An ESP Production Optimization Algorithm Applied to Unconventional Wells

The objectives and Scope is to evaluate the feasibility of a Production Maximization algorithm for ESPs on unconventional wells using projected operating conditions instead of current ones, which authors expect will be crucial in adjusting the well deliverability to optimum frequencies on the rapidly changing conditions of tight oil wells. Actual production data for an unconventional well was used, covering from the start of Natural Flow production up to 120 days afterwards. Simulating what the production would be if a VFD running on IMP Optimization algorithms had been installed, new values for well flowing pressures were calculated, daily production scenarios were evaluated, and recommended operating frequencies were plotted. Result, observations, and conclusions: A. Using the Intelligent Maximum Production (IMP) algorithm allows maximum production from tight oil wells during the initial high production stage, and the prevention of gas-locking at later stages when gas production increases. B. The adjustment of frequency at later stages for GOR wells is key to maintaining maximum production while controlling free gas at the intake when compared against controlling the surface choke. Novel/additive information: The use of Electrical Submersible Pumps for the production of unconventional wells paired with the use of a VFD and properly designed control algorithms allows faster recovery of investment by pumping maximum allowable daily rates while constraining detrimental conditions such as free gas at the intake.

Unlocking the Potential of Electrical Submersible Pumps: The Successful Testing and Deployment of a Real-Time Artificially Intelligent System, for Failure Prediction, Run Life Extension, and Production Optimization

This paper is a summary of the collaborative work between a Gulf Cooperation Council (GCC) national oil company (NOC) and Nybl, a deep tech development company, and the results of applying Nybl's proprietary science-based AI to the GCC NOC ESP wells in real-time applications. The paper demonstrates the potential benefits of the real-life application of AI / Machine Learning in conjunction with traditional Petroleum Engineering concepts and algorithms to predict imminent and future failures, extend and monitor run life, and maximize the production of Electrical Submersible Pumps (ESP's). This paper will highlight the NOC's innovative approach to pilot new technology through successful deployment on 27 wells, spread onshore and offshore, in real-time, with prescriptive actions.

Unlocking the Potential of Electrical Submersible Pumps: the Successful Testing and Deployment of a Real-Time Artificially Intelligent System, for Failure Prediction, Run Life Extension, and Production Optimization

This paper is a summary of the collaborative work between ADNOC (Abu Dhabi National Oil Company) and nybl, a deep tech development company, and the results of applying nybl's proprietary "Science-Based Artificial Intelligence" to ADNOC Electrical Submersible Pump (ESP) wells in real-time applications. The paper demonstrates the potential benefits of the real-life application of Artificial Intelligence (AI) / Machine Learning (ML) in conjunction with traditional Petroleum Engineering concepts and algorithms to predict imminent and future failures, extend and monitor run life, and maximize the production of ESPs. This paper will highlight ADNOC's innovative approach to pilot new technology through successful deployment on 27 wells, spread onshore and offshore, in real-time, with prescriptive actions.

Troubleshooting Cable Deployed Thru Tubing Electrical Submersible Pumps: A Case Study from South East Asia

PETRONAS had embarked on an ambitious thru tubing ESP journey in 2016 and had installed global first truly rig less offshore Thru Tubing ESP (TTESP) in 2017. To replicate the success of the first installation, TTESP's were installed in Field – T. However, all these three TTESP's failed to produce fluids to surface. This paper provides the complete details of the troubleshooting exercise that was done to find the cause of failure in these wells. The 3 TTESP's in Field – T were installed as per procedure and was ready to be commissioned. However, during the commissioning, it was noticed that the discharge pressure of the ESP did not build-up and the TTESP's tripped due to high temperature after 15 – 30 mins of operation. Hence none of the 3 TTESP's could be successfully commissioned. Considering the strategic importance of TTESP's in PETRONAS's artificial lift plans, detailed troubleshooting exercise was done to find the root cause of failure to produce in these three wells. This troubleshooting exercise included diesel bull heading which gave some key pump performance related data. The three TTESP's installed in Field – T were of size 2.72" and had the potential to produce an average 1500 BLPD at 80% water cut. The TTESP deployment was fully rigless and was installed using 0.8" ESP power cable. The ESP and the cable was hung-off from the surface using a hanger – spool system. The entire system is complex, and the installation procedure needs to be proper to ensure a successful installation. The vast amount of data gathered during the commissioning and troubleshooting exercise was used for determining the failure reason and included preparation of static and dynamic well ESP model. After detailed technical investigative work, the team believes to have found the root cause of the issue which explains the data obtained during commission and troubleshooting phase. The detailed troubleshooting workflow and actual data obtained will be presented in this paper. A comprehensive list of lessons learnt will also be presented which includes very important aspects that needs to be considered during the design and installation of TTESP. The remedial plan is finalized and will be executed during next available weather window. The key benefit of a TTESP installation is its low cost which is 20% – 30% of a rig-based ESP workover in offshore. Hence it is expected that TTESP installations will pick-up globally and it's important for any operator to fully understand the TTESP systems and the potential pain points. PETRONAS has been a pioneer in TTESP field, and this paper will provide details on the learning curve during the TTESP journey.

