The behavior of electric submersible pumps (ESP) handling two-phase flow is a subject of primary concern, especially in the petroleum industry, where significant amounts of free gas may be found in oil wells production. In the past, several attempts were made to predict the performance of such kind of pumps, nevertheless, limited success has been achieved due to the complex flow dynamics inside the impeller. Geometry, gas void fraction (GVF) and suction pressure seem to be the main parameters affecting ESP performance. Furthermore, the higher the GVF of the mixture is, the higher the degradation of head that is experienced by the pump. So far, this complex phenomenon has not been well understood. In the present work, a two fluid model is used in three-dimensional (3D) CFD simulations to obtain the pressure, liquid and gas velocity fields as well as the GVF distribution inside an ESP impeller of known geometry; using flow rates, bubble diameter and GVF at the suction as independent variables and an incompressible fluid hypothesis. The gas pocket in the impeller blade reported by other researchers is obtained and comparison with experimental results shows good agreement. The obtained variables from the simulations are the cornerstone that allows the prediction of the performance curve of the pump for different GVF and such, lets the head degradation of the pump be estimated.
Throughout the history of turbomachines investigators have tried to develop reliable methods for prediction of centrifugal pump behavior. Among the parameters available to estimate the performance of this kind of machine is the slip factor. In spite of being regarded as a variable of great significance in the analysis of turbomachinery, there seem to be a misconception regarding its concept and application. Indeed, empirical correlations have been widely used to estimate the slip factor, even in the case of two-phase flow applications, where it has not been investigated. Moreover, these correlations provide a constant value of the slip factor for a given impeller only at the best efficiency point, which is an important restriction to the pump performance prediction, considering that slip factor varies with the pump flow rate. In this study, three-dimensional computational fluid dynamics simulations were carried out on an impeller of known geometry (NS=1960) from which values of slip factor were calculated for both single- and two-phase flow (water and water-air). These results include curves of the slip factor as a function of the specific capacity and the gas-void fraction. Additionally, results for the slip factor in the case of single-phase flow (water) are given for various centrifugal impellers (NS=1157, 1447, 1612, and 3513) in order to illustrate the influence of the flow rate on this parameter. Finally, based on the numerical results, a methodology for prediction of the pump head is presented. Excellent agreement with experimental results has been found. This paper attempts to contribute to a better understanding of the fluid dynamics within centrifugal pump impellers and to shed more light on the path that prediction models should follow in the future.
Gas lift (GL) and electrical submersible pump (ESP) are the two main artificial lift (AL) methods in the steam-assisted gravity drainage (SAGD) process. GL has been used for high-pressure SAGD processes effectively while the ESP has been used in low-pressure processes. There is considerable interest to convert SAGD wells directly into ESP lift during the startup or ramp-up phases, eliminating the GL process traditionally used in the high-pressure SAGD period for injection pressure from 3500 to 4500 kPa and bottomhole operating temperature exceeding 220°C, and using one artificial lift method for the entire SAGD production cycle. In 2011, the 250°C rated high-temperature ESP was introduced, and more than 90 SAGD wells from Athabasca formation have been converted directly to ESP since then. In this paper well production and injection data were analyzed in order to evaluate the key performance indicators (KPIs) including well oil and water production, steam-to-oil ratio (SOR), ESP production performance, and ESP reliability between the 250°C ESP in direct-to-ESP (DTE) wells and 250°C ESP in all SAGD wells.
