Development of unconventional resources in the primary US basins helped the US increase oil production to where it is now one of the top two worldwide oil producing countries. The unconventional well production cycle is characterized by a comparably short natural flow period, and unconventional wells require artificial lift to continue production. Electric submersible pump (ESP) systems are used as first artificial lift system in the well life cycle in 36% of the US unconventional wells. Such use challenges ESP performance with gas, solids, and abrasives and other issues that negatively affect ESP run life and uptime. A reliable solution to face those challenges is surveillance using real-time technologies with remote control capabilities. Artificial lift surveillance centers (ALSCs) provide 24/7 surveillance of all wells with ESPs as the artificial lift system to prevent or resolve ESP critical events. Reducing critical events in ESP operations helps reduce stress on ESP components and increases ESP reliability, but this requires timely intervention. Real-time interventions via remote control can eliminate the high-temperature, high-vibration, high-pressure, and high-electrical-load events that would otherwise lead to immediate equipment damage or premature failure. This paper summarizes how an ALSC 24/7 service helped to increase uptime for an operator by using workflows for remote ESP analysis and control to spot critical events, which constituted 46% of 1026 events registered in the system for this operator. Remote intervention techniques, including a gas lock recovery feature, combined with global ESP well event classification and reporting workflows helped to identify every event and avoid ESP shutdowns, thus reducing deferred production and improving ESP performance. Active collaboration of 24/7 ALSC personnel with the operator and field personnel reduced trips to the field, which directly reduced driving risk, one of the significant hazards in the oil industry.

Electrical submersible pumps (ESPs), one of the main artificial lift methods employed in the Western Desert of Egypt, can significantly influence the operating costs associated with producing assets. ESP well interventions are typically complex and costlier than other artificial lift-related workovers. Consequently, it is important that operators develop a strategy to closely monitor ESP-lifted producing wells to maximize production potential, ESP efficiency, and run-life. This case study reviews the experience gained from developing a monitoring program and response strategy to optimize ESP well value in Egypt. Qarun Petroleum Company (QPC), one of the main operators in the Western Desert of Egypt, operates more than 340 ESP producing wells. Similar to other ESP operators in the area, QPC deals with a range of challenges that can affect ESP performance, run-life, and ESP uptime. To address these challenges, a number of wells were selected for a monitoring program based on the transmission of downhole sensor and surface data. The program called for dedicated surveillance engineers to analyze and review the data in real time to identify any suspicious events that may pose a risk to the ESP's performance. Furthermore, a robust communication workflow was developed to enable the surveillance engineers, field operators, and production engineers to communicate, identify root causes of the captured events, and take corrective actions in a timely manner. Actions could then be executed remotely, eliminating health, safety, and environment risks and reducing the time required to optimize the performance of the ESP wells. The surveillance system proved to be valuable in several instances. Events that could have drastically affect production, such as motor overheating and gas interference were detected in real time. Flow recirculation was also identified more rapidly than without the system; thus, improving operational responsiveness and reducing deferred production. In addition, an ESP failure was avoided by optimizing the pump speed automatically to avoid gas-locking effects without compromising production. This study showed that production gains up to 9,000 BOPD were possible. Moreover, significant improvements in ESP run-life was observed in the monitored wells when compared with premonitoring performance. Field case studies are used in this study to demonstrate the well production and operating expenditure improvements resulting from real-time surveillance and continuous performance monitoring for ESP wells and fields.

As the oil industry begins to emerge from one of the worst downturns in decades, companies need to operate in a market of unstable oil prices that the upstream oil and gas industry continues to face. New innovative, sustainable, and disruptive artificial lift technologies are the cost-effective way seek by the operators to minimize risks, maximize production, and remain profitable on the market. In wells with sucker rod-lift systems, elastic beam vibrations induced by downhole pump operation are the main source for premature rod string failure and tubing wear. A completely new steady-state vibrations model for rod string assemblies has been implemented to understand and predict the rod/tubing wear damage phenomenon responsible for half of all well failure events in beam pump operation and most expensive routine well servicing cost. This paper introduces the developed model to enhance prediction of mechanical rod string dynamics during pumping operation, and delivers next generation analytics solution to be utilized for artificial intelligence, industrial internet of things, real-time monitoring, and automation of rod pumping systems. The model works on a set of forced Duffing-like differential equations with cubic non-linearity and damping, these generated discretizing beam elastic behavior using vibration mode basis. Model simulation runs in the time domain numerically capture relevant axial-flexural dynamic forces undergone by rod string during up and down stroke phases, as well as downstroke rod string bending-buckling tendency and its interaction with tubing internal wall. Some examples show usefulness of the novel model to predict failures and maximize uptime, reduce costs with predictive analytics, and design the optimal rod lift solution in every stage of well life cycle.

