ESP—1: Run-time analysis assesses pump performance

Oct. 4, 2010
Run-time analysis is one of the ways to determine how various factors affect electrical submersible pump operating life.

Run-time analysis is one of the ways to determine how various factors affect electrical submersible pump operating life. By understanding and addressing these factors, operators and suppliers have improved ESP performance over time.

To qualify this improvement, Part 1 of this two-part series of articles will discuss run-life measurements and also summarize what various producers have reported about ESP run life as published in industry technical papers during the last decade.

The concluding part will discuss the key factors that influence run life.


The petroleum industry extensively uses ESPs as an artificial lift method for producing oil wells. The application of ESPs to oil production began more than 8 decades ago and has grown greatly, judging from the industry's annual ESP expenditures. Fig. 1 shows a typical ESP installation.

In 2009, Spears & Associates estimated that ESP expenditures were 58% of the total artificial lift market of $5.8 billion.1 In other words, the industry spends more money annually on ESPs than for all other forms of artificial lift combined (Fig. 2).

Three factors largely account for the substantial growth in ESP use, estimated at more than 100,000 installations worldwide:

1. ESPs are the most efficient and effective method for pumping large volumes from medium and deep depths.

2. The pumps now have a much broader application range and produce both higher and lower volumes of fluid from deeper depths at higher temperatures while handling high viscosity, high gas-liquid ratios, and high solids production.

3. Equipment technology advancements along with the enhanced application experience of both producers and ESP suppliers have improved ESP operating life.

Over the years, the most often articulated concerns of new ESP users have been that ESP workover costs were high while perceived ESP system run life was inadequately low. While in some cases these perceptions might be true, suppliers have made strides to ensure proper sizing and application of ESPs while introducing new technology and materials to improve system robustness.

In addition, producers are reporting that using ESP monitoring and surveillance systems in conjunction with continuous improvement programs focused on increasing ESP run life are yielding many reliability and run-life gains.

The use of downhole sensors with surface monitoring and surveillance capabilities, as demonstrated and reported by multiple operators, provides many benefits in ensuring a proactive response to dynamic conditions while providing key information to conduct a continuous improvement program for ESP run life. Also ESP suppliers can be critical partners for implementing and operating these programs continuously.

The industry widely recognizes the importance of achieving long run life of ESP systems as a way to maximize the economic value of their use. To ensure long ESP system life, critical beginning points include proper equipment sizing and the provision of acceptable power quality.

Next, an installation design must address dynamic well conditions associated with well inflow performance, operating temperature, solids production, gas production, and the presence of deposition and corrosion.

Run-life measurements

It is important to understand the common methods used for measuring run-life performance. Unfortunately, the industry does not have one standard but uses several approaches because no single approach is perfect. The five primary methods are:

1. Measured mean time before failure (MTBF).

2. Failure index.

3. Failed unit average run life.

4. Running unit average run life.

5. Numerical simulation and survivor analysis.

The industry typically uses the MTBF approach for evaluating components for frequency of failure and also a good number of ESP users and suppliers use it for determining expected system life. The benefit of using MTBF is that it statistically considers both running and failed ESP systems.

Simply stated, the calculation for MTBF involves the summing of the operating time for all ESP installations in a target group of wells and then dividing the total cumulative operating time by the number of failed ESP systems during that same period (Equation 1 in the equation box).

In some instances, instead of a calculation based on equipment failures, the calculation will use ESPs pulled for any reason. In such cases, MTBF becomes mean time before pulling (MTBP) and reflects disruptions in production for any reason, not just equipment failure.

The failure index is the measured failure rate as expressed by the number of failures/well/year and is particularly useful in forecasting the total number of failures across the coming annual period for a designated ESP population. This forecast can help in budgeting expenses and personnel required for the coming year associated with ESP well workovers.

This method first divides the number of ESP failures by the number of operating wells for a periodic time interval and then sums the resultants for each of the interval periods across a 1-year time horizon (Equation 2).

The recommended period is daily but weekly or monthly are options.

A third common measurement method uses the operating run life for each failed ESP and statistically averages the data to determine an average run life of the failed ESP population. Although this method provides important and useful information especially for infant mortality and short runs, it does not accurately reflect the expected run life of the entire ESP population. The method's limitation is that it statistically ignores the effect of currently operating ESPs, many of which may have been operating for long periods.