A Comprehensive ESP Preventive Maintenance Program for Long-Term Reliability, Better Life Cycle and Maximum Availability

The reliability of Electrical Submersible Pumps (ESPs) is a critical target for companies managing artificially lifted fields. While efforts to continuously improve the reliability in the downhole system are crucial, it is necessary to focus on the health and long-term reliability of the ESP surface equipment. One effective approach toward achieving this goal is through conducting a comprehensive Preventive Maintenance Program (PMP) for the different components of the ESP surface system. An ESP PMP should be managed without jeopardizing production strategy. The design of the PMP must meet the production demand while maintaining the best-in-class PMP practices. The well operating condition, frequency, weather, well location, required periodic inspection and preemptive servicing and replacement of surface equipment components must be considered, based on studied criterion. The design of the PMP considers equipment upgrades and thermal imaging surveillance to guarantee healthy electrical systems. The mentioned activities have to be captured in a dedicated checklist to cover all requirements. To ensure adequate PMP planning, a well-structured tracking mechanism must be followed. Implementing the recommended PMP framework contributes to minimizing ESP surface equipment component defects like transformer failures, blown fuses, jammed fans, obsolete drive controllers, etc. The proposed PMP is structured to achieve maximum production availability while maintaining a healthier run-life of surface equipment with minimal outages. To ensure minimal ESP surface equipment malfunctions, a comprehensive periodic checkup and well-designed replacement mechanism of surface equipment components should be implemented. The operator company and the maintenance service provider will be able to easily identify the bad actors without complicating the overall process. Consequently, efforts will be made to assign and implement corrective actions to avoid similar problems. The PMP will significantly enhance the ESP surface equipment reliability and prolong the uptime of the fixed/variable speed drives, associated transformers, and other auxiliary equipment. In addition, it should reduce the ESP trips attributed to the malfunction of any surface equipment component and consequently minimize the operational and financial impact of production disruptions. Ultimately, the operator company will be able to maximize its production availability and comply with its planned strategies to meet its target. As a result, the PMP will significantly improve the ESP Key Performance Indicator(KPI) records. In this paper, an innovative and structured framework for ESP surface equipment PMP will be illustrated in details. Additionally, a prototype that contains the main formulas and tools in the program, which were derived from huge historical records and data analytics, will be shown. The paper will explain why and how the PMP can help any operator company or service provider to excel in maintaining healthy ESP systems while meeting its production commitments.

Completion Study Aims To Extend Life of Electrical Submersible Pumps

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 20130, “Practical Approach for Solid Production Prediction and Completion Strategy Decisions in Horizontal Wells: A Case Study From a Cretaceous Carbonate Reservoir, North Oman,” by Mohammed Al-Aamri, Sandeep Mahajan, SPE, and Nair Sujith, Petroleum Development Oman, et al., prepared for the 2020 International Petroleum Technology Conference, Dhahran, Saudi Arabia, 13–15 January. The paper has not been peer reviewed. Copyright 2020 International Petroleum Technology Conference. Reproduced by permission. The carbonate reservoir fields in Oman discussed in the complete paper are produced by several horizontal wells from long openhole sections. The wells are completed by barefoot (openhole) completion with electrical submersible pumps (ESPs) located in the wells’ buildup section. The field has experienced significant ESP failures, so a study aimed to provide input for well-completion-strategy design and operational parameters, which could minimize solids production and lower intervention/operating expenditure (OPEX). Based on the study results, recommendations were provided for a drawdown-management strategy, which potentially will benefit from increasing ESP run life and reducing field OPEX. Field Background Problem Statement and Motivation Petrophysical rock typing for the studied reservoir is detailed in the complete paper. The primary understanding of the root cause of these ESP failures was argillaceous rock typing along the horizontal section. The decision was made to recomplete the wells by isolating equipment from such rock typing. As a result, ESP run lives improved, but failures continued. Several wells featured an isolation process from the first day, for example, but run life did not improve. The field team subsequently analyzed a sample of fines taken from the ESP, and their mineralogy was examined. The main finding was that almost 50% of the sample included calcite mineral content with some quartz (Fig. 1). However, the question remained as to which part of the reservoir the sample belonged. All rock types potentially consist of such calcite minerals because of the marine-deposition environment. Hence, investigating and characterizing the possible root causes of the ESP failures, as well as providing effective completion mitigations for upcoming wells, was critical. The key objectives of the study were to understand the mechanisms and causes of the observed solids from a geomechanical standpoint and to provide recommendations to minimize the risk of near-wellbore failure.