The advent of US unconventional completion presents new challenges for electrical submersible pump (ESP) systems. Rapid production decline from fractured unconventional wells, solid production, and high amount of gas are considered the main challenges for ESP system performance and longevity. In addition to production decline and high free gas, unconventional wells introduce scale, gas slugs, and solids. Consequently, it is important to monitor ESP systems to optimize performance, to detect anomalies, and prevent potential failure. This paper discusses multiple case histories where real-time remote monitoring was deployed to overcome unconventional wells challenges. Real-time ESP monitoring uses downhole and surface data such as pressure, temperature, vibration, production data, motor load, and many other parameters to monitor the system performance. The data are stored in several servers and interfaced in real time with production engineers or production analysts through a web browser for analysis, optimization, and diagnosis of any potential failures. Monitoring helps to identify opportunities for maximizing accumulated oil production and reducing ESP system downtime. Remote monitoring provides analysts with access to the well for remote ESP optimization that significantly reduces the number of ESP shutdowns and decreases HSE incidents related to field trips and interfacing with surface units. This paper presents a comparison between ESP performance before and after remotely adjusting the operation parameters using the monitoring system. The result shows how real-time monitoring system improved ESP system run life and maximized oil production. In addition, we look into details how the monitoring system enhances overall ESP efficiency and reduces the number of trips to the wellsite to adjust the operation parameters. ESP monitoring provides the operator with a good indication of issues related to scale, paraffin, asphaltenes, or system plugging to start chemical treatment promptly. In addition, this paper discuss how remotely modifying the ESP variable-speed drive (VSD) operating mode reduced ESP repeated shutdowns due to possible gas interference.

Objective/Scope Achieve operational excellence in field of Electrical Submersible Pump (ESP) surveillance and optimization by benefitting Petroleum Development Oman (PDO) asset teams in identifying optimization opportunities, use of real time data for well test validation and improving overall asset KPIs (Key Performance Indicator) through a fully automated Well Management System (WMS). Methods, Procedures and Process The ESP well models are built and sustained in WMS by automated processes to update recent well model information from PDO corporate databases. WMS provides real time well and pump information, along with well model based calculated outputs, pump operational status, workbenches to validate well tests, design inputs, modeling sensitivities for users to perform daily tasks using well-defined standard operating procedures. Operating envelopes based Exception Based Surveillance (EBS) were improved by replacing them with pattern recognition based EBS to improve accuracy, avoid wastage of time and resources. Continuous hands on coaching were conducted to users to strengthen their skills. Benefits, Results, Observations, Conclusions Since implementation of WMS, it has maintained more than 1600 ESP well by building well models automatically for new or workover ESP wells successfully saving huge effort and time from engineers in gathering data and building model. Production Engineers have created more than 100 ESP design input datasheet using the WMS resulting in improved ESP design by avoiding human errors. WMS have already supported assets in identifying around 138 ESP wells with optimization opportunity resulting in increasing around 3 % net oil gain only in year 2017. Real time pump operational status calculation from WMS and sensitivity (Tubing Head Pressure and Hz) based operating point analysis reduced upthrust / downthrust ESP wells by ~50% across PDO in few months. Early detection through Pattern Recognition based EBS has resulted in minimizing ESP downtime by around 30% through quick realization of sub-optimum wells. Validating well tests utilizing downhole gauge data has helped in identifying dubious well tests because of faulty well test equipments thus saving time and money for sequencing the well for re-test and improving allocation. A proper tool and SOPs utilization tracking mechanism is already in place highlighting areas for continuous improvement. Novel Ideas The utilization of real time data and well model together has proven to be a unique and novel way in improving ESP surveillance and optimization for managing around 1600 wells. The replication of same methodology is already undertaken for Progressive Cavity Pump (PCP) and Beam Pump (BP) surveillance and optimization utilizing WMS for PDO assets.

