction higher than 45%. Homogeneous Model has a fairly good agreement with pump performance up to 30% GVF. Pump flowrate can be obtained from electrical current and boost for all range of GVF and speed. Correlation depends strongly in fluid viscosity and pump configuration.
The main technical contributions of this study are the determination of flow patterns under two important variables, high viscosity and two-phase flow inside the ESP to predict operational conditions that cause pump head degradation and the beginning of bubble accumulation that lead to surging Barrios (2011). For similar applications, pump performance degradation can be predicted in viscous environment and two-phase flow conditions.
A progressive cavity pump (PCP) characterization model is developed to predict flow characteristics under varying multiphase flowing conditions.
This paper presents a procedure for modeling PCPs and its integration to grid-based network solvers including successively accelerated substitution (SAS) and Newton-based. Our numerical study shows the latter leads to a much lower computing cost than that of its counterparts. This PCP model also provides calibration capacity on the performance curve at in-situ PVT properties.
This modeling work will assist production engineers in PCP related jobs, including: PCP surveillance, well planning, nodal analysis, and network optimization.
Electrical submersible pumping (ESP) system performance is limited by the amount of free gas that could be tolerated before gas-locking would occur. Gas-locking of a pump generally causes a catastrophic failure of the ESP system because the pump no longer is moving fluid, which keeps the ESP from overheating during normal operation. Understanding of the phenomenon of head degradation and gas-locking in a pump is well known and has been documented and presented in numerous SPE papers in the past.
The net result of excessive gas at the pump intake is that the gas can potentially accumulate into a long continuous column in the pump, impeding the pump's ability to generate discharge pressure. Gas-locking occurs when the pump is unable to lift the fluid column in the tubing above. In cases where the pump does not actually gas-lock, at the very least the pump will suffer head degradation and low efficiency when high vapor-to-liquid ratios are being pumped. Due to the impact of free gas by volume on ESP performance, the industry has made extensive efforts to address this problem. Two important approaches have been developing technology that either separates the gas from the fluid prior to entering the pump inlet, or creating gas handling pumps which can pump larger gas by volume percentages of up to 70 percent before pump head degradation and gas-locking occurs.
Within Saudi Aramco, ESP applications have become a major contributor to meet our artificial lift requirements. In these applications, Saudi Aramco has avoided the potential issues that occur when free gas is present at the pump inlet by ensuring the pump intake pressure remains above the bubble point pressure of fluid being produced. Although this mode of operation has prevailed thus far; it is anticipated that an ever increasing number of applications will see the presence of gas at the ESP intake. Additionally, one of the leading causes of ESP failures within Aramco is directly attributable to the electrical system consisting of the packer penetrator, motor lead cable, and motor pothead.
To address these challenges, Saudi Aramco has collaborated with Baker Hughes to develop the integral pod intake (IPI) system. The IPI system is a new patent-pending concept initiated by Saudi Aramco that incorporates the shroud hanger for an encapsulated pod system as part of the intake, constructed as a single assembly including the seal, electrical penetrators, and electrical conduits extending to the seal base. This paper will discuss the background and development of the IPI system in terms of how it addresses the issues that occur when free gas is present at the ESP pump. The system's ability to eliminate the electrical integrity problem between the packer and motor pothead will also be covered. A field trial is planned to begin this year in Saudi Arabia and the results will be made available for the 2013 ESP Workshop or in earlier publications within SPE.
Saudi Aramco approached Baker Hughes with the concept of the integral pod intake system in 2008. A design specification was proposed, and two prototypes were built in 2009, with a third prototype built in 2010 for internal testing at the Baker Hughes ESP factory in Claremore, Oklahoma, USA. The original prototypes were shipped to Saudi Arabia along with all the required tooling, as well as the pump, motor, cable, controller, shroud, and other equipment needed for the field trial. Aramco is currently in the process of locating a suitable well for the field trial, which is likely to occur this year.
Medina, Maximiliano (Statoil Canada Ltd) | Torres, Carlos E. (Statoil Canada) | Sanchez, Julio (Statoil Canada Ltd) | Boida, Lindsey (Statoil Canada Ltd.) | Leon, Alfredo Javier (Baker Hughes) | Jones, Jason Allen (Baker Hughes Inc.) | Yicon, Carlos (Baker Hughes Inc.)
Leismer is the first Statoil operated steam-assisted gravity drainage (SAGD) project in the Athabasca region of Alberta, Canada. Electrical submersible pumping systems (ESPs) are the standard artificial lift method for this project. A field trial was planned for newly developed ESPs rated to 250°C. The increased temperature rating allows operating SAGD chambers at higher pressures, thus providing more operational flexibility for increasing recovery and dealing with common exploitation problems. The field trial required reliable and comprehensive down-hole monitoring, so that thorough ESP performance analysis could be performed under real field conditions.
Given the extreme conditions at which ESP systems operate in SAGD, fiber optic pressure and temperature sensors were selected for real-time down-hole monitoring. These sensors were placed at the pump intake, inside the motor and at the discharge. The fiber optic gauges' performance is comparable to standard SAGD measurement devices, but without some of the disadvantages.
The sensing system configuration, ESP interface and installation will be described. This paper will also present the value of real-time ESP monitoring. The pump operation is controlled by continuously history matching performance with well performance software and adjusting parameters to changing down-hole conditions. This ensures the ESPs are run near the best efficiency point. Pump intake sub-cool is controlled to minimize steam flashing occurrence. ESP motor temperature is monitored to boost reliability and run time. Finally, discharge pressure measurement has been used for history matching multiphase flow correlations. This improves ESP performance calculation accuracy in the field's other wells.
Integrating ESP advances with fiber optic measurement has allowed effective local technology qualification under real operating conditions. This project has provided abundant information and knowledge for field-wide production optimization.