First Worldwide Slim Coiled-Tubing Logging Tractor Deployment

Summary Successful reservoir surveillance and production monitoring is a key component for effectively managing any field production strategy. For production logging in openhole horizontal extended reach wells (ERWs), the challenges are formidable and extensive; logging these extreme lengths in a cased hole would be difficult enough but is considerably exaggerated in the openhole condition. A coiled-tubing (CT) logging run in open hole must also contend with increased frictional forces, high dogleg severity, a quicker onset of helical buckling, and early lockup. The challenge of effectively logging these ERWs is further complicated by constraints in the completion where electrical submersible pumps (ESPs) are installed, including a 2.4-in. bypass section. Although hydraulically powered CT tractors already existed, a slim CT tractor with real-time logging capabilities was not available in the market. In partnership with a specialist CT tractor manufacturer, a slim logging CT tractor was designed and built to meet the exceptional demands of pulling the CT to target depth (TD). The tractor is 100% hydraulically powered, with no electrical power, allowing for uninterrupted logging during tractoring. The tractor is powered by the differential pressure from the bore of the CT to the wellbore and is operated by a preset pump rate from surface. Developed to improve the low coverage in openhole ERW logging jobs, the tractor underwent extensive factory testing before being deployed to the field. The tractor was rigged up on location with the production logging tool and run in hole (RIH). Once the CT locked up, the tractor was activated and pulled the coil to cover more than 90% of the openhole section, delivering a pulling force of up to 3,200 lbf. Real-time production logging was conducted simultaneously with the tractor activation; flowing and shut-in passes were completed to successfully capture the zonal inflow profile. Real-time logging with the tractor is logistically efficient and allows instantaneous decision making to repeat passes for improved data quality. The new slim logging tractor (SLT) is the world’s slimmest and most compact and is the first CT tractor of its kind to enable production logging operations in openhole horizontal ERWs. The importance of the ability to successfully log these ERWs cannot be overstated; reservoir simulations and management decisions are only as good as the quality of data available. Some of the advantages of drilling ERWs, such as increased reservoir contact, reduced footprint, and fewer wells drilled, will be lost if sufficient reservoir surveillance cannot be achieved. To maximize the benefits of ERWs, creative solutions and innovative designs must be developed continually to push the boundaries further.

Forty-Seven–Well Case Study: How a Holistic ESP Design for Deep Deviated Wells with Low Flow Rates Achieved Economic Production

The Shaya wells have vertical depths of 11,000 ft and are heavily depleted. They, therefore, require 10,000 ft of lift to achieve the target drawdown. Electrical submersible pumps (ESPs) were deployed, but because of the low flow rates (80 B/D), produced solids, and high free gas content, initial run lives were uneconomical. This 47-well case study demonstrates how a holistic design and operating procedure achieved both the target drawdown and an economical mean time between failure (MTBF). "Learning from history" was the key method as there was sufficient ESP data to determine the root cause of ESP failures based on a combination of dismantle inspection and failure analysis (DIFA) and operating conditions. Moreover, production testing combined with real-time downhole gauge data enabled inflow characterization with both nodal and pressure transient analysis, thereby establishing the well potential and ensuring that the new proposed design was not only reliable but also achieved the targeted drawdown. An additional requirement was to handle both the current low rates and higher rates associated with future waterflooding. A historical review of 9 wells was conducted, followed by a new ESP design that was proposed and installed in 47 wells, which achieved an MTBF of over 940 days, whereas previous designs in the same wells had an MTBF of only 650 days. This substantial improvement was achieved without compromising drawdown as the wells were produced with a flowing intake pressure of approximately 250 psia at setting depths of 9,500 ft. This result is particularly noteworthy when one considers the harshness of the well conditions and, in particular, bottom-hole temperatures of 240°F, fines migration, deviated wells with doglegs above 2.5°/100ft, intake pressures below bubble point and low productivity indices (PIs) of 0.2 B/D/psi. The high depletion combined with low PIs, which resulted in very low flow rates of as low as 50 B/D, was the most challenging factor of this application. Outflow modeling and wellbore hydraulics were also important considerations to limit solid fallback due to insufficient velocity in the production tubing as well minimize heat rise caused by startup transients, which can be long in low-PI wells. ESPs are traditionally best suited to wells with liquid rates providing sufficient cooling for both the motor and the pump as well as short unloading transients during startup. This success story, therefore, provides an important reference for future ESP applications in very low flow rates in deep wells, which are beyond the recommended application envelope of alternative low flow rate artificial lift solutions such as progressive cavity pumps and sucker rod pumps.

Overview of Opportunities and Challenges of Electrical Submersible Pumps ESP in the Geothermal Energy Production Systems

The electrical submersible pump (ESP) is an essential and critical component in most low-enthalpy geothermal wells where high volumes of hot (up to 120°C) and harsh geothermal brine is required to be transported to the surface. Despite a great deal of knowledge and experience in the design and operation of ESP in the petroleum and water sector, reliability of geothermal ESPs requires further improvement. Frequent failures have been observed that resulted from sub-optimum design, installation and operation of these systems which made the lifetime of them shorter than the expected 5-7 years. In this paper we summarize the typical conditions in low-enthalpy geothermal systems (specifically in the Netherlands) and several observed reliability challenges. Lastly, we will discuss the gaps between the petroleum, water and geothermal practices and identify a list of R&D opportunities to better understand the geothermal ESP failures and improve ESP reliability. Testing ESPs in realistic geothermal conditions and a proper monitoring of the well-ESP system is crucial to improve the reliability of existing ESP designs and can enable the development of new geothermal ESP system designs.