Real-time electric submersible pump (ESP) surveillance is becoming a standard in the oil industry, and many successful cases of applying 24/7 monitoring have been recorded around the world. Kuwait has more than 1,300 ESP installations, with the majority containing both downhole and surface sensors along with SCADA connectivity. Real-time surveillance is a relatively new concept in Kuwait because previous attempts were unsuccessful due to complications in the implementation. For the current application, it was necessary to set up the process without incurring additional costs and additional workforce. These challenges limited the process and application of real-time surveillance in Kuwait. Because increasing the workload with the same manpower risks loss in quality of implementation, it was necessary to improve the productivity of surveillance activities to cover more wells with the same workforce. The method of applying alarms was modified to speed up access and updates. Displays were redesigned for uniformity, resulting in an easy-to-navigate and user-friendly tool for monitoring. Decentralizing the surveillance center into smaller field units was also found to improve communications with field engineers. Improving the response time of identifying, diagnosing, and taking preventive actions is crucial in avoiding downtime. Multiple tools were built to identify triggered alarms to notify the surveillance engineers. A live diagnostic tool is built to improve the accuracy of root cause analysis and to recognize threats faster. GPS vehicle trackers are used to identify the closest service provider to take preventive action on every well. Sharing access with other sectors of the company enables interested sectors to be a part of the surveillance process. This paper presents the approach taken in modifying real-time surveillance by using existing company data and software without additional capital costs. The authors discuss applied methods of improving the productivity of the surveillance process and improving the response time to identify threats, diagnose, and take preventive actions.

In today's world of increased automation and large data, Geographical Information Systems ("GIS") technology has been proven to be a useful component in the oil industry. Through the integration of GIS with critical production engineering and oil wells operations, a prime example of such uses have been realised at Tatweer Petroleum ("Tatweer"). Real-time data streaming from the Bahrain Field ("Bahrain Field" or "Field") has been integrated with GIS to deliver an advanced insight into the production environment leading to profound improvements in control and operation. The GIS, Information Technology, and the Production Engineering teams at Tatweer collaborated to develop a unique application to highlight operations awareness of critical operational events using real-time streaming data imposed on a spatial map.Surveillance and Control of Operation Production Environment ("SCOPE") is a pilot application covering specific traits related to Tatweer's producing wells which focuses on seven traits - (alarms for events such as High Flowline Pressure, Dead Wells, Shut-ins, Transmitters Errors, etc.) SCOPE is an application that was developed by using available tools by focusing on integrating and complementing existing applications and data sources. SCOPE is developed using GIS and real-time data management software which replicates the Bahrain field information on SCOPE within one (1) minute, focusing at well level as Iconics stop at facilities (i.e. Tank Battery/ Well Manifold) and obtaining data from different sources to one dashboard screen. Anomalies can be detected as cluster events, analyzing data to indicate post-events and pre-event and provides a decision tool to acknowledge and take action for particular problematic wells, and measures their efficiency (Key Performance Indicators).

Surveillance and deep analysis of the performance of artificial lift systems in a field are fundamental for continuous improvement. A field data analysis was conducted to determine the appropriate configurations of electrical submersible pumps (ESP) for the field and to identify how the implementation of the improvement plans resulted in the increase of mean time between failure (MTBF). The investigation and exhaustive data analysis of the common root causes of failure identified in the failure analysis of the ESPs and analysis of the challenging conditions presented in the field, such as fluid characterization, decline of reservoir pressure, workover intervention procedures, and ESP technology currently applied in the field, enabled determining the specifications required of the ESP equipment to avoid premature failures (run life less than 90 days). The analysis included a specific matrix for root cause identification and several lessons learned over the 32 months of experience in this mature field. The methodology used for this investigation included the recompilation and analysis of data on failed ESPs and knowledge of specific parameters of the field and applications (wells and fluids produced). The methodology enabled the operator and service companies to achieve greater run life and improve valuable indicators such as MTBF and failure index. After the implementation of the improvement plans, the index of premature failures (ESP failures with less than 90 days) was reduced by 86%from the first to the third year. An increase of 66.6% of survival probability compared in a 1-year period (comparing year 1 to year 3) was also achieved for the entire ESP population operating in this field. The thorough knowledge of the well conditions, including production, surface facilities, chemical treatment, and electrical parameters, by the artificial lift engineers and the operator’s engineering department helped in developing appropriate applications for the studied field. With the knowledge of a field, it is possible to determine the appropriate artificial lift ESP configuration and best operational practices for production and technology. This knowledge allows the operator to be aware of changes to the budget in considering equipment fit for the operating environment, which results in improved run life, thus minimizing the deferred production and preserving the reservoirs through the reduction of well interventions.