Another method of monitoring run life involves calculation of the running unit average. This run-life calculation method is also frequently called instantaneous run life. The calculation involves simply totaling the cumulative time of the ESP population currently operating and dividing it by the number of wells considered. The result of this method provides an average run life of the operating ESPs. This method has the benefit of recognizing the effect of equipment running with long lives while statistically reducing the result for units running that were recently replaced due to failure.

It is important, however, to point out that this method is used best as an instantaneous calculation and evaluated over successive time intervals as a directional indicator. The reason for this is that the results are negatively and unfairly biased by wells that are new applications of ESPs and have never failed but have yet had no chance to achieve their true run-life potential.

Although less frequently used, a growing trend is for developing more sophisticated approaches for predicting ESP run life by using historical run-life data for a particular ESP population and then fitting the data to one of several mathematical distributions, the most common being Weibull and Exponential distributions. This method allows for the definition of different classes of failures based on the data and with the help of simulation techniques such as Monte Carlo, it is possible to forecast failure rates.3-6

The main benefit of this approach is the ability both to quantify and forecast future failures based on classes. On the downside, it requires diligence in acquiring and maintaining the data as well as sophistication in developing and using the calculation and simulation program.

Reported run life

Over the years, several technical papers and articles have summarized ESP run life for fields in various locations and operating conditions. In general, these publications center on successful efforts to improve run life where a variety of less-than-ideal producing complications existed.

A search of published technical papers covering the last 10 years (2000-09) provided data to better quantify actual user experience with ESP system performance and subsequent run life. The search yielded 13 published papers by 11 producing companies covering more than 15,000 ESPs in 11 different countries (Table 1).7-19

The ESP operations covered by these papers span ESPs operating in diverse locations and reservoir conditions. As seen from Table 1, the average reported run life of ESP systems ranged from 10 to 66 months with 27 months being the mean value reported.

In addition, six papers reported the longest single unit ESP run life as ranging from 13 to 152 months. It is important to note that all the authors reported their ESP run life continuing to improve while several also reported that they expected run life to average at least 5 years in the future.

In the last 5 years, suppliers have commercialized substantial technical improvements for ESPs including advances in abrasion resistance, gas handling, high temperature, pump-stage thrust tolerance, optimized controls, and ESP monitoring. Given those improvements and the continuing increase in experience with ESPs, in general one would expect the more recent technical papers to report longer run life than the earlier papers, given the population being reported on represents a normal range of ESP installations.

The average typical run life reported 2000-05 (seven papers) was 24 months and after 2005 (six cases) was 31.5 months. Although these results statistically are not rigorous, they do support the conclusions reported in all the technical papers that overall run life continues to increase with time.

The details of ESP run life reported in these papers indicate that producers' experiences had many things in common yet each had a degree of uniqueness due to the range of well conditions, operator experience, and breadth of equipment used.

Of particular interest is that the papers noted 10 key factors that affect run life in various degrees (Table 2). The concluding part of this two-part series will discuss these factors.

The most common deleterious run-life factors reported were high solids production (69%), high gas production (54%), and equipment sizing and operation (46%).

The operating companies generally addressed these factors by modifying equipment configurations, resizing the pump, increasing employee training, and improving operating procedures. In addition, the authors broadly reported the use of monitoring and surveillance (76%) and continuous improvement programs (100%) as beneficial factors for a longer ESP run life. OGJ


1. Spears & Associates, "Oilfield Market Report, 1999-2010," Tulsa, 2009.

2. Upchurch, E.R., "Analyzing Electrical Submersible Failures in the East Wilmingon Field of California," Paper No. 20675, SPE ATCE, New Orleans, Sept. 23-26, 1990.

3. Brookbank, E.B., "How Do You Measure Runlife?" SPE Gulf Coast Section ESP Workshop, Houston, May 1-3, 1996.

4. Brookbank, B., and Bebak, K., "Making Sense of Mean Time Before Failure (MTBF) and Other Run Life Statistics," SPE Gulf Coast Section ESP Workshop, Houston, Apr. 28, 2004.

