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Abstract This paper presents the results of field evaluation by Rosneft of correlations developed by the Tulsa University Artificial Lift Projects (TUALP) to predict the performance of the natural separation process and of Electrical Submersible Pumps (ESP) operating under multiphase flow conditions as well as Russian State University of Oil and Gas (RSUOG) correlations for the performance of rotary gas separators. The first two set of correlations were developed using data acquired with TUALP experimental facilities but have not been tested against field data. The correlations developed by the Russian State University were also accomplished using lab data and a field test validation was required. During the years of 2006 and 2007 Rosneft conduct several field tests with the purpose of evaluating the performance of several gas handling technologies for ESP installations. The valuable data from those tests enabled Rosneft to verify the accuracy and validity of TUALP and RSUOG correlations for natural separation efficiency, rotary gas separator efficiency and for ESP multiphase performance under real field operational conditions with real crude and natural gas. The TUALP-Marquez-Prado correlation was selected for natural separation efficiency, the correlations for rotary gas separators developed by RSUOG were used and the TUALP-Duran correlation was chosen for pump multiphase head degradation. An excellent match was obtained between the field test data and the correlations predictions with exception of the following cases:• Natural separation for installations with a horizontal ESP; • Multiphase flow head degradation in installations using gas handling devices. The paper presents a brief description of field data, a review of correlations for natural separation efficiency and pump head degradation; and a comparison between the predicted and measured performance. Introduction Electrical Submersible Pumping is a very important artificial lift method. The basic principle is the use of a down hole centrifugal pump that pressurizes the production stream reducing bottom hole flowing pressure. When the pressure decreases below the bubble point pressure, gas evolves out of solution from the liquid phase. If the amount of free gas present at the pump intake that is dragged into the pump is too high, significant operational problems can occur. Correct design of pumping system requires:Prediction of how much free gas is dragged by the liquid phase into the pump Prediction of the multiphase performance of the pump Many of Rosneft oilfields have a high bubble point pressure (higher then 1000 psi). It is estimated that up to 15% of oil production in the near future will be produce from those oilfields. ESPs are the most attractive artificial lift method for Rosneft, with more than 8000 wells currently producing by this method. It is very important for Rosneft to be able to predict correctly the performance of wells producing with ESPs under multiphase flow conditions.
- Europe > Russia (1.00)
- Asia > Russia (1.00)
- North America > United States > Oklahoma (0.30)
- North America > United States > Texas (0.28)
- Government > Regional Government > Europe Government > Russia Government (1.00)
- Government > Regional Government > Asia Government > Russia Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design > Separation and treating (1.00)
Abstract One of limitations of achieving full potential in pumped wells is due to the presence of excessive free gas at pump intake. The presence of free gas at pump intake has several effects on the pump performance. A reduction in the pressure drop developed by the pump is usually observed when pumping multiphase flow mixtures. This performance reduction sometimes may be severe, resulting in unstable pump operation, production losses and may lead to premature equipment failure. Electric submersible centrifugal pumps (ESP) are commonly used in Russia and other parts of the world for oil production. Currently operators are being required to produce wells under non conventional and challenging operational conditions. One of such conditions is the use of ESP in wells with a high free gas liquid ratio that requires the use of special technology. Under those circumstances it is very important to understand more profoundly the processes of ESP operation as any mistake in the equipment design may have severe economical consequences. One of the crucial information needed is the technical limiting operational conditions for different ESP technologies when handling high gas liquid ratio mixtures. Determination of the technical operational envelope is itself a challenge. Experimental work conducted in Universities and industry research centers are very important for an understanding of the problem and advance of the technologies. But it is difficult to recreate in the lab the same conditions that exist in a well bore. Working with actual fluids at high temperatures and pressures are still challenging conditions to be reproduced in the lab. Therefore theoretical models, experimental correlations manufactures technical guidelines need to be verified against the conditions existing in a real oil well. This work presents the conclusions of the use of state of the art engineering methods describing the reservoir-pump production system to analyze the performance of gas handling technologies based on real well field test results. The field tests were conducted under the New Technologies System project of Rosneft Oil Company. Field tests estimated technical limits for ESP gas handling technologies for up to 75% of volumetric gas fraction at pump intake conditions, as well as confirmed the possibility of oil production enhancement with the tests (the NPV for 11 ESP tested was more than 40 mln. rubles in 2007). It is estimated that more than a 100 wells would benefit from ESP gas handling technologies in Purneftegas alone, yielding significant economic impact for the company, increasing oil production by more than 700 tons/day. Review of gas handling approaches Typically, wells with high GLR are produced by natural flow until conditions require an artificial lift system. At this point, gas lift is usually chosen as an artificial lift method unless some of the free gas can be separated and vented allowing the use of a conventional pump. The performance of ESPs under two phase flow conditions depends on factors such as liquid flow rate, amount of free gas, fluid properties (surface tension, densities and viscosities), rotational speed and of course pump geometry. The industry has innumerous simple "rules of thumb" (usually only based on the amount of free gas and pump intake pressure) that try to capture this complex behavior. As a consequence, when those "rules of thumb" fail to reproduce the phenomena they either hinder the applicability of ESP in gassy wells or in the worse case permit the installation of equipment under non acceptable pumping conditions. Both cases bring undesirable economic consequences. Therefore application of ESP in high GLR wells has been limited. Recent advances in ESP gas handling technology indicate the possibility of extending ESPs to some of the more gassy applications in the industry.