The company Petrogas E&P was established in 1999 by acquiring onshore block 7 in Oman. Over 23 years, Petrogas E&P has continuously grown by acquiring several blocks in Oman, India, Mozambique, Egypt, Netherlands, Germany, Denmark and in the United Kingdom. The main operations are in Oman, Netherlands and in the UK. Since 2007, Petrogas is the operator of Rima Cluster small fields in southern Oman. Artificial lift, mainly rod driven Progressive Cavity Pumps (PCPs) and Beam Pumps (BPs), is required to produce oil with an average specific gravity of 21 °API to surface. Parted rods are the main reasons of well failures and rods present the weakest part of the completion. Some of the wells in Petrogas Rima show high angles of inclination, complex trajectories and certain levels of hydrogen sulfide (H2S) & carbon dioxide (CO2). Completion failures due to parted rods lead to production deferment and workover interventions because of required rod string replacement. In general, sucker rods are made of a certain grade of steel and these steels are prone to corrosion in an aggressive environment due to the presence of carbon dioxide and sulfide in the crude oil. A coating solution for sucker rods and couplings was implemented to reduce the influence of corrosive environment in some wells. The lower coefficient of friction resulting from the coating reduces the abrasion between the coupling and the tubing. In that way, the risk of tubing holes can be reduced. After a coating solution was implemented in selected problematic wells, the rod run life could in average been tripled with no failures observed as of this writing.
Alternative deployed ESP Systems are strings that are deployed in the well on other than conventional tubulars. Coiled Tubing (CT) deployed Electric Submersible Pumps is one of the most common configurations and has been used successfully in Al Karkara field to reduce intervention cost. As part of a closed loop product improvement workflow, utilizing data from dismantle, inspection and failure analysis of equipment, design improvement were suggested and implemented to address root causes and maximize life in Al Karkara. As part of this work, the main challenges of the application as well as weaknesses identified on the different sections of the string are explained in detail. Moreover, the design and specification changes incorporated because of said observations are also covered, including improvements on the power cable, lower connector, multisensor, motor, bottom intake, and base protectors, among others. Through implementation of downhole equipment ESP upgrade and enhancing the operating philosophy, this improved the run life of Al Karkara field by more than 300%. With the industry shifting into a drastic reduction of total cost of ownership (TCO) approach and with the volatility of oil price, the rigless ESP deployment through coil tubing will help to eliminate the cost of a work over rig while reducing the deferred oil production. This paper showcases the ESP capabilities in this corrosive and high temperature environment.
Electric submersible pump (ESP) systems use thrust bearings in the seal section to handle the thrust generated by the pump stages. Thrust bearings are subjected to harsh operating conditions, including high loads, poor oil circulation, and motor oil viscosity degradation. A less-recognized issue is gas becoming centrifugally trapped under the thrust runner. The gas may be present because of incomplete purging of air during filling, permeation of well gas into the motor oil, or gradual gasification of motor oil at high temperatures. Because thrust bearings are such critical components, it is of interest to increase their reliability, which in turn will increase ESP life. A novel gas purging system (GPS) was designed to alleviate stressors on thrust bearings, including gas accumulation, viscosity deterioration and gasification at high temperature, and low working oil volume. GPS circulates oil along with any gas that accumulates under the thrust runner up to a quiet separation chamber. Degassed oil circulates back to the thrust bearing, while accumulated gas eventually purges to the wellbore through relief valves on subsequent on/off cycles. GPS also improves viscosity and reduces gasification by cooling the oil, and it provides a greater working volume of thrust bearing oil to reduce the effects of oil deterioration. This paper details the GPS design principles as well as the optimization of the different design parameters that affect its performance conducted via computational fluid dynamics (CFD). Observations captured on a test fixture built using the final configuration are also presented, validating the intended functionality.
A new high-temperature electric submersible pump (ESP) system was introduced in 2017 that is designed to address documented failure mechanisms and improve system reliability for steam-assisted gravity drainage (SAGD) operations at 250°C. A closed-loop product improvement workflow based on equipment dismantle, inspection and failure analysis (DIFA) has significantly driven high-temperature ESP technology development and reliability. In this paper, the authors discuss the unique closed-loop design workflow, present the new engineering features to address the identified failure modes, review field results and demonstrate the positive effects of the design modifications by comparing reliability trends based on nearly 150 field installations of the new generation equipment.
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