Objectives/Scope This paper describes one of the first worldwide pilot implementations of a new generation of downhole digital gas lift system. This system brings a step change in the way gas lifted fields are completed and operated. In a joint effort between operator PTTEP and service company Silverwell, this digital intelligent system was successfully installed in one development well which deviated and depth around 7500 ft in the Sirikit onshore oilfield of Thailand. Well completion and commissioning were done in January 2017. Methods, Procedures, Process The digital and intelligent artificial lift technology is an in-well gas lift system that overcomes the well design and operational limitations of existing side-pocket mandrels and valves. This system enables the operator to optimize gas injection rate, and change the depth of injection to satisfy well conditions, and without any intervention required. Each in-well unit features up to six different sized orifice valves to accommodate a wide range of unloading and production conditions, as well as in-built pressure and temperature sensing capability. As reservoir conditions change the injection orifice can be remotely adjusted from surface and confirmed in real-time. Multiple in-well units can be connected by a single ¼" TEC cable. Results, Observations, Conclusions With regards to reservoir properties from logs and performance of near-by wells, PTTEP was expecting a fast decline in reservoir pressure. Therefore, the flexibility and real time optimization of the Silverwell system allowed them to monitor closely the changing reservoir conditions and adapt gas lift accordingly. The benefits observed in terms of reductions of interventions, production optimization and gas savings will be described in this paper. Novel/Additive Information One of the first worldwide pilot implementations of a new generation of downhole digital gas lift system, with results and benefits detailed in this paper.

The objective is to increase production and run life of 1200 Progressive Cavity Pumps (PCP) wells for Petroleum Development Oman (PDO) which contributes 19% of its total production. This project also intends to improve efficiency in the management of continuously growing (100+ annually) PCP population utilizing improved surveillance and optimization techniques through automated physics-based models linked with real time data and advanced data analysis. The primary challenge in accomplishing automated well modeling was data collection from right corporate databases with good quality. Proper workflows were designed for vendors to enter identified 42 critical data from installation/commissioning reports. Catalogs and engineering validations were prepared to ensure data consistency and highlight human errors during data-entry. The Well Management system (WMS) was integrated with corporate databases to read required data and perform additional data quality checks/validation while building the PCP model. Furthermore, WMS was enabled to utilize measured gross, Torque, RPM and Intake pressure or fluid level to tune model automatically in real time to reflect actual well conditions. A pilot was conducted on 14 PCP wells to establish a system that automatically generates and updates well models to provide complete accessibility of available invested resources to production engineers.8% net oil gain was identified from 50% of these wells based on optimization sensitivities. Full Time Engineer's actual work hours reduced from 8 hours to 15 minutes for PCP optimization, hence enabled quick decisions making process. Inferred production calculation enabled engineers to monitor well performance and estimate daily production allocation between distant well tests.Simultaneously, PDO corporate database data quality issues were identified for improvements, with subsequent positive feedbacks from the automated well modeling process. This project achieved complete standardization of PCP activities from design to commission using well-defined standard operating process and provided one version of truth to PDO engineers.Integrating physics based well model, well test information and real time data from sensors into a single platform has been able to identify hidden opportunities for production gain, perform proactive well diagnostics and increase engineers’ productive time. Furthermore, automated well modeling has delivered benefits across multiple streams by building a platform for future data analytics projects with improved overall data quality of PDO corporate databases. Transitioning from need based well modeling using stand-alone applications and utilizing heterogeneous data from different sources to an integrated and automated Well management System has created an environment for the company to achieve their goals of accelerated net oil gain, improved run life and faster decision-making process.