- Europe > Russia (1.00)
- Asia > Russia (0.90)
- North America > United States > Texas (0.66)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Europe Government > Russia Government (0.60)
- Government > Regional Government > Asia Government > Russia Government (0.60)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Downhole and wellsite flow metering (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (1.00)
The article also features some case studies of applying the proposed integrated dynamic model based on separate transient multiphase models on Rosneft oilfields.
- Europe (0.70)
- Asia > Russia (0.52)
- North America > United States > Texas (0.29)
Analysis of Self Flowing through Annulus of wells operated with Electric Submersible Pumps, Western and Eastern Siberia Fields Cases
Goridko, Kirill Alexandrovich (Gubkin University) | Kobzar, Oleg Sergeevich (Gubkin University) | Khabibullin, Rinat Alfredovich (Gubkin University) | Verbitsky, Vladimir Sergeevich (Gubkin University) | Litvinenko, Konstantin Vladimirovich (LLC RN-BashNIPIneft) | Grishaev, Maksim Stanislavovich (LLC Slavneft-Krasnoyarskneftegaz)
Abstract When operating production oil wells with electric submersible pump units in conditions of high free gas content in the pump, the mode of flowing through the annular (FTA) may occur due to a combination of factors, such as: relatively high pump intake pressure sufficient to maintain self-flowing conditions through annulus, large amount of gas coming to annulus, high degradation of ESP parameters which prevents decreasing BHP and others. The authors of the article have reviewed literary sources, formulated the relevance of the problem of flowing in annular space of artificially lifted wells. The full characteristics of ESP was adapted by the results of flow loop tests with gas-liquid mixture. It made it possible to develop the model of ESP operation under FTA conditions, which was proven on field cases (four examples). Recommendations for FTA mode optimization discussed.
- Europe > Russia (0.28)
- Asia > Russia (0.28)
- North America > United States (0.28)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Fyodorovskoye Field (0.99)
- Asia > China > Sichuan > Sichuan Basin > Chuanzhong Block > Sichuan Field (0.99)
Abstract The paper is devoted to the estimation of energy efficiency of wells equipped with ESP at different operating conditions in Western Siberia. As a measure of energy efficiency, the overall efficiency of the wells equipped with ESPs was used. The ESP efficiency can be defined as the ratio of the useful hydraulic power developed by ESP to electric power consumed by the ESP on the surface. Corporate production monitoring systems have evolved significantly in recent years in Gaspromneft [1]. Large amount of production data has been gathered and processed, including well operation and energy consumption data. It allows to analyze ESP's energy efficiency for each well. This analysis has been focused on comparison of different ESP operating modes – continuously operating mode (COM) – standard ESP working mode and periodic short-term activation (PSA) mode [2]. ESP in PSA mode starts and stops frequently – an average start stop period less that one hour. The analysis showed that at the current time the information gathered during the monitoring of wells is sufficient to conduct energy audit of the equipment at the level of ESP efficiency evaluation. It makes it possible to identify the dependencies between equipment operation parameters and evaluate the operation efficiency under various operating conditions. Energy efficiency estimation can be used to make decisions for the well stock efficiency improvement. For example, in the course of the analysis, a number of results were revealed: the efficiency in the operation of a well in a periodic short-term activation mode (PSA) in comparison with a continuously operating mode (COM) on a low rate wells is higher by an average of 20%; With the increase in water cut, the EPS's energy efficiency is increasing, both in terms of PSA and COM; The average EPS's energy efficiency decreases with increasing rotating frequency; with an increase in run life, the efficiency of the ESP system is smoothly reduced by an average of 5% in three years, after a gain of 1,300 days, the rate of decrease in efficiency is significantly increased; on COM wells with a motor load of less than 40% efficiency is dramatically reduced, so it is recommended to transfer this fund to the PSA; there is a potential for increasing efficiency and oil production at a low rate wells by using ESP with larger nominal rate in PSA mode and reduced the ratio of operation and accumulation periods. Finally, the efficiency analysis can be used to rank ESP manufacturer by energy efficiency in specific conditions.
- Europe > Russia (0.29)
- North America > United States (0.28)