5. Sawaryn, S.J., Norrel, K.S., and Whelehan, O.P., "The Analysis and Prediction of Electrical Submersible Pump Failures in the Milne Point Field, Alaska," Paper No. SPE 74685, SPE ATCE, Houston, Oct. 2-6, 1999.

6. Bailey, W.J., et al., "Survival Analysis: The Statistical Rigorous Method for Analyzing Electrical Submersible Pump System Performance," Paper No. 96722, SPE ATCE, Dallas, Oct. 9-12, 2005

7. Miwa, M., Yamada, Y., and Kobayashi, O., "ESP Performance in Mubarraz Field," Paper No. SPE 87257, Ninth Abu Dhabi International Petroleum Exhibition, Abu Dhabi, Oct. 15-18, 2000.

8. Ramos, M., and Rojas, C., "Experiences in the Use of ESOP's in Orinoco Belt Cerro Negro Area, Venezuela," Paper No. SPE 69432, SPE Latin American and Caribbean Petroleum Engineering Conference, Buenos Aires, Mar. 25-28, 2001.

9. Mubarak, H., Khan, F., and Oskay, M., "ESP Failures /Analysis/Solutions in Divided Zone—Case Study," Paper No. SPE 81488, SPE 13th Middle East Oil Show & Conference, Bahrain, Apr. 5-8, 2003.

10. Young, J., Kappelhopp, G.H., and Watson, A., "ESP Run Life Improvement in Harsh Elastomer Environments, the Moomba Field," Paper No. SPE 80526, SPE Asia Pacific Oil and Gas Conference, Jakarta, Apr. 15-17, 2003.

11. Lockard, E., and Saleh, I., "Case History, First Field Wide ESP Installations in Saudi Aramco," Saudi Aramco, 2003.

12. Aihevba, L.O., Al-Sharji, H.H., Barwani, B.B., and Amri, T.A., "Management of ESPs in the Yibal Cluster of PDO—North Oman," SPE Gulf Coast Section ESP Workshop, Houston, Apr. 28-30, 2004.

13. Jaramillo, L., "Down-hole Equipment Reliability and Efficiency Improvements in Cravo Norte" SPE Gulf Coast Section ESP Workshop, Houston, Apr. 27-29, 2005.

14. Jiang, Z.H., and Zreik, B., "ESP Operation, Optimization, and Performance Review: ConocoPhillips China Inc. Bohai Bay Project," SPE Gulf Coast Section ESP Workshop, Houston, Apr. 25-27, 2007.

15. Pantoja, L., et al., "ESP Process Optimization Results in Longer Lives—A Case History from Block 1 AB in Northeastern Peru," SPE Gulf Coast Section ESP Workshop, Houston, Apr. 25-27, 2007.

16. Dorrestijn, L.W., "How to Make Your ESPs Last Longer," SPE Gulf Coast Section ESP Workshop, Houston, Apr. 25-27, 2007.

17. Al-Bimani, Atika, et al., "Electrical Submersible Pumping System: Striving for Sustainable Run-Life Improvement in Oman Oil Fields," Paper No. IPTC 12601, International Petroleum Technology Conference, Kuala Lumpur, Dec. 3-5, 2008.

18. Borling, D.C., Sviderskiy, S.V., and Forlanov, S.F., "Pumping Up the Life of Electrical Submersible Pump Systems, Russian Federation," Paper No. SPE 116905, SPE Russian Oil and Gas Technical Conference and Exhibition, Oct. 28-30, 2008.

19. Al-Zahrani, A.R., et al., "Case Study: First Successful Offshore ESP Project in Saudi Arabia," Paper No. SPE 126066, SPE Saudi Arabia Section Technical Symposium and Exhibition, Al Khobar, Saudi Arabia, May 9-11, 2009.

The author

Joe Vandevier ([email protected]) recently retired from Baker Hughes and is now the principal at Downhole Dynamics LLC, a business and technical consulting company. Vandevier joined Baker Hughes Centrilift in 1973 and held numerous positions. In 2004, he became director of technology at Baker Hughes, where he directed the overall corporate focus on technology, and in 2006, he became president of ProductionQuest, a new Baker Hughes business unit. Vandevier holds a BSEE and a masters in engineering management from the University of Tulsa. He is a registered professional engineer in Oklahoma and a member of SPE.

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