In Ecuador, the fields are getting more challenging in terms of reservoir depletion. Inchi field is an example of such a field in which the production is normally obtained using electric submersible pumps (ESP), with a fast production decline. The wells start with production rates of 1,000 BOPD, and immediately production and pump intake pressure begin to decrease, thus requiring a secondary recovery technique such as water injection. However, the water to inject at required pressure is not always available, andspecial facilities are required to execute this operation, which increasescapital expenditures (CAPEX). Using a new approach that used the advantages of ESP sensors and operational flexibility, a production well was selected and converted to an injection well thus avoiding the high investments in surface facilities and making the secondary recovery a feasible option for low-producing wells. The Inchi A8 well on the Inchi A pad, was converted toa production injection well due to lack of available water in the field and production facilities. The paper includes an analysis of the completion design, ESP design, sensor installation modification for real-time injection pressure monitoring, ESP performance, injection stimulation, and results with the performance analysis for production recovery of nearby wells. The experience shared in this paper will let the reader understand the challenges for installation of a production injection well driven by the specific needs for and the advantages of injection pressure monitoring. After the installation of the production injection completion, the decrease in production and reservoir pressure stopped, the production in the field increased up to 166 BFPD in the Inchi 01 and Inchi A5 wells, the flowing bottomhole pressure has increased inan average of 100 psi in the wells Inchi 01 and Inchi A5, and in the well Inchi B6 the flowing bottomhole pressure is steady now closed to 600 psi (before was constantly decreasing). The injection pressure monitoring has been useful especially during the injection pressure tests performed by a testing unit, which allows to check the actual injection index of the reservoir. The savings associated with the installation of the production injection well include eliminating the need for additional surface facilities, a pipeline to bring water from the main station, and the construction of the water treatment plant in the location. This paper presents a design guideline for future production injection well applications, the benefits to in having a real-time injection pressure monitoring, and the way to usea conventional ESP discharge pressure to monitor the injection pressure and its performance.

This paper presents the first ever successful Sliding Sleeve Door (SSD) Jet Pump application in Ghauri oil field located in Jhelum, Pakistan. Ghauri is a single completed well flowed with 22 API gravity from the Sakessar Formation. Because the well is a solution gas drive reservoir, the initial production rate declined quickly. The use of jet pump was motivated by the need to revive the well without a work-over. Based on initial testing data, jet pump was selected as a preferred artificial lift method. SSD was installed as a part of initial completion. The downhole jet pump was designed per the SSD dimensions. The pump was operated to enhance/ restore the production of well. During operations, real-time monitoring was conducted to optimize the parameters of the pump, such as the nozzle/throat combination or horsepower. In addition, the life of the jet pump was calculated in relation to the economic limits of the production. Based on the results, the jet pump was found to be the most economical and cost-effective artificial-lift method for Ghauri. SSD jet pump deployment achieved the expected performance and reliability. It has allowed the operator to save the cost of a workover. The cumulative production with jet lift is twice the cumulative production using natural energy. When the well production declined, the jet pump was easily re-optimized by using slickline to pull the pump and change the nozzle and/or throat. The rest of the pump was unchanged to keep the CAPEX at low. In addition, further production of 200,000 BBLS is expected through the jet pump.

The main goal of all production operators is maximizing production and net profit out in a very safe and environmentally controlled manner. When producing difficult fluids from marginal, mature and brown onshore oil fields, Sucker rod (Beam and Progressive Cavity) Pumping systems are typically the most common artificial lift methods used. The primary challenge is to extend the lifting equipment run life, especially the downhole components. For years, operators have been looking for a reliable and accurate way to automatically control these types of lifting systems to improve their reservoir recovery factor by maximizing production. The best-proven way for operators to make proactive decisions for well / field optimization, is to have a fully automated closed-loop monitoring and control solution for the entire field of artificially lifted wells. This paper will show how the well automation and real time downhole measurements are used in real time to control and optimize the operation parameters and well production to obtain maximum benefits. Some case histories for Beam and Progressive cavity pumping systems from different oil fields will presented.

In a field offshore Sumatra, several wells were experiencing pump failures because of loss of flow, sand erosion on pump stages, pump shaft rotation, broken shafts, and motor burnout. The remote offshore location of the wells was an additional hindrance, making it difficult to quickly respond to pump performance issues. This paper will show that the combination of abrasion-resistant pumps and accessibility and analysis of electric submersible pump (ESP) data are critical parameters for responsiveness and efficiency in troubleshooting. The ESP reliability initiative began with well candidate selection to identify the most challenging wells with a known history of short run life primarily due to excessive sand and gas production. A new abrasion-resistant pump with enhanced compression design was installed in four wells as a pilot project. This count increased to 11 by Q2 2016. In addition, all these wells were put under 24/7 real-time surveillance to ensure that the pump performance issues were noticed immediately and acted upon much faster than in the manual troubleshooting process, which could take 2 to 3 days, at best. A right combination of technical solution for pumps enabled better run life performance, and remote surveillance enabled faster troubleshooting and optimization of ESP peformance. These improvements are sustained through defined end-to-end workflows for performing root cause analysis of incidents performed jointly by the operators and ESP suppliers.