Sizing electric submersible pumps (ESPs) for unconventional wells presents new challenges compared to traditional applications, typically conventional, vertical wells. These challenges are due to the highly dynamic, rapidly changing nature of unconventional wells compared to conventional wells. Traditional ESP sizing software is not structured to design for dynamic conditions, but rather a single point in time. The objective is to design an ESP tool fit for unconventional design applications. Because of the rapidly changing conditions of unconventional wells, it is difficult to balance the lifetime sizing needs of the equipment with needs of the equipment during peak demand. Changing flow rates, water cuts, pump intake pressure (PIP), and gas oil ratio (GOR) have a great effect on stage size, total dynamic head (TDH), and motor horsepower (HP) requirements at different points over time. The new design tool will allow the user to upload a well type curve and help chose a pump and motor combination by calculating different TDH and motor horsepower requirements for each day over the life of the well. Optimized ESP sizing will allow oil and gas operators to install one initial ESP at the completion of the well which lasts until production rates have declined to the conversion point of a lower rate form of artificial lift. This has significant cost savings implications both for capital and operational budgets, by avoiding overspending on oversized equipment upon the initial install of the wells, and greatly reduced the work of the operations team by eliminating workovers needed to downsize equipment. The use of this design tool allows much more rigorous reviews of vendor designs, to avoid over sizing equipment while still capturing high initial production rates during the early production life of the well. ESPs designed using the new design tool will be compared to historical ESP designs provided by the vendors on analogous wells. Production numbers, run life, and historical ESP data streams will be compared between wells designed using the old methodology vs the new design tool.

Electricity is the lifeblood of the Electric Submersible Pump (ESP), the Variable Frequency Drive (VFD) is the heart that keeps it going, the power cable is the artery that provides the blood and the motor is the equivalent of the body that moves. As Doctors, if we looked at our system "would we pass our annual physical exam"? Surprisingly, there is no specification in our industry for the ‘blood’ or electricity we provide to our ESPs, a shocking (pun intended) omission when most operators desire increased ESP runlife. This paper will identify the key aspects (what and why) of healthy power going downhole and put forward a proposed specification. In the 2017 ESP Symposium a breakout session was run that looked at downhole power quality (PQ) and posed the question "Is our operating environment worse than other industries and do we apply the best practices from other industries?". The short answer was that our operating environment is extremely challenging and that we have not adopted the learnings that other industries have applied. As part of the breakout, these key learnings were presented. There was overwhelming agreement in the room that a downhole PQ specification is required. Volunteers were solicited to work on a committee to put together such a specification. This paper will illustrate the best practices from other industries and put forward the rationale and a practical methodology for applying PQ best practices to ESPs. The key aspects of PQ will be presented in layman's terms so that this work can be easily understood by petroleum engineers using ESPs. Many of the PQ improvements can be implemented retroactively at surface and can provide benefit to existing ESPs as well as provide a basis for technical requirements as part of the surface and downhole specification for new wells. The consequences of poor power quality are ESP component failures (penetrator, cable, splice, MLE / pothead, motor end turn, motor bearing, sensor, shafts) and short runlives. This paper will put the information and practices in the hands of the operator to act to improve ESP runlife.

The effect of Variable Speed Drive (VSD) waveforms on electrical motors is generally well understood; however, typical industrial solutions fail to adequately protect specialized ESP systems, as ESP motors cannot be drive-duty rated. This paper examines VSD/ESP systems, discusses how switching transients and high frequency content may manifest themselves via the carrier frequency of the VSD, addresses the harm those transients may cause to ESP systems, and provides solutions that can mitigate related ESP failures. Dismantle, inspection, and failure analysis of the VSD-powered ESP equipment indicated that there was an underlying electrical issue with these systems, thus comprehensive power quality studies were conducted. Data was collected on unfiltered VSD outputs, after the installation of Sine Wave (line to line) filters, and after the installation of Common mode (line to ground) filters. Current and voltage data was collected using Fluke 1750 power quality analyzers, as well as Tektronix THS3024 and Yokogawa PX8000 oscilloscopes with appropriate high frequency test probes. Spectral analysis (also known as harmonic analysis, or frequency domain analysis) was then performed on the collected data, from which corrective actions were determined. Spectral analysis indicated that even on sine wave filtered systems, there was always significant common mode current present. While these currents contribute relatively little to Total Harmonic Distortion between 20th and 73 rd harmonic (dependent on carrier frequency), it was found if their individual resultant amperage was greater than only 0.3 amps L-G, ESP failures would occur. Failures were caused by bearing fluting; feedthrough and penetrator arcing; stator end turn failures; skin effect heating of cables; and MLE, pothead, or splice insulation failures. Due to the specialized application of ESP's, motor design changes have not been readily implemented to improve their resistance to high frequency electrical content. Therefore, the only reasonable solution is to improve VSD output power quality to conform to IEEE 519-2014 specifications in the high frequency realm, with special attention paid to reducing harmonic content beyond the 20 th harmonic. The installation of well-designed sine wave and common mode filters provides the most cost effective means to correct poor power quality in ESP systems, thus both types of filters were installed in the case presented. Adding these electrical filters resulted in the ESP mean time between failure to typically double, but most importantly, resulting failure modes were attributed to other non-electrical root causes. During testing, an inspection of ESP wellhead cable utilizing airborne ultrasonic scanning tools was performed. The operator detected the distinct sound of an inverter over 1000' away from the VSD that was powering the ESP. As filters were installed, the sound decreased and was ultimately not detectable. It is believed that with enough research, the use of airborne ultrasound may provide a novel, non-invasive means to detect harmful high frequency electrical signals in ESP systems.

New unconventional wells have been a huge challenge for ESPs in the Permian Basin due to horizontal wells with high-formation GORs or GLRs. The pumped fluid can cause issues such as gas interference, gas locking, short run life, low production, poor energy efficiency, increased failure rates, shutdowns, so forth. A major problem is gas presence around the ESPs, because it causes the motor to rapidly overheat since the gas is incapable of adequately cooling. In short term, the presence of gas in the flow reduces the pump efficiency and in severe conditions leads to gas lock in the impeller which could damage the equipment. In the long term, the motor life is shortened as a function of the temperature increase. In general, for every 18F of operating temperature increase, the life of the insulation material is reduced by 50% and leading the motor material to be severely affected. The gas handling capacity of standard ESPs is very low, and the efficiency of the traditional rotary gas separator might not be as expected that is why a new and innovative downhole gas separator has been introduced in recent applications to combat the gas slug's problems. The new gas mitigation technology consists of a shrouded ESP with a double stage of gas separation connected at the bottom of the shroud that act as intake and was designed to break the gas slugs and avoid gas entrance into ESPs by forcing free gas to go around the shroud and produce through the casing. The fluid is now forced to pass through an additional gas separator (New Gas Mitigation Technology), which helps on gas mitigation as well as lower motor temperature This paper summarizes different case studies in wells located in the Permian Basin that had reported frequent shutdowns due to gas lock and high motor temperature. All the pump parameters are analyzed before and after the installation to conclude on optimization; in these wells, an increase on production was observed, and better performance of the pump. Other results observed were the reduction of the shutdowns and no gas mode with stable condition along with significantly breaking the drawdown barrier of the 700 psi (ESP PIP). This success was noted on most of our wells where the lowest of them operated at 290 psi (ESP PIP). Additionally, some operational and analytics guides are provided to understand how to identify and control the gas problem in ESPs.

This paper presents a case study on how Petroleum Development Oman (PDO) is advancing Electrical Submersible Pump (ESP) operations by using real-time Automated Well Model and delivering tangible values in ESP life cycle from design to surveillance and optimization. The value to be discussed is captured from actual examples found from all ESP wells in operation in PDO. PDO's Well Management System (WMS) contains 2,000 real-time well models sampled at five minute intervals automating ESP well analysis such as ESP design, performance, well test validation and optimization, amongst others. This was achieved by aligning diverse data feeds with relevant business validation rules to auto-generate Online Well Models, once ESP is commissioned. To ensure the end users’ competence and sustainability of WMS usage, Standard Operating Procedures (SOPs) have been established for all activities such as ESP design, monitoring performance, well test validation, and intelligent surveillance by exception (EBS). Furthermore, this WMS is embedded in PDO's in-house ESP training to Production and Operation Engineers, where activity functionalities such as ESP design, performance monitoring, optimization and sureveillance by exceptions are routinely practiced in the class using real-time well data. In the last 3½ years, PDO has successfully utilized WMS with tangible results. This case study details real examples where production and operation engineers have utilized real-time well models on the following functionalities shown in Fig. 1 : ESP Design : 30% of total submitted designs by vendors, which have been technically quality checked, needed to be revised on the area of production, pump setting depth, pump size, motor capacity and applicability of variable speed drive for optimum operation, increased efficiency and cost saving. This exercise is expected to increase ESP run-life thereby reducing the Company's intervention cost while minimizing deferred oil. ESP Performance : All newly commissioned wells are instantly evaluated as per design targets. Since the start of utilization of this customized WMS, 1,500 new well tests have been validated by engineers, which ensured correct oil allocation for around 44% of total ESP wells across PDO. ESP Optimization : Low hanging opportunities, i.e. by simply increasing pump frequency or reducing tubing head pressure (THP), have been capitalized on, which yielded nearly 2% increase of net oil production of ESPs at zero cost. Pattern Recognition Exception Based Surveillance (EBS) : Pattern Recognition EBS enabled timely planning for well intervention and reducing deferment by 30%. Equipment/Pump operational limits : Around 50% of ESP wells operating in upthrust or downthrust were quickly observed and were successfully brought within recommended optimum range, improving ESP run life and reducing power consumption. Additional functionalities and automation : Easily available real-time calculated variables such as pump efficiency, system efficiency, power consumption and inflow rate have eased the asset well review tasks, enhancing decision making and improving the overall ESP key performance indicator to over 85%. The use of automatic well models ensures that at all times, engineering equations are used for decision making throughout the ESP life cycle. In addition, the well model based well test validation process brings the notion of virtual metering which ultimately will reduce the frequency of well test activities and reduce the amount of deferred production. Moreover, well models integrated with control algorithms have a wider scope of application on well on/off, water injection response/efficiency and station capacity optimization decisions

Production fluids with abrasive sand are a continuous challenge for artificial lift equipment (e.g. electric submersible pumps or ESPs) because these fluids generate wear, reduce lifting efficiency and increase the frequency of well interventions due to failures. This study summarizes the first implementation of hardened ESP stages in the Northern Llanos Field. The impellers used in the ESP system are made of a special alloy called Ni-resist Type 4. This alloy improves the resistance to erosion and abrasion over a traditional pump stage made of Ni-resist Type 1. A candidate well with high flow rate 20,000 bbl/d (600 bbl/d of oil) was selected for a field trial with these special pump stages. The prior ESP's failed with an average run life of 72 days even though the flow rate was restricted producing approximately 75% of its real potential due to the high amount of sand produced. This well is completed in a formation that produces high solids between 50 and 1,000 ppm. During the field trial of hardened stages, the candidate well reached a run life of 797 days, equivalent to 11 times the average of its previous ESP's with standard metallurgy. It also produced 20% above its fluid potential estimated by reservoir engineering and surveillance teams, and the frequency of well interventions was reduced. The paper shows a real case study that demonstrates production and run life increases as well as the capability of being replicated in other wells with high sand production.

Electrical submersible pumps (ESPs) are subject to several failure modes that are well documented in the industry. Startup conditions have seen a lot of improvement over the past decade, with new generations of the variable speed drive (VSD) and controllers avoiding harmful frequencies to the system. Subsequently, ramping protocols are important to achieve safe and optimal pump operation. The present paper discusses the requirements to achieve a smooth and reliable startup of ESPs based on dynamical considerations. The analysis evaluates both mechanical and electrical constraints and their implications on a safe ramping procedure. It was found that a combination of different loads on the pump shaft can result in unwanted dynamical loads that could compromise the pump's operational reliability. It is shown that startup protocols close to the natural motor resistance are beneficial for a smooth and reliable rampup without compromising the system's stability.

The following study considers the ESP system implementation experience from the year 2009 to 2016 in the challenging field of Samaria Luna located in the Southern Region of Mexico. During this time frame, many well failures occurred in the different processes of the ESP system. The study will present a comprehensive methodology that provides solutions to ultimately extend the run life of wells with ESP system. It will also discuss the solutions provided to the Samaria Luna project aiming to achieve an acceptable run life (MTBF) and compare it with international well run life indicators operating under similar field conditions of temperature, depth, gas, and other adverse conditions for artificial lift systems. The diagnosis, failure analysis and root cause analysis for the time frame evaluation played an important role in the construction of the methodology. The results of the evaluation oriented to correction making, decision making and appropriate optimization strategies in various technical aspects such as: the different stages of the ESP system, energy quality, equipment maintenance, pump design, pump installation, well operation and well stabilization. Another important element that will be discussed in the methodology is the external close supervision from PEMEX to manufacturers and vendors in the field, the office and software use and application in the different stages of the project. There are currently not many fields in the world with these characteristics. However, over time artificial lift systems such as gas lift become inefficient due to an increase in the water cut parameter. For this reason, in more fields of the world the eventual decision is to transition to ESP as the alternative artificial lift system due to the advantages of operating in greater depth reservoirs and having much higher volumes of production. It is important to share the lessons learnt: optimization strategies, design methodologies, positive and negative operational practices and other technical actions that have been executed in the Samaria Luna project that may assist as reference to other fields in the world under similar operating conditions (high temperature above 280 F, great depths above 12,000 Ft, high GOR above 1500 SCF/STB). The recommendations of this project may be applied in other projects and directly or indirectly help improve the run life of wells with ESP system, increasing the project profitability in any part of the world.

The Electrical Submersible Pump (ESP) technology has dramatically evolved not only to cover wider inflow ranges but also to deal with abrupt gas conditions observed into unconventional applications. Gas production increment through the life of the well can cause multiple intermittent shutdowns which will constrain the overall well's production and eventually shorten the run life of the ESP. Therefore in order to avoid costly interventions and deferred production, it is fundamental to have the proper gas handling system sized since the beginning of the well's life. This material will encompass different cases which occurred in the Permian Basin area; ( 1 ) Tapered system with gas handling stages deployed in new drill wells with gas' increment observed through the life of the well ( 2 ) Tapered system with multi-vane pump installed in existing producing wells with high gas level, low production and low pump intake pressure ( 3 ) Encapsulated system in wells with high and repetitive gas slugs conditions. The present study describes performance of different scenarios in gassy wells and technologies applied to stabilize the challenging conditions; the benefits are demonstrated through those case histories. The primary goals of those applied technologies are to reduce or even avoid gas interference with the pump. As a result of reducing or eliminating cycling conditions due to gas, non-productive time was able to get reduced, production rate maintained and the run life of the wells extended successfully. A daily monitoring system is also a further help to achieve those goals. The use of ESPs have been increasing through the years, especially in the unconventional market. Therefore, it is crucial to provide new technologies as solution to tackle those challenging conditions. Data uncertainty is a well-known and common challenge regarding an ESP systems'design, observed mainly in new wells, but specifically in unconventional reservoirs. Unconventional reservoirs can be defined in many different ways, but in this study we will limit that definition on horizontal wells that have a rapid production declination curve but also tremendous gas increment through the life of the wells. Running a cost-efficient equipment is a must. Most of the new drills' population have been traced in those reservoirs.

Maximizing production in high gas wells produced with Artificial Lift Systems is one of the greatest challenges operators face daily. The accumulation of gas inside an Electrical Submersible Pump (ESP) creates a condition called "Gas Locking" which prevents fluid production and leads to system shutdown. Multiple shutdowns and frequent Gas Locking negatively affect the runlife and profitability of ESP systems. However, the impact of gas accumulation in ESP applications can be mitigated by implementing intelligent frequency control software included in Variable Speed Drives (VSD's) specifically designed to control and protect ESP's. Baker Hughes has designed an intelligent solution to solve the problems caused by gas locking in ESP systems: a variable speed drive with built-in gas control software that can mitigate and clear gas locking, manage draw down to minimize formation face damage, and avoid gas locking during extended gas slugs to improve production. This paper will present the results of the variable speed drive's gas control software implementation in a high gas well in Colombia. The case history presents a mature well with water injection secondary recovery operated by Ecopetrol in partnership with OXY. The ESP system operation was monitored before and after the VSD's gas control software activation. The following significant benefits in ESP reliability and increased production were achieved: 14% daily production increase, stable operation, lower operating downhole temperatures with no high temperature events, lower pump intake pressure (decrease of 170 PSI) and zero system shutdowns due to gas locking.

To arrest production decline without infill drilling, one must maximize production from existing wells, typically by identifying wells with skin and increasing drawdowns on wells with good pressure support or lower water cut. This paper examines how high-frequency, high-resolution flow rate measurements on ESP wells can identify such opportunities without the need for buildups which cause production deferment. The application of this workflow was examined for wells in Egypt. To obtain flow rate measurements at frequencies greater than once an hour, without dedicating a test separator or multiphase flowmeter to each well, the method relied on real-time data to calculate liquid rate and water cut. The liquid flow rate calculation was based on the principle that the power absorbed by the pump is equal to that generated by the motor. Water cut was calculated by modelling the production tubing as a gradiometer. Analytical equations ensured that the physics were respected at all times, which yields greater repeatability and resolution than analogous methods based on correlations and artificial intelligence. The well analysis in Egypt demonstrated that the evolution of depletion and skin could be identified qualitatively using plots of rate-normalized differential pressure. These diagnostic plots are only possible with high-frequency and high-resolution flow rate measurements and could not be generated using traditional monthly production test data. The case studies also illustrated how frequency and resolution enabled real-time measurement of the impact of small changes in pump speed on both the reservoir inflow characteristic as well as production. This qualitative technique makes it possible to fine-tune production iteratively without the need for time-consuming simulation, which was nevertheless also conducted to quantify the changes in reservoir pressure and skin on the wells considered in this case study. Furthermore, with a water cut resolution of less than 1%, potential water coning can be identified rapidly, which allows the production operator to test small drawdown increases. Finally, this method also has the advantage that it can reduce the mobilization of testing equipment to the well site to measure the change in production, thereby minimizing and eliminating health, safety and environment (HSE) risks in remote locations while also optimizing the use of the available test packages. This novel use of real-time gauge data demonstrates how a cost-effective method can improve well testing quality and thereby identify production optimization opportunities, providing the means to arrest decline. This case study provided a proof of concept on specific wells, however fieldwide application is necessary to identify the wells with the highest production optimization potential because, typically, most of the gain is obtained from a minority of the wells